Technical Review of Subpart RR MRV Plan for Camrick Unit December 2022


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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

WASHINGTON, D.C. 20460

OFFICE OF
AIR AND RADIATION

December 14, 2022

Mr. Carl Thunem
Camrick Unit

1101 Central Expressway South
Suite 150

Allen, Texas 75013

Re: Monitoring, Reporting and Verification (MRV) Plan for Camrick Unit

Dear Mr. Thunem:

The United States Environmental Protection Agency (EPA) has reviewed the
Monitoring, Reporting and Verification (MRV) Plan submitted for Camrick Unit, as required by
40 CFR Part 98, Subpart RR of the Greenhouse Gas Reporting Program. The EPA is approving
the MRV Plan submitted by Camrick Unit on October 20, 2022, as the final MRV plan. The
MRV Plan Approval Number is 1009997-1. This decision is effective December 19, 2022 and is
appealable to the EPA's Environmental Appeals Board under 40 CFR Part 78.

If you have any questions regarding this determination, please contact me or Melinda
Miller of the Greenhouse Gas Reporting Branch at miller.melinda@epa.gov.

Sincerely,

Julius Banks, Chief
Greenhouse Gas Reporting Branch

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Technical Review of Subpart RR MRV Plan for
Camrick Unit

December 2022

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Contents

1	Overview of Project	1

2	Evaluation of the Delineation of the Maximum Monitoring Area (MMA) and Active
Monitoring Area (AMA)	3

3	Identification of Potential Surface Leakage Pathways	4

4	Strategy for Detection and Quantifying Surface Leakage of C02 and for Establishing Expected
Baselines for Monitoring	7

5	Considerations Used to Calculate Site-Specific Variables for the Mass Balance Equation	12

6	Summary of Findings	16

Appendices

Appendix A: Final MRV Plan

Appendix B: Submissions and Responses to Requests for Additional Information

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This document summarizes the U.S. Environmental Protection Agency's (EPA's) technical evaluation of
the Greenhouse Gas Reporting Program (GHGRP) Subpart RR Monitoring, Reporting, and Verification
(MRV) plan submitted by CapturePoint, LLC (CapturePoint) for the carbon dioxide (C02) capture and
enhanced oil recovery (EOR) project in the Camrick Field Area (CFA). Note that this evaluation pertains
only to the Subpart RR MRV plan for the Camrick Unit facility, and does not in any way replace, remove,
or affect Underground Injection Control (UIC) permitting obligations.

1 Overview of Project

CapturePoint indicates in the introduction of the MRV plan that it operates the CFA located in Beaver
and Texas Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil
recovery (EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA is composed of three units, the
Camrick Unit (CU), the North Perryton Unit (NPU), and the Northwest Camrick Unit (NWCU). The GHGRP
facility, called Camrick Unit, has been operating the CFA since 2017. Camrick Unit acquired the CFA from
Chaparral Energy LLC, which initiated the C02-E0R project in March 2001 for the CU and January 2007
for the NPU. No C02 has been injected into the NWCU as of the date of the MRV plan submission.
Camrick Unit intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). This MRV plan was developed in accordance with 40 CFR §98.440-449
(Subpart RR) to provide for the monitoring, reporting, and verification of the quantity of C02
sequestered at the Camrick Unit.

The two units with prior operations previously reported to the GHGRP subpart UU under two separate
facility identification numbers. CU C02 Flood reported under GHGRP identification number 544678 and
the NPU C02 Flood reported under GHGRP identification number 544679. As stated in the MRV plan,
Camrick Unit has notified the EPA that the NPU will not be reporting for 2022, and that the facilities will
be merged into the Camrick Unit (544678) for subpart RR reporting.

The States of Texas and Oklahoma have primacy with respect to implementation of UIC Class II injection
well permits. The MRV plan states that the relevant OCC rules are OAC Title 165:10-5-1 through 165:10-
5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules under OAC 165:5-7-29,
and other governing filing forms. The TRRC has issued UIC Class II enhanced recovery permits under its
Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the CFA, including both injection and production wells,
are regulated by the OCC and the TRRC. According to the MRV plan, C02 is injected into the Upper
Morrowan, a lenticular bedded sandstone trending northwest to southeast with the average top of sand
at 7,250 feet, true vertical depth.

Section 2 of the MRV plan provides a description of the CFA project, including detail on estimated C02
volumes to be injected over the life of the project, site geology, injection operations and results of
reservoir modeling.

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Camrick Unit states in the MRV plan that C02-E0R operations have been ongoing within the CFA for over
20 years and Camrick Unit intends to continue injection for another 12 years. The MRV plan forecasts
cumulative C02 injection and storage over the life of the project to be approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from initial injection to end of the
project in October 2034. During the period covered by the MRV plan, September 2022 through October
2034, Camrick Unit expects to store 52.5 Bscf or 2.77 MMMT in the CFA.

The MRV plan bases the site geology on logs from both the CFA and the Farnsworth Unit, which is
located 10 miles South-South-West of the CFA. According to Camrick Unit, both areas have similar pay
thickness, porosity values, permeability measurements, depositional environment, tectonic processes,
and overburden strata layers. The CFA is located on the northwest shelf of the Anadarko basin, see
Figure 2.2-1 of the MRV plan, and is one of many oil fields in the area that produce from a sequence of
alternating sandstones and mudstones deposited during the late Pennsylvanian Morrowan period.
According to the MRV plan, oil production and C02 injection at CFA are restricted to the operationally
named Morrow B sandstone; the uppermost Morrow sandstone encountered below the Atokan
Thirteen Finger limestone. The plan also states that the primary caprock intervals at CFA are comprised
of the upper Morrow shale and the Thirteen Finger limestone. The Morrowan and Atokan intervals were
deposited approximately 315-300 million years ago. Overlying stratigraphy includes late Pennsylvanian
through the middle Permian shales and limestones, with lesser amounts of dolomite, sandstone and
evaporites. The MRV plan notes that the primary seal rocks of the Morrow shale and the Thirteen Finger
Limestone comprise a package of approximately 180-200 feet thick in the field and are overlain by
thousands of feet of Atokan and younger limestones and shales. Figure 2.2-1 in the MRV plan shows a
generalized stratigraphic column of the area underlying the CFA.

The MRV plan states that the Upper Morrowan sandstones in the Anadarko Basin margins have long
been recognized as fluvial deposits. At the Farnsworth Unit, and similarly at the CFA, the Morrow B is
described as a relatively coarse-grained subarkosic sandstone. The upper Morrowan facies, with
sequences of basal conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be
typical of incised valley deposits. The Morrow B sandstones are encased above and below by shales.
Contacts with shale both below and above the sandstone are sharp and irregular. The Morrow shale
generally fines upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds.

As stated in the MRV plan, the Thirteen Finger limestone formation has two different lithofacies:
diagenetic limestone (cementstone) and pyrite and fossil bearing fine to medium mudstone and coal.
The two facies are intercalated with each other but tend to cluster in layers dominated more by one or
the other. The entire Thirteen Finger interval is typically 130 feet (39.6 meters) thick, comprised of
mudstone, coal, and limestone. The mudstone is calcite rich, with some dolomite, and is completely
diagenetic in origin and probably formed relatively soon following deposition.

The description of the project is determined to be acceptable and provides the necessary information
for 40 CFR 98.448(a)(6).

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2 Evaluation of the Delineation of the Maximum Monitoring Area
(MMA) and Active Monitoring Area (AMA)

As part of the MRV plan, the reporter must identify and delineate both the maximum monitoring area
(MMA) and active monitoring area (AMA), pursuant to 40 CFR 98.448(a)(1). Subpart RR defines
maximum monitoring area as "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 C02 plume until the C02 plume has
stabilized plus an all-around buffer zone of at least one-half mile." Subpart RR defines active monitoring
area as "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 C02 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 C02 plume at the end of year t
+ 5." See 40 CFR 98.449.

Camrick Unit has defined the MMA as the boundary of the CFA plus an additional one-half mile buffer
zone. Some wells have C02 retention on the 4,800 acres that have been under EOR injection in the CFA
since project initialization, see Figure 3.1-1 of the MRV plan for a map of these wells. Camrick Unit
reports that oil recovery in the CFA since August 1955 has resulted in a voidage space of 36 million
standard cubic feet (MMscf) of C02 per acre of surface area that was later filled with water during
waterflood operations. According to the MRV plan, the average decimal fraction of C02 injection to
hydrocarbon pore volume left in the ground after accounting for C02 production through 2021 is 0.29.
The lateral extent of C02 in the injection zone or the C02 storage radius for each well was estimated
based on cumulative C02 injected times the decimal fraction of C02 remaining divided by the voidage
space. The MRV plan states that the site characterization and stratigraphic trapping of the Morrow did
not reveal any leakage pathways that would allow free-phase C02 to migrate laterally, thus, a buffer
zone greater than one-half mile, the minimum required, was not necessary.

The MRV plan states that the volumetric storage capacity calculated for the 49 patterns identified for
continued injection indicates an additional 90 Bscf of C02 can be stored. This 90 Bscf would be added to
the 50 Bscf already stored to result in 140 Bscf of total storage. The MRV plan states that with the
anticipated 12 MMCFD rate or purchased C02, this storage volume will only be 60 percent utilized.
Camrick Unit states in their MRV plan that the MMA accounts for an injected volume of up to 140 Bscf
and includes all areas of the CFA that could be utilized in the future for C02 injection.

As described in the introduction and section 2.2.1 of the MRV plan, the AMA is defined by Camrick Unit's
exclusive right to operate the CFA unitized leases. The MRV plan states that Camrick Unit focuses their
current operations on the western portion of the CU and the entire NPU. It is anticipated that as the
project develops, or as additional C02 volumes become available, additional areas within the CFA may
be developed.. However, Camrick Unit indicates in the MRV plan that project development will be
driven by the market price of oil, so Camrick Unit is unable to provide a specific time in the future when
the eastern portion of the CFA will be developed. The MRV plan states that as C02 injection operations

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are expanded beyond the currently active C02-E0R portion of the CFA, all additional C02 injection wells
will be permitted under the UIC program and will be included in the annual submittal per 40 CFR
98.446(f)(13). Camrick Unit states that all future C02 injection wells permitted will be within the AMA.
The MRV plan states that Camrick Unit expects the free phase C02 plume to remain within the CFA for
the entire length of the project and through year [t + 5], Therefore, Camrick Unit is defining the AMA as
the CFA plus an all-around one-half mile buffer, as required by 40 CFR 98.449. Camrick Unit states that a
new MRV plan will be resubmitted if there are any material changes to the monitoring/operational
parameters not outlined in this MRV plan, as directed by 40 CFR 98.448(d)(1).

The delineations of the MMA and AMA were determined to be acceptable per the requirements in 40
CFR 98.448(a)(1). The MMA and AMA described in the MRV plan are clearly and explicitly delineated in
the plan and are consistent with the definitions in 40 CFR 98.449.

3 Identification of Potential Surface Leakage Pathways

As part of the MRV plan, the reporter must identify potential surface leakage pathways for C02 in the
MMA and the likelihood, magnitude, and timing of surface leakage of C02 through these pathways
pursuant to 40 CFR 98.448(a)(2). Camrick Unit identified the following as potential leakage pathways in
their MRV plan that required consideration:

•	Leakage from Surface Equipment

•	Leakage through Wells

o Abandoned Wells
o Injection Wells
o Production Wells
o Inactive Wells
o New Wells

•	Leakage through Faults and Bedding Plane Partings

o Presence of Hydrocarbons
o Fracture Analysis

•	Leakage through Lateral Fluid Movement

•	Leakage through Confining/Seal system

•	Leakage through Natural and Induced Seismic Activity

3.1 Leakage through Surface Equipment

The MRV plan states that the surface equipment and pipelines utilize materials of construction and
control processes that are standard in the oil and gas industry for C02-EOR projects. Ongoing field
surveillance of pipelines, wellheads, and other surface equipment via personnel instructed on how to
detect surface leaks and other equipment failure minimizes releases. In addition, the Oil and Gas
Division requirements of the OAC rules of the OCC and the TAC rules of the TRRC require operators to
report and quantify leaks. Both serve to minimize leakage of GHG from surface equipment. Operating

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and maintenance practices currently follow and will continue to follow demonstrated industry
standards.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected through surface equipment.

3.2 Leakage through Wells

Camrick Unit has identified 68 abandoned wells, 49 injection wells (29 active) and 94 production wells
(59 active) within the MMA and assessed their potential for leakage of C02 to the surface.

Abandoned Wells

Because the CFA was unitized in 1969 to 1972, Camrick Unit asserts that all plugging and abandonment
activities of wells within the CFA have been conducted under the regulations of the OCC and the TRRC
for plugging wells. Camrick Unit further states that the cement used to plug wells when exposed to C02
will form colloidal gels that further reduce any flow. Camrick Unit concludes that leakage of C02 to the
surface through abandoned wells is unlikely.

Injection Wells

The MRV plan states that mechanical integrity testing (MIT) is an essential requirement of the UIC
program in demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule 46
requirements include special equipment requirements (e.g., tubing and packer) and modification;
records maintenance; monitoring and reporting; testing; plugging; and penalties for violations of the
rule. The TRRC and the OCC detail all the requirements for the Class II permits issued to Camrick Unit.
These rules ensure that active injection wells operate to be protective of subsurface and surface
resources and the environment. Thus, Camrick Unit concludes that leakage of C02 to the surface
through active injection wells is unlikely.

Production Wells

The MRV plan states that some of the original field wells drilled as oil wells were reclassified,
administratively, to gas wells per OAC Title 165:10-1-6 paragraph (d), because of the gas-oil ratio growth
due to reservoir depletion. Hence, there is no difference in well construction. As the field is being
further developed for enhanced oil recovery, these gas wells have been reclassified to oil wells per OCC
regulations and will be monitored for leakage. Once EOR operations commence, the energy content of
the produced gas drops and cannot be sold; therefore, Camrick Unit asserts that any inactive gas wells
are reclassified to either oil producer or WAG injector. Presumably, in this case, the wells are merely
reclassified, with no conversion or well workover taking place. Nonetheless, upon reclassification, these
wells will be assumed to have the same potential leakage characteristics as the well category to which
they are reclassified, with the corresponding monitoring activities and quantification of emissions from
such wells used.

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As the project develops in the CFA; additional production wells may be added and will be constructed
according to the relevant rules of the OCC and the TRRC per the MRV plan. Additionally, inactive wells
may become active according to the rules of the OCC and the TRRC.

Inactive Wells

The MRV plan notes that the OCC has regulations for temporally abandoned/not plugged (TA) and
terminated order wells/UIC not plugged (TM) and likewise the TRRC has regulations for inactive wells.
Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then checked per
operation schedule for any change. Camrick Unit concludes that leakage of C02 to the surface through
inactive wells is unlikely.

New Wells

According to Camrick Unit, all new wells will be constructed according to the relevant rules for the OCC
and the TRRC, which ensure protection of subsurface and surface resources, as well as the environment.
All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and production
wells, are regulated by the OCC and the TRRC, respectively, which have primacy to implement the UIC
Class II programs. New well construction is based on existing best practices, established during the
drilling of existing wells in CFA, and follows the OCC and the TRRC rules. The MRV plan states that these
practices significantly limit any potential leakage from well pathways. Additionally, Camrick Unit notes
that the existing wells followed the OCC and the TRRC rules. Therefore, Camrick Unit concludes that
leakage of C02 to the surface through new wells is unlikely.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected through abandoned, injection, production, inactive, and new wells.

3.3 Leakage through Faults and Bedding Plane Partings

According to the MRV plan, primary seals at CFA have been demonstrated to be mechanically very
competent, thus the main concern of C02 migration at CFA is via seal bypass systems along fracture
networks.

Presence of Hydrocarbons

The MRV plan states that the presence of 75 MMB of oil in the reservoir helps show the lack of
significant leakage pathways present, as oil would have drained from the reservoir prior to the current
day should such pathways exist.

Fracture Analysis

The MRV plan asserts that work done at the Farnsworth Unit is analogous to the CFA. Specifically, the
MRV plan acknowledges that small aperture fractures were noted but not common in most of the
reservoir cores examined, but most of these fractures appear to be drilling induced. The MRV plan also

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notes that fractures in the Thirteen Finger limestone caprock were described using an industry-standard
format for fracture class type, orientation, fracture dip, type of mineral fill, fracture porosity, fracture
spacing, and intensity. Natural mineral-filled fractures, which are rare, were formed during diagenesis at
shallow depths, and are of late Carboniferous age. Unless significantly damaged by large changes in
reservoir pressure, the MRV plan claims that they are highly unlikely to provide migration pathways.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected through faults and bedding plane partings.

3.4 Leakage through Lateral Fluid Movement

The MRV plan states that the Morrow strata in the Oklahoma and Texas Panhandle was primarily a
deltaic sequence that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor conglomerates,
and shale. Since C02 is lighter than the water remaining in the reservoir, it should migrate to the top of
each lenticular structure as it is filled according to the MRV plan. The producing wells, which create low
pressure points in the field, will drain the water and keep the C02 within each discontinuous sandstone.
Therefore, Camrick Unit believes the likelihood of any extensive migration of fluid outside of the AMA is
very low.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected through lateral fluid movement.

3.5 Leakage through Confining/Seal System

The MRV plan states that petrophysical analytical methods used at the CFA include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight rocks, and
mercury injection porosimetry, which is also known as mercury injection capillary pressure (MICP).
Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and Thirteen
Finger Limestone can support C02 column heights of approximately 1,000 to 10,000 feet. At an order of
magnitude over the thickness of the Morrow reservoir, according to the MRV plan, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

As stated in the MRV plan, failure analyses show that the Morrow B sands are weaker than overlying
lithologies, so that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones provide an
interesting and effective combination of strength and elasticity. Limestone layers are strong but brittle,
while the shale layers are weaker but sufficiently ductile to prevent extensive fracture propagation.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected from the confining/seal system.

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3.6 Leakage through Natural and Induced Seismic Activity

Figure 4.6-1 of the MRV plans shows the map of earthquakes with magnitudes measured at greater than
2.5 as defined by the United States Geological Survey (USGS). The small number of events near CFA after
the 29 waterflood operations were initiated in 1969 implies the area is not seismically sensitive to
injection. Also, no documentation exists that any of the distant earthquake events caused a disruption in
injectivity or damage to any of the wellbores in CFA. Camrick Unit states that there is also no direct
evidence that natural seismic activity poses a significant risk for loss of C02 to the surface in the CFA.

Thus, the MRV plan provides an acceptable characterization of the likelihood of C02 leakage that could
be expected from natural or induced seismicity.

4 Strategy for Detection and Quantifying Surface Leakage of CO2 and
for Establishing Expected Baselines for Monitoring

40 CFR 98.448(a)(3) requires that an MRV plan contain a strategy for detecting and quantifying any
surface leakage of C02, and 40 CFR 98.448(a)(4) requires that an MRV plan include a strategy for
establishing the expected baselines for monitoring C02 surface leakage. Section 4 of the MRV plan
details Camrick Unit's strategy for monitoring and quantifying C02 leakage, and section 5 of the MRV
plan details strategies for establishing baselines for C02 leakage. Camrick Unit claims the atmospheric
C02 concentrations from the Moody, Texas station can be used for background C02 values for soil
measurement in the CFA area, per the characterization, monitoring and well data collected by the
Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous Farnsworth Unit.
Monitoring will occur during the planned 12-year injection period. Table 1 of the MRV plan, which has
been reproduced below, provides a summary of the potential leakage pathway(s), their respective
monitoring methods, and anticipated responses.

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Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.1	Detection of Leakage through Surface Equipment

The MRV plan states that the combination of regulation from the OCC and the TRRC and following
industry standards minimize leakage from surface equipment in the facility. If leakage should be
detected through periodic inspections or a MIT, it will be quantified according to the procedures in
Subpart W of the GHGRP.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage that could be expected through surface equipment as required by 40
CFR 98.448(a)(3).

4.2	Detection of Leakage through Wells

The MRV plan identifies several abandoned, injection, and production wells in the MMA. These wells all
have different leakage risks associated with them.

Abandoned Wells

Camrick Unit states that C02 leakage is unlikely through abandoned wells thanks to the cement used to
plug abandoned wells. If leakage were to occur though, it would be detected through changes of
pressure in WAG skids and quantified using techniques per Subpart W of the GHGRP.

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Injection Wells

Since injection wells must follow TRRC and OCC requirements to be active, Camrick Unit asserts leakage
is not likely through injection wells. MITs would also be used to detect the potential leakage and the
leak would be quantified according to procedures in Subpart W of the GHGRP.

Inactive Wells

As stated in the MRV plan, inactive wells are not plugged, and so are subject to TRRC regulations that
diminish leakage risk. A leak that occurs would be detected by field inspection and changes in pressure
and quantified according to procedures in Subpart W of the GHGRP.

New Wells

The MRV discusses how new production and injection wells may be added to the CFA in the future. OCC
and TRRC rules reduce the risk of leakage. These wells will be subject to the same C02 leakage detection
and quantification methods as active injection wells.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage through wells within the MMA as required by 40 CFR 98.448(a)(3).

4.3 Detection of Leakage through Faults and Bedding Plane Partings

Since there are no faults or fracture zones cutting across the seal units according to the MRV, the risk of
leakage is very low. Regardless, if a leak were to occur, it would be detected by monitoring changes in
WAG skid pressure, and the volume of leakage will be reported in Subpart RR of the GHGRP.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage through faults and bedding plane partings as required by 40 CFR
98.448(a)(3).

4.4 Detection of Leakage through Lateral Fluid Movement

The likelihood of any extensive migration of fluid outside of the AMA is very low due to the shale and
fine sandstone composition of the Morrow strata per the MRV plan. Leakage laterally would be detected
though continuous pressure monitoring using WAG skids, with the volume of the leakage being reported
in Subpart RR of the GHGRP.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage through lateral fluid movement as required by 40 CFR 98.448(a)(3).

4.5 Detection of Leakage through Confining/Seal System

Petrophysical and caprock analysis was performed at the Farnsworth Unit, which is analogous to the CFA
according to Camrick Unit. Per the analyses, it is unlikely for hydrocarbon migration pathways that

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charged the Morrow reservoir to be potential C02 migration pathways via primary pore networks today.
Camrick Unit states that C02 migration is more likely due to leakage through other pathways. The MRV
plan states that leakage would be detected with WAG skids' pressure measurements, with the volume
of the leakage being reported in Subpart RR of the GHGRP.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage through the confining/seal system as required by 40 CFR 98.448(a)(3).

4.6 Detection of Leakage through Natural and Induced Seismic Activity

A small number of seismic events have occurred near the CFA, which were attributed to waterflood
operations. These events did not disrupt injection or damage any well bores in the CFA. Therefore,
Camrick Unit asserts that seismic activity will likely not contribute to major C02 leakage in the CFA. If
leakage were to occur, constant monitoring of pressure in the WAG skids would detect the leak, and its
volume would be reported in Subpart RR of the GHGRP.

While the risk to leakage is small, the MRV plan discusses how detection of leaks as a result of seismic
activity will occur using soil C02 and groundwater monitoring.

Thus, the MRV plan provides an acceptable characterization of Camrick Unit's approach to detecting and
quantifying potential C02 leakage through the natural and induced seismic activity as required by 40 CFR
98.448(a)(3).

4.7 Strategy for Determining CO2 Baselines for CO2 Monitoring
Site Characterization and Monitoring

According to the MRV plan, the primary seal consists of 180 - 200 ft of Morrow shale and Thirteen
Finger Limestone which in turn is overlain by over a thousand feet of younger shale and limestone.

These units provide a suitable seal to prevent the migration of C02 out of the injection reservoir.
Additionally, the MRV plan states that no significant faults or fracture zones that cut across the seal
units have been identified in the CFA, indicating that the most likely leakage pathway is from legacy
wellbores that have been poorly completed/cemented.

Groundwater Monitoring

While Camrick Unit states that it does not usually pull water samples from the Ogallala water wells,
samples are pulled when OCC injection permits are submitted in Oklahoma and there has been no
indication of fluid leakage from any samples. Camrick Unit is unlikely to continue monitoring USDW
wells for C02 or brine contamination because it contends the Morrow has been characterized as having
a minimal risk of groundwater contamination from C02 leakage.

Soil C02 Monitoring

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Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower installation,
as mentioned in the MRV plan. While the tower malfunctioned and was not repaired in 2019 due to
COVID, the data values from the tower when it worked were quite close to the data gathered from the
NOAA Global Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is near
the Farnsworth Unit, Camrick Unit states that atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

Visual Inspection

Camrick Unit states that operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

Well Surveillance

Camrick Unit says it adheres to the requirements of OAC Title 165:10-5 for the OCC and of TAC Rule 46
for the TRRC governing fluid injection into productive reservoirs. Rule 46 includes requirements for
monitoring, reporting, and testing of Class II injection wells. Furthermore, the OCC and the TRRC rules
include special conditions regarding monitoring, reporting, and testing in the individual permits for each
injection well if they are deemed necessary.

5 Considerations Used to Calculate Site-Specific Variables for the
Mass Balance Equation

5.1 Determining Mass of CO2 Received

According to the MRV plan, Camrick Unit currently receives C02 at its CFA facility through its own
pipeline from the Arkalon Ethanol plant in Liberal, Kansas. Camrick Unit also recycles C02 from its
production wells in the CFA. Therefore, in accordance with 40 CFR §98.444(a)(2), Camrick Unit has
elected to use Equation RR-2.

C02Tx = Y*=1 (Qr,p - Sr p) * D * Cc02pr (Equation RR-2)

Where:

C02T,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

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D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2,P,r= Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Flow meter.

Camrick Unit provides an acceptable approach to calculating the mass of C02 received in accordance
with Subpart RR requirements.

5.2	Determining Mass of CO2 Injected

Camrick Unit lists the SEF injection wells in Appendix 1 of the MRV plan and uses Equation RR-5 to
calculate the mass of C02 that is injected.

/*"\	Tl /»¦	*"*%	/ mm	_ •	mm \

C02,u = Zp=i Qp.u * D * CCo2 pu (Equation RR-5)

Where:

CO 2u Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2,P,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent
C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Flow meter.

Camrick Unit provides an acceptable approach to calculating the mass of C02 injected in accordance
with Subpart RR requirements.

5.3	Mass of CO2 Produced from Oil Wells

Camrick Unit also recycles C02 from its production wells which are part of its operations in the CFA.
Therefore, Equation RR-8 is used to calculate the mass of C02 produced.

13

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C02 w = Ep=i	Qpw * D * (Equation RR-8)

Where:

CO 2u — 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2,P,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent
C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, Camrick Unit will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9 below:

C02P = (1 + X) * Zw=i(Equation RR-9)

Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

Camrick Unit provides an acceptable approach to calculating the mass of C02 produced from oil wells in
accordance with Subpart RR requirements.

5.4 Calculation of Mass of CO2 Emitted by Surface Leakage

The MRV plan states that per 98.448 (d) of Subpart RR, Camrick Unit will assess leakage from the
relevant surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233 (r)

14

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(2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to estimate all
streams of gases, including recycle C02 stream, for facilities that conduct EOR operations.

Camrick Unit will calculate the total annual mass of C02 emitted from all leakage pathways in
accordance with the procedure specified in Equation RR-10 below:

C02e = Zx=i^^2,x (Equation RR-10)

Where:

CO 2e — Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year.
X = Leakage pathway.

Calculation methods from subpart W will be used to calculate C02 emissions from equipment
located on the surface between the flow meter used to measure injection quantity and the
injection wellhead.

Camrick Unit provides an acceptable approach for calculating the mass of C02 emitted by surface
leakage in accordance with Subpart RR requirements.

5.5 Calculation of Mass of CO2 Sequestered

The MRV Plan states that the mass of C02 sequestered in subsurface geologic formations will be
calculated based off Equation RR-11, because the facility will be actively producing oil or natural gas, as
follows:

C02 = C02i — C02p — C02e — C02fi — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year.

C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this
source category in the reporting year.

CO 2p=Total annual CO2 mass produced (metric tons) in the reporting year.

CO 2E — Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year.

15

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CO 2fi - Total annual CO2 mass emitted (metric tons) from equipment leaks and vented emissions of
C02 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
the GHGRP.

CO 2fp - Total annual CO2 mass emitted (metric tons) from equipment leaks and vented emissions of
C02 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
the GHGRP.

Camrick Unit provides an acceptable approach for calculating the mass of C02 sequestered in
accordance with Subpart RR requirements.

6 Summary of Findings

The Subpart RR MRV plan for Camrick Unit Facility meets the requirements of 40 CFR 98.238. The
regulatory provisions of 40 CFR 98.238(a), which specifies the requirements for MRV plans, are
summarized below along with a summary of relevant provisions in the Camrick Unit MRV plan.

Subpart RR MRV Plan Requirement

Camrick Unit MRV Plan

40 CFR 98.448(a)(1): Delineation of the
maximum monitoring area (MMA) and the
active monitoring areas (AMA).

Section 3 of the MRV plan describes the MMA and
AMA. The MMA is defined as equal to or greater than
the area expected to contain the free-phase C02 plume
until the C02 plume has stabilized plus an all-around
buffer zone of at least one-half mile. The AMA has been
defined as the entire CFA.

40 CFR 98.448(a)(2): Identification of
potential surface leakage pathways for C02
in the MMA and the likelihood, magnitude,
and timing, of surface leakage of C02
through these pathways.

Section 4 of the MRV plan identifies and evaluates
potential surface leakage pathways. The MRV plan
identifies the following potential pathways: leakage
from surface equipment, leakage through existing wells
within MMA, leakage through faults and bedding plane
partings, leakage through lateral fluid movement,
leakage through confining/seal system, and leakage
through natural and induced seismic activity. The MRV
plan analyzes the likelihood, magnitude, and timing of
surface leakage through these pathways. Camrick Unit
determined that these leakage pathways are not likely
at the Camrick Unit facility, and that it is unexpected
that potential leakage conduits would result in
significant loss of C02 to the atmosphere.

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40 CFR 98.448(a)(3): A strategy for
detecting and quantifying any surface
leakage of C02.

Section 4 of the MRV plan also describes both the
strategy for how the facility would detect C02 leakage
to the surface and how the leakage would be
quantified, should leakage occur. Leaks would be
detecting using methods such as field inspections,
continuous monitoring of pressure in WAG skids, and
mechanical integrity testing.

40 CFR 98.448(a)(4): A strategy for
establishing the expected baselines for
monitoring C02 surface leakage.

Section 5 of the MRV plan describes the strategy for
establishing baselines against which monitoring results
will be compared to assess potential surface leakage.

40 CFR 98.448(a)(5): A summary of the
considerations you intend to use to
calculate site-specific variables for the mass
balance equation.

Section 6 of the MRV plan describes Camrick Unit's
approach to determining the amount of C02
sequestered using the Subpart RR mass balance
equation, including as related to calculation of total
annual mass emitted from equipment leakage.

40 CFR 98.448(a)(6): For each injection
well, report the well identification number
used for the UIC permit (or the permit
application) and the UIC permit class.

Appendix 1 of the MRV plan provides the well
identification numbers for all injection wells. The MRV
plan specifies that the wells have been issued a UIC
Class II permit under TRRC Rule 46.

40 CFR 98.448(a)(7): Proposed date to
begin collecting data for calculating total
amount sequestered according to equation
RR-11 or RR-12 of this subpart.

Section 7 of the MRV plan states that Camrick Unit will
begin implementing baseline measurements of
injection volumes and pressures will be taken
September 1, 2022.

17

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Appendix A: Final MRV Plan

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Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

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Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	22

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	31

5.5	Well Surveillance	31

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	32

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	34

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	35

8.1.3	CO2 Injected	35

8.1.4	CO2 Produced	35

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	36

8.3	Estimating missing data	36

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 Code of Federal Regulations (CFR) 98.440 (c)(1), Subpart RR of the
Greenhouse Gas Reporting Program (GHGRP) for the purpose of qualifying for the tax credit in section
45Q of the federal Internal Revenue Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

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Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 8 describes the quality assurance and quality control procedures that will be implemented for
each technology applied in the leak detection and quantification process. This section also includes a
discussion of the procedures for estimating missing data as detailed in 40 CFR 98.445.

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood had reported under Greenhouse Gas Reporting Program Identification number
544678 and the NPU C02 Flood had reported under Greenhouse Gas Reporting Program
Identification number 544679. The EPA has been notified that the NPU will not be reporting for
2022, and that the facility has been merged into the Camrick Unit Facility Identification number
544678.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through 165:10-5-
15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules under OAC 165:5-7-
29, and other governing filing forms. Also, the TRRC has issued UIC Class II enhanced recovery
permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the CFA, including both
injection and production wells, are regulated by the OCC and the TRRC, which have primacy to
implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection process
are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

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injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

CapturePoint has defined the boundary of the MMA as equivalent to the boundary of the
CFA plus Vz mile beyond. A discussion of the methods used in delineating the MMA and the
AMA are presented in Section 3.

2.2.2 Geology

The geological discussions in Sections 2.2.2 and 4.3-4.4 are based on analysis of logs from
both the Farnsworth Unit, which is located 10 miles South-South-West of the CFA, and the
CFA. Both areas have similar pay thickness, porosity values, permeability measurements,
depositional environment, tectonic processes, and overburden strata layers. The
descriptions of cores at the Farnsworth Unit included sections from overlying seals as well as
the shale underlying the main reservoirs, petrographic thin section descriptions and point
counts as well as a variety of special analytical techniques. These techniques included X-ray
diffraction (XRD), which is the science of determining the atomic and molecular structure of
rock crystals with an X-ray beam; scanning electron microscope (SEM) analysis, which uses a
beam of electrons to define the surface of crystals; carbon isotope analysis to estimate the
age of the C02 in the sample; and a variety of mechanical tests. Two dimensional (2D) and
three dimensional (3D) geophysical surveys were also used as part of the Farnsworth Unit
MRV Plan (2021). Details of recent geological investigations can be found in Gallagher
(2014), Gragg (2016), Rasmussen et al (2019), Rose-Coss et al (2015), Trujillo (2018), Hobbs
et al (2019), and Gragg et al (2018).

2.2.2.1 Tectonic Setting and Stratigraphy
The CFA is located on the northwest shelf of the Anadarko basin (Figure 2.2-1) and is one of
many oil fields in the area that produce from a sequence of alternating sandstones and
mudstones deposited during the late Pennsylvanian Morrowan period. Oil production and
C02 injection at CFA is restricted to the operationally named Morrow B sandstone; the
uppermost Morrow sandstone encountered below the Atokan Thirteen Finger limestone.
The primary caprock intervals at CFA are comprised of the upper Morrow shale and the
Thirteen Finger limestone (Figure 2.2-2). The Morrowan and Atokan intervals were
deposited approximately 315-300 million years ago. Overlying stratigraphy includes late
Pennsylvanian through the middle Permian shales and limestones, with lesser amounts of
dolomite, sandstone and evaporites (Ball, 1991). The reservoir is approximately 60 feet thick
throughout the field and lies at a depth of approximately 6,800-7,600 feet. The primary seal
rocks of the Morrow shale and the Thirteen Finger Limestone comprise a package of
approximately 180-200 feet thick in the field and are overlain by thousands of feet of
Atokan and younger limestones and shales.

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Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

From CFA's location on the western edge of the basin, the Anadarko Basin plunges to the
southeast (Figure 2.2-3) where it reaches depths of over 40,000 feet (12,192 meters)
adjacent to the Amarillo-Wichita Uplift (Perry, 1989). Maximum rates of subsidence
occurred during Morrowan to Atokan times (Evans, 1979; Perry, 1989; Higley, 2014).
Positive features that might have influenced deposition within the region include the
Ancestral Rockies to the north, the Central Kansas uplift to the northeast, and the Wichita-
Amarillo uplift to the south (Evans, 1979; Munson, 1989). Of note is the fact that during the
Pennsylvanian time, the CFA was located on the basin shelf in an area that was not affected
greatly by tectonic deformation. Although faults have been reported previously in the
northwest Anadarko Basin, we found no direct evidence for tectonic faults within the CFA
(see Section 4).

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OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

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The Thirteen Finger limestone formation has two different lithofacies: diagenetic limestone
(cementstone) and pyrite and fossil bearing fine to medium mudstone and coal. The two
facies are intercalated with each other but tend to cluster in layers dominated more by one
or the other.

The entire Thirteen Finger interval is typically 130 feet (39.6 meters) thick, comprised of
mudstone, coal, and limestone. The mudstone is calcite rich, with some dolomite, and is
completely diagenetic in origin and probably formed relatively soon following deposition.

2.2.2.2 Hydrogeology
Information about Morrowan and Atokan formation water flow during oil operations has
not been discovered in any oil or gas company published reports or academic research
studies in the Anadarko Basin. Groundwater flow rates in confined deep Anadarko layers at
present are considered to be low to no flow (Nelson and Gianoutsos, 2014). Their
arguments are based on (1) restricted recharge in the western basin, (2) density barriers to
flow in the east, and (3) an overpressure pocket inhibiting flow in the deep basin. Jorgenson
(1989) suggested flow could be west to east, driven by potential recharge to elevated units
in the west and discharge at lower elevation outcrops in the east. The CFA C02 injection and
production operations have negligible likelihood of causing water to flow to outcrops of the
late Carboniferous (Pennsylvanian) time period that extend from Brownwood, Texas, to the
Jacksboro/Bowie, Texas, area, which are hundreds of miles away (The Paleontology Portal).

The Carboniferous is a geologic period and system that covers 60 million years from the
Devonian Period 358.9 million years ago, to the beginning of the Permian Period, 298.9
million years ago. As noted in the Section 2.2.2.1, the Morrowan and Atokan intervals of the
CFA were deposited approximately 315-300 million years ago and are contained in the
Carboniferous period.

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the boundaries
of the CFA. C02 captured from the ethanol plant fermentation process is delivered via pipeline to
the field for injection. The Arkalon plant in Liberal, Kansas is the only source of C02 to the field. The
amount delivered is dependent on the production of C02 produced from the fermentation process.
This amount will vary but should average 12 MMCFD. Once C02 enters the CFA there are three
main processes involved in EOR operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from the CFA
central tank battery (CTB) and sent through the main C02 distribution system to various
water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test" (AWT)
site. The AWT site has two major purposes; 1) to individually test a well's performance by
separating and metering oil, gas, and water, and 2) to separate all gas from liquid then send
these two phases to the CTB for final separation; while only the gas from NPU is sent to the
CTB the NPU oil and water remains in Texas.

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3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

2.3.1 CO2 Distribution and injection
CapturePoint purchases C02 from Conestoga Energy Partners, the parent company of the
Arkalon Ethanol plant located in Liberal, Kansas. A custody transfer meter is located in the
compression facility owned and operated by CapturePoint. The purchased C02 from the
fermentation process is transported via a United States Department of Transportation (DOT)
regulated pipeline to the CFA. A totalizer meter, for the purchased C02, is located in the field
where instantaneous data is summed into a 24-hour flow rate which is recorded. A totalizer
meter is a meter approved by the American Gas Association (AGA) Report #3 to measure the
flowrate of gases. The actual measurements taken are temperature, line pressure, and
differential pressure across the meter. Gas produced, which contains recycled C02, from the
wells is compressed and metered by a similar totalizer meter as the purchase C02 meter and
is recorded daily.

CapturePoint currently has seven active injection manifolds and approximately 29 active
injection wells that the C02 is distributed through. When the MRV plan becomes active, the
daily injection volume of the combined purchased C02 and recycled C02 will be
approximately 24 MMCFD. Of this volume 12 MMCFD is purchased C02 and 12 MMCFD is
recycled C02. This ratio of purchased C02 to recycled C02 is expected to change over time,
with the percentage of recycled C02 increasing and purchased C02 decreasing. The current
reservoir management plan projects that C02 purchases will remain constant at 12 MMCFD
for 12 years and cease after 2034. A reservoir management plan is an integrated process
using various surveillance techniques, economic evaluations, and accepted petroleum
technical practices to efficiently operate enhanced oil recovery projects.

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The seven injection manifolds currently in the field distribute the C02 to the field. These
manifolds have valves to switch to water when the time is called for. Depending on the
reservoir management plan, the WAG cycle will be adjusted to maximize oil recovery and
minimize C02 utilization in each injection pattern. At each injection well pad there is a
totalizer to measure the volumes injected every 24 hours. This data is collected daily by the
field personnel and input into the data warehouse to be allocated for the pattern injection.

The two totalizer meters as described above will be used to determine the total volume
injected used in section 7 for the mass balance equations necessary to determine annual
and cumulative volumes of the stored C02.

2.3.2 Produced Fluids Handling
As injected C02 and water migrate through the reservoir; a mixture of oil, gas, and water
(referred to as "produced fluids") flows to the production wells. Gathering lines bring the
produced fluids from each production well to the AWT sites. CapturePoint has
approximately 32 active production wells producing at any time. Each AWT has two
separators. The first separator is used for testing individual wells to separate the gas, oil,
and water produced from an individual well. This gas, oil, and water is subsequently
measured and recorded for the well. Each producing well is production tested every 30 to
60 days after the last production test, or after the well is returned to production. Depending
on the reservoir management plan, well testing can be more frequent to obtain data. The
second separator is used to separate the gas from the oil/water mixture from the other
wells producing into the AWT, and the gas and liquids are displaced from the vessel in
separate lines. Leaving the AWT sites are two lines transporting produced fluids. One line is
used for the liquid phase, a mixture of oil and water, and one line is used for the gas phase.
However, the AWT in NPU does not transfer oil or gas to the CTB, it only transfers gas while
reinjecting water with pumps at the NPU AWT and sells oil at the NPU AWT.

When gas and liquid lines enter the CTB, a series of vessels separate the oil, gas, and water
to be accounted for and distributed for sales or reinjected. The liquid phase line has vessels
to separate the oil from the water using density and residence time. The gas phase vessels
collect any free liquids entrained with the gas. These free liquids are then combined back
into the liquid phase line. All gas and water are reinjected, and the oil, which contains an
estimated 2,360 ppm C02 (0.236%) for CU and 4,540 ppm C02 (0.454%) for NPU, is sold out
of tanks. Annually, the oil from the stock tank is analyzed by a laboratory using ASTM crude
oil analysis methods to determine the C02 content in the oil being sold.

After separation, the gas phase, which is approximately 92-95% C02, is mixed with reservoir
volatile components, compressed, and distributed throughout the high-pressure distribution
system using reciprocal compression and high-pressure horizontal pumps.

The water is transferred from the separation vessels to tanks for reinjection. After the water
is conditioned, it is either reinjected at the WAG skids or disposed of into permitted disposal
wells. Although CapturePoint is not required to determine or report the amount of dissolved
C02 in the water as it is reinjected into the ground and not emitted to the atmosphere, the
analyses have shown the water typically contains <690 ppm (0.069%) C02.

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CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, which might go
unnoticed by other observations or measurements. No gas volumes can be calculated based
on the detector reading or alarm; only a H2S leakage is detected and located. Once
identified, a further response will be initiated and C02 volumes will be quantified as
discussed in sections 4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

Produced gas separated at the CTB is stripped by a series of vessels of entrained and free
water. The water content has been recorded to be < 20 pounds mass per MMCF, thus
dehydration is not necessary. The gas is then sent to a centralized compression system to be
compressed and placed in the high-pressure distribution system. This compression turns the
C02 into a variable density liquid, which is then transported out via high pressure lines to the
AWT sites where a manifold splits this dense C02 to the wells that are on C02 injection at
that time.

2.3.4 Facilities Locations

The locations of the AWT sites are positioned in the field to access both injection
distribution and production gathering. The CTB is where the final separation and injection
equipment is maintained and operated. The water injection station is where the horizontal
pumps are located to reinject the produced brine.

-------
CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

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Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic,
or resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from
the Regulators and allow consideration of the suitability of the cement based on the
use of the well, the location, and setting of plugs.

2.3.7 Number, Location, and Depth of Wells
CapturePoint's CFA injection wells are listed in Appendix 1. Injection is into the Upper
Morrowan, a lenticular bedded sandstone trending northwest to southeast with the average
top of sand at 7,250 feet, true vertical depth. The Upper Morrowan is described in section
2.2.2.1 above.

2.4 Reservoir Characterization

2.4.1 Reservoir Description
The target reservoir CFA Morrow B is a sandstone formation overlain by the Morrow shale
and the Thirteen Finger limestone, which serve as excellent seals for injected C02 as
determined by Farnsworth data (Ampomah et al., 2016a). The Morrow B sandstone
reservoir is at a depth between 6,800 feet and 7,600 feet subsurface with an average dip of
less than one degree (Figure 2.4-1). The productive limit of the CFA is about 80 to 90 percent
of the total operated surface acreage, which is 14,652.315 acres. The maximum pay
thickness is 56 feet with an average of 15 feet and does diminish to zero in spots.

The CFA is approximately eight miles by seven miles with areas that exhibit different
reservoir behavior. The southwest portion of CU was most prolific oil producing area of the
CFA under primary and secondary production; whereas the western portion of NPU is now
responding to C02 better than historical operations would have indicated.

-------
(Lower Right) Thickness map of Morrow sands.

15

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2.4.2 Reservoir Fluid Modeling
The compositional fluid model was constructed for the CapturePoint operated Farnsworth
Unit. From laboratory compositional analysis an equation of state was tuned (Gunda et al.,
2015). The minimum miscibility pressure (MMP) experiment was then simulated using a
one-dimensional model. The simulated Farnworth Unit MMP of 4,009 psia compared to an
MMP value of 4,200 psia derived from laboratory experiments provided by the operator
represents a less than 5% error (Gunda et al., 2015).

The reservoir temperature in the CFA is 152 degrees Fahrenheit or 16 degrees lower than
the temperature at Farnsworth Unit of 168 degrees. Using parameters of the Alston
empirical correlation (1985), the MMP would be 170 psia lower at the CFA or 3,510 psia
compared to 3,680 psia at the Farnsworth Unit (Figure 2.4-2).

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

Based on similar geologic, petrophysical, engineering, and operational parameters between
the Farnsworth Unit and the CFA, the oil recovery performance of both fields is expected to
be similar. Due to the stratigraphic nature of the Morrow channel sands, the potential
movement of C02 is severely limited. The CFA area has contained the free phase C02 plume
in a very confined area since March 2001 as exhibited by oil, water, and C02 recovery
performance. Also, during CFA drilling and production operations, no reports exist which
would indicate any plume has moved outside of the MMA. The Farnsworth Unit MRV and
the CFA data justifies the conclusion that C02 will continue to be contained inside the MMA
at the end of the C02 injection year t + 5, per §98.449 definitions.

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

-------
amount of oil recovered from projects is plotted as a decimal fraction of the original-oil-in-
place versus the decimal fraction of the hydrocarbon pore volume (HPV) of C02 injected into
the oil reservoir as measured in reservoir barrels (RB).

The CFA has been injecting C02 since March 2001. The dimensionless curves were matched
to historical performance through early 2020 (Figure 2.4-3). The supply of C02 was curtailed
from March 2020 until present, due to oil price uncertainty, and will resume after the
Arkalon Plant upgrade that will be finished in the 4th quarter of 2022.

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
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Wat l vpe Curve

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War Type Curve

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Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

The dimensionless water oil ratio and the gas oil ratio trends (Figure 2.4-4) for the CFA
flooded acreage are very similar to what was forecasted by simulation in the Farnsworth
Field as expected because of the porosity, permeability, and sand similarities.

too

Camrick/N Perryton Forecast Type Curve

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Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

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The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Purchase (Fermentation) Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

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Camrick Field Area Purchase vs Time

120
100
80

H 60

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Purchase (Fermentation) Volume.

Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than the area
expected to contain the free phase C02 plume until the C02 plume has stabilized plus an all-around
buffer zone of at least one-half mile. The purchase volumes that are displayed in Figure 2.4-6 were
mapped and are displayed in Section 3.1.1 indicating that C02 storage pore space is available,
barring unforeseen future operational issues. Therefore, CapturePoint is defining the MMA as the
boundary of the CFA plus an additional one-half mile buffer zone. This will allow for operational
expansion throughout the CFA for the next 12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Figure 3.1-1 displays wells that have C02 retention on the developed 4,800 acres that have
been under C02 EOR injection in the CFA since project initialization (14,652.315 acres are in
the CFA). The volume of the oil recovered since August 1955, resulted in a voidage space of
36 MMscf of C02 per acre of surface area that was later filled with water during waterflood
operations. The average decimal fraction of C02 injection to hydrocarbon pore volume left
in the ground after accounting for C02 production through 2021 is 0.29. The lateral extent of
C02 in the injection zone or the C02 storage radius for each well was estimated based on
cumulative C02 injected times the decimal fraction of C02 remaining divided by the voidage
space. The largest C02 storage areas are around wells that injected the largest volume C02.

Ferm entatio n
C02

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Figure 3.1-2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres per pattern can be filled. The volumetric storage capacity calculated for the
49 patterns identified for continued injection indicates an additional 90 Bscf of C02 can be
stored and with 50 Bscf already stored results in 140 Bscf of total storage. With the
anticipated 12 MMCFD rate of purchased C02, this storage volume will only be 60 percent
utilized. As delineated in this MRV plan, the MMA account for an injected volume of up to
140 Bscf and includes all areas of the CFA that could be utilized in the future for C02
injection. The MMA will contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. If there are any material changes to
the monitoring/operational parameters not outlined in this MRV plan, the plan will be
resubmitted in accordance with 40 CFR 98.448(d)(1).

Areas that do not have C02 storage posted on Figure 3.1-2 will be evaluated if existing C02
injection operations experience any rate restriction or develop any operational issues in the
future. If necessary, replacement wells or additional injection locations in inactive areas of
the CFA will be drilled or activated. This will be accomplished by utilizing existing plugged
and abandoned wells or redrilling old locations as described in Section 3.2.

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The AM A is the land area inside the solid line polygon except for the red hashed rectangle.
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3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization and stratigraphic
trapping of the Morrow did not reveal any leakage pathways that would allow free-phase
C02 to migrate laterally thereby warranting a buffer zone greater than one-half mile.

3.2 AMA

The Active Monitoring Area (AMA) is defined by CapturePoint's exclusive right to operate the CFA
unitized leases, as described in the INTRODUCTION and Section 2.2.1. Currently, CapturePoint's
operations are focused on the western portion of the CU and the entire NPU. However, it is
anticipated as time passes, or additional C02 volumes become available additional areas within the
CFA may be developed. Additional development is driven by the market price of oil coupled with
the availability of sufficient C02 volumes and thus the timing of additional development is
uncertain at this time. As C02 injection operations are expanded beyond the currently active C02
EOR portion of the CFA, all additional C02 injection wells will be permitted under the UIC program
and will be included in the annual submittal per 40 CFR 98.446(f)(13). All future C02 injection wells
permitted will be within the AMA. Based on our projections, CapturePoint expects the free phase
C02 plume to remain within the CFA for the entire length of the project and through year [t + 5],
Therefore, CapturePoint is defining the AMA as the CFA plus an all-around one-half mile buffer,
consistent with the definitions in 40 CFR 98.449. If there are any material changes to the

-------
monitoring/operational parameters not outlined in this MRV plan, the plan will be resubmitted in
accordance with 40 CFR 98.448(d)(1).

Therefore, for the purposes of this MRV plan, CapturePoint is continuously monitoring the entire
CFA, which is the AMA.

4 Identification and Evaluation of Leakage Pathways

Since its discovery in 1955, the unitization of the different units from 1969 to 1972, and the
commencement of C02 EOR in 2001; the CFA is an analogous field to the Farnsworth Unit, which has
undergone extensive investigation and documentation as indicated in Section 2. From this body of work,
CapturePoint has identified the following potential pathways of C02 leakage to the surface. This section
will also address detection, verification, and quantification of leakage from each pathway.

4.1 Leakage from Surface Equipment

The surface equipment and pipelines utilize materials of construction and control processes that
are standard in the oil and gas industry for C02 EOR projects. Ongoing field surveillance of
pipelines, wellheads, and other surface equipment via personnel instructed on how to detect
surface leaks and other equipment failure minimizes releases. In addition, the Oil and Gas Division
requirements of the OAC rules of the OCC and the TAC rules of the TRRC to report and quantify
leaks, both serve to minimize leakage of GHG from surface equipment. Operating and maintenance
practices currently follow and will continue to follow demonstrated industry standards. As
described in Section 6.4 below, should leakage from surface equipment occur it will be quantified
according to the procedures in Subpart W of the GHGRP.

4.2 Leakage from Wells

CapturePoint has identified 68 abandoned wells, 49 injection wells (29 active) and 94 production
wells (59 active) within the MMA and assessed their potential for leakage of C02 to the surface as
listed in Appendix 1.

4.2.1 Abandoned Wells

Figure 4.2-1 shows all wells plugged and abandoned in the CFA. Because the CFA was
unitized in 1969 to 1972, all plugging and abandonment activities of wells within the CFA
have been conducted under the regulations of the OCC and the TRRC for plugging wells. The
cement used to plug wells when exposed to C02 will form colloidal gels that further reduce
any flow. CapturePoint concludes that leakage of C02 to the surface through abandoned
wells is unlikely. However, strategies for leak detection are in place that are discussed in
Section 4.5 and the strategy to quantify the leak is discussed in Section 4.6.

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4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

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4.2.3 Production Wells

Some of the original field wells drilled as oil wells were reclassified, administratively, to gas
wells per OAC Title 165:10-1-6 paragraph (d), because of the gas-oil ratio growth due to
reservoir depletion. Hence, there is no difference in well construction. (See Section 2.3.6) As
the field is being further developed for enhanced oil recovery, these gas wells have been
reclassified to oil wells per OCC regulations and will be monitored for leakage. (See Section
4.7) Figure 4.2-3 shows the active oil production wells in the CFA. Once EOR operations
commence, the energy content of the produced gas drops and cannot be sold; therefore,
any inactive gas wells are either reclassified to oil producers, or activated to WAG injectors,
as described earlier. (See Section 4.2.2) However, as the project develops in the CFA
additional production wells may be added and will be constructed according to the relevant
rules of the OCC and the TRRC. Additionally, inactive wells may become active according to
the rules of the OCC and the TRRC.

During production, oil, gas, and water flow from the reservoir into the wellbore. This flow is
caused by a differential pressure where the bottom hole wellbore pressure is less than the
reservoir pressure. These lower pressure fluids, which also contains C02, are contained by
the casing, tubing, wellhead, and flowline all the way to the CTB. CapturePoint concludes
that leakage of C02 to the surface through production wells is unlikely.

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

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4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

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• And that all wells follow plugging procedures that require advance approval from
the Regulators and allow consideration of the suitability of the cement based on the
use of the well, the location and setting of plugs.

New well construction is based on existing best practices, established during the drilling of
existing wells in CFA and follows the OCC and the TRRC rules, which significantly limits any
potential leakage from well pathways. Additionally, the existing wells followed the OCC and
the TRRC rules.

In public databases, the area of CFA plus one mile past the unit boundary contains over 100
wells that were drilled deeper than the Morrow formation and none of these wells were
productive in reservoirs deeper than the Morrow. Therefore, it is very unlikely that anyone
will ever drill through the AMA reservoir in the future. In the event a well is drilled within
the AMA, the operator would be required to follow all the OCC and the TRRC rules and
procedures in the drilling the well and the potential for leakage would be similar to any well
that CapturePoint drills within the AMA. In addition, CapturePoint's visual inspection
process during routine field operation will identify any unapproved drilling activity in the
CFA.

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see Section
2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems along fracture
networks. The following lines of analysis have been used to assess this risk in the area.

4.3.1 Prescence of Hydrocarbons

The first and foremost argument against present day up-fault transmissibility is the 75 MMB
of oil that was found trapped in the reservoir. If significant escape pathways existed, oil
would have drained from the reservoir prior to the current day.

4.3.2 Fracture analysis

At the CFA, the work done at the Farnsworth Unit is analogous, where small aperture
fractures were noted but not common in most of the reservoir cores examined but most of
these fractures appear to be drilling induced. Fractures in the Thirteen Finger limestone
caprock were described using an industry-standard format for fracture class type,
orientation, fracture dip, type of mineral fill, fracture porosity, fracture spacing, and
intensity. Again, drilling induced fractures are most common. Natural mineral-filled fractures
are quite rare, were formed during diagenesis at shallow depths, and are of late
Carboniferous age. Unless significantly damaged by large changes in reservoir pressure, they
are highly unlikely to provide migration pathways.

In the unlikely event C02 leakage occurs as a result of leakage through the faults and
fractures, it is unlikely that the leak would result in surface leakage. As with any C02 leakage,
CapturePoint has strategies for leak detection in place that are discussed in Section 4.5 and
the strategy to quantify the leak is discussed in Section 4.6.

-------
4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence that
prograded toward the southeast, resulting in deposition of mainly shales with lenticular,
discontinuous coarse sandstones separated with very fine sandstone, minor conglomerates, and
shale. The likelihood of any extensive migration of fluid outside of the AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of each
lenticular structure as it is filled. The producing wells, which create low pressure points in the field,
will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical methods
were used for caprock (confining system) analysis, and the results should be the same for the CFA.
Petrologic examination included standard thin section petrography and backscattered electron
microscopy. Petrophysical analytical methods include retort analysis, pulse-decay permeability
measurement, pressure decay permeability analysis for tight rocks, and mercury injection
porosimetry, which is also known as mercury injection capillary pressure (MICP). Geomechanical
analysis involved a standard series of mechanical tests: Brazil tension, unconfined compression,
triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and Thirteen
Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an order of
magnitude over the thickness of the Morrow reservoir, this should prove an effective seal for C02
storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so that any
fracture initiation around the injection well would not be expected to propagate into the overlying
sealing units. Mechanical properties of the overlying shale and limestones provide an interesting
and effective combination of strength and elasticity. Limestone layers are strong but brittle, while
the shale layers are weaker but sufficiently ductile to prevent extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02 migration
would be most likely due to leakage from wellbores or bypass through fault and fracture networks,
discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint has
strategies for leak detection in place that are discussed in Section 4.5 and the strategy to quantify
the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

Figure 4.6-1 shows the map of earthquakes with magnitudes measured at greater than 2.5 as
defined by the United States Geological Survey (USGS). While past earthquake data cannot predict
future earthquakes, the small number of events near CFA after the waterflood operations were
initiated in 1969 implies the area is not seismically sensitive to injection. Also, no documentation

-------
exists that any of the distant earthquake events caused a disruption in injectivity or damage to any
of the wellbores in CFA.

Kansa:

ueblo

Dodge City

Lil>eral

Wichita Falls

Lubbock

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02 to the
surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of C02 to
migrate from the injection zone, other reservoir fluid monitoring provisions (e.g., reservoir
pressure, well pressure, and pattern monitoring) would lead to further investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as problems
with surface equipment (pumps, valves, etc.) or subsurface equipment (well bores), and unique
events such as induced fractures. Table 1 summarizes some of these potential leakage scenarios,
the monitoring activities designed to detect those leaks, Capture Point's standard response, and
other applicable regulatory programs requiring similar reporting.

29

-------
The potential C02 losses discussed in the table are identified by type. Once the type is reported to a
response manager the correct resources and personnel can be mobilized to develop the optimal
response procedure. The procedure will address and mitigate further C02 leakage.

Table 1 Response Plan for C02 Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track, and if
applicable, quantify potential C02 leakage to the surface. CapturePoint will use Subpart W
techniques to estimate leakages only on equipment and ensure those results are consistently
represented in the Subpart RR report. Any event-driven leakage quantification reported in Subpart
RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be encountered,
it is not clear the method for quantifying the volume of leaked C02 that would be most
appropriate. In the event leakage occurs, CapturePoint will determine the most appropriate
method for quantifying the volume leaked and will report the methodology used as required as
part of the annual Subpart RR submission.

Any volume of C02 detected leaking to the surface will be quantified using acceptable emission
factors such as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts
based on measurements in the subsurface, CapturePoint's field experience, and other factors such
as the frequency of inspection. As indicated in Section 6.4, leaks will be documented, and the
records of leakage events will be retained in the electronic environmental documentation and

30

-------
reporting system, which consists of reports stored on servers, with information uploaded into third
party software.

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers)
suggest that the amount released from routine leaks would be small as compared to the amount of
C02 that would remain stored in the formation.

5 Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02 values
for soil measurement in the CFA area, per the characterization, monitoring and well data collected by
the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and below
by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow shale and
Thirteen Finger Limestone which in turn is overlain by over a thousand feet of younger shale and
limestone. These units provide a suitable seal to prevent the migration of C02 out of the injection
reservoir. Additionally, no significant faults or fracture zones that cut across the seal units have
been identified in the CFA, indicating that the most likely leakage pathway is from legacy wellbores
that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of fluid
leakage has been identified from any of these in the CFA area. CapturePoint is unlikely to continue
monitoring USDW wells for C02 or brine contamination, as characterization of the Morrow (see
section 5.1) has suggested minimal risk of groundwater contamination from C02 leakage from this
depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due to
COVID travel restrictions. However, the atmospheric C02 concentration data from the eddy tower
were in very good agreement with values obtained from the NOAA Global Monitoring Laboratory
station in Moody, Texas (Station: WKT). Since the CFA area is in close proximity to the Farnsworth
Unit, atmospheric C02 concentrations from the Moody, Texas station can be used for background
C02 values.

5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report and
act upon any event indicating leakage.

5.5 Well Surveillance

-------
rules include special conditions regarding monitoring, reporting, and testing in the individual
permits for each injection well if they are deemed necessary.

CapturePoint also adheres to the requirements of OAC Title 165:10-7 for the OCC and TAC Rule 20
for the TRRC governing the notification of fires, breaks, leaks, or escapes. Rule 20 requires that all
operators report leaks to the OCC or the TRRC including measured or estimated quantities of
product leaked.

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1	Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the Arkalon
Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02 from its production wells in the
CFA.

2T ,r = Ip =1 (Q r,p-Sr,p)*D *C 2jPjr (Equation RR-2)
where:

C02T,r = Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pr = Quai"tei"ly C02 concentration measurement in flow for flow meter r in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02iU = £p=i QpiU * D * Cc02 p u (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3 Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in the CFA.
Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol. percent C02,
expressed as a decimal fraction).

p = Quarter of the year.

w= Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at each
gas-liquid separator in accordance with the procedure specified in Equation RR-9 below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators
in the reporting year (weight percent C02, expressed as a decimal fraction), CU is 0.00236 and NPU
is 0.00454 at the last sample.

w= Separator.

33

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6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant surface
equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233 (r) (2) of
Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to estimate all
streams of gases, including recycle C02 stream, for facilities that conduct EOR operations.

CapturePoint will calculate the total annual mass of CO2 emitted from all leakage pathways in
accordance with the procedure specified in Equation RR-10 below:

C02E = Y^=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural gas.

C02 = C02I - C02P - C02E - C02FI - C02FP (Equation RR-11)

Where:

C02= Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the reporting
year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.

C02pi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 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
theGHGRP.

C02FP= Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 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 the GHGRP.

7 Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

34

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8 GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the collection
of emissions data includes the following:

• Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

• Explanation of the processes and methods used to collect the necessary data for the GHG
calculations.

• Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1 General

Measurement of CO? Volume - All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

8.1.2 CO2 Received

Daily fermentation C02 purchased is received via the pipeline from the Arkalon ethanol
plant in Liberal, Kansas, and is measured using a volumetric totalizer, which uses accepted
flow calculations for C02 according to the AGA Report #3.

8.1.3 CO2 Injected

Daily C02 injection is recorded by combining the totals for the recycle compressor meter and
the received C02 meter from Arkalon based on what's delivered on a 24-hour basis. This
data is taken from the meter daily and stored in CapturePoint's data warehouse for records
and reservoir management.

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

-------
8.1.5	C02 Emissions from equipment leaks and vented emissions of CO2

As required by 98.444 (d), CapturePoint will follow the monitoring and QA/QC requirements
specified in Subpart W of the GHGRP for equipment located on the surface between the
flow meter used to measure injection quantity and the injection wellhead and between the
flow meter used to measure production quantity and the production wellhead.

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations. The default emission factors for production equipment are applied to the
carbon capture utilization and storage (CCUS) injection operations reporting under Subpart
RR.

8.1.6	Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

•	All flow meters are operated continuously except as necessary for maintenance and
calibration.

•	All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

•	All measurement devices are operated according to an appropriate standard
method published by a consensus-based standards organization 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 Gas Producers Association
(GPA), the American Society of Mechanical Engineers (ASME), the American
Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

•	All flow meters are National Institute of Standards and Technology (NIST) traceable.

8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP, as
required in the development of this MRV plan under Subpart RR. Any measurement devices used to
acquire data will be operated and maintained according to the relevant industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR 98.445
of Subpart RR of the GHGRP, as required.

A quarterly flow rate of CO2 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.

36

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A quarterly quantity of C02 injected that is missing would be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.

For any values associated with CO2 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing would
be estimated using a representative quantity of C02 produced from the nearest previous period of
time.

8.4 Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures for the
maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment
downtime.

37

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9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

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10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

C02

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

C02

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

C02

1

0

CU 2731

35007359750000

Oi

Prod

Active

C02

1

0

CU 2761

35007350590000

Oi

Prod

Active

C02

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

C02

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

C02

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

C02

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

co2

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

co2

1

0

CU 3171

35007359600000

Oi

Prod

Active

co2

1

0

CU 3182

35007249250000

Oi

Prod

Active

co2

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

co2

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

co2

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

co2

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

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Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

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§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

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Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

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Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas: Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

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Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

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Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

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Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

CFR - Code of Federal Regulations

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

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NIST - National Institute of Standards and Technology

NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

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Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas-The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

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Appendix B: Submissions and Responses to Requests for Additional

Information

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Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	22

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	31

5.5	Well Surveillance	31

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	32

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	34

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	35

8.1.3	CO2 Injected	35

8.1.4	CO2 Produced	35

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	36

8.3	Estimating missing data	36

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 Code of Federal Regulations (CFR) 98.440 (c)(1), Subpart RR of the
Greenhouse Gas Reporting Program (GHGRP) for the purpose of qualifying for the tax credit in section
45Q of the federal Internal Revenue Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

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Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

1.2 UIC Permit Class

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection process
are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

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injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

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Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

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OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

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CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

-------
Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells file a completion report including basic electric log (e.g., a density, sonic,
or resistivity (except dip meter) log run over the entire wellbore).

2.4 Reservoir Characterization

-------
(Lower Right) Thickness map of Morrow sands.

15

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Purchase (Fermentation) Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

-------
Camrick Field Area Purchase vs Time

120
100
80

H 60

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Purchase (Fermentation) Volume.

Delineation of Monitoring Area

3.1 MMA

3.1.1 Determination of Storage Volumes

Ferm entatio n
C02

CapturePoint LLC
CAM RICK

C02 Retention Storage

0 10.000

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WELL CQ2 III SgflgT

U—

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Figure 3.1-1. Estimated C02 storage as of2021 in CFA.

The AM A is the land area inside the solid line polygon except for the red hashed rectangle.
The MMA extends to dotted red line and includes the red hashed rectangle.

-------

-N

1
1

\
0 N

\ "

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CapturePoint LLC

CAMRICK

C02 Potential Storage
5,000 10,000

FEET

SiSliSISS

Figure 3.1-2. Potential Total CO2 Storage in the CFA.

The AM A is the land area inside the solid line polygon except for the red hashed rectangle.
The MM A extends to dotted red line and includes the red hashed rectangle.

3.2 AMA

-------
monitoring/operational parameters not outlined in this MRV plan, the plan will be resubmitted in
accordance with 40 CFR 98.448(d)(1).

Therefore, for the purposes of this MRV plan, CapturePoint is continuously monitoring the entire
CFA, which is the AMA.

4 Identification and Evaluation of Leakage Pathways

4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

-------






















CapturePoint LLC

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0 5.000 10.000
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Figure 4.2-1. Plugged and Abandoned Wells in the CFA.

4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

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4.2.3 Production Wells

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

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4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

-------
4.4 Lateral Fluid Movement

4.5 Leakage through Confining/Seal system

4.6 Natural and Induced Seismic Activity

-------
exists that any of the distant earthquake events caused a disruption in injectivity or damage to any
of the wellbores in CFA.

Kansa:

ueblo

Dodge City

Lil>eral

Wichita Falls

Lubbock

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02 to the
surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of C02 to
migrate from the injection zone, other reservoir fluid monitoring provisions (e.g., reservoir
pressure, well pressure, and pattern monitoring) would lead to further investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as problems
with surface equipment (pumps, valves, etc.) or subsurface equipment (well bores), and unique
events such as induced fractures. Table 1 summarizes some of these potential leakage scenarios,
the monitoring activities designed to detect those leaks, Capture Point's standard response, and
other applicable regulatory programs requiring similar reporting.

29

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The potential C02 losses discussed in the table are identified by type. Once the type is reported to a
response manager the correct resources and personnel can be mobilized to develop the optimal
response procedure. The procedure will address and mitigate further C02 leakage.

Table 1 Response Plan for C02 Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track, and if
applicable, quantify potential C02 leakage to the surface. CapturePoint will use Subpart W
techniques to estimate leakages only on equipment and ensure those results are consistently
represented in the Subpart RR report. Any event-driven leakage quantification reported in Subpart
RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be encountered,
it is not clear the method for quantifying the volume of leaked C02 that would be most
appropriate. In the event leakage occurs, CapturePoint will determine the most appropriate
method for quantifying the volume leaked and will report the methodology used as required as
part of the annual Subpart RR submission.

Any volume of C02 detected leaking to the surface will be quantified using acceptable emission
factors such as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts
based on measurements in the subsurface, CapturePoint's field experience, and other factors such
as the frequency of inspection. As indicated in Section 6.4, leaks will be documented, and the
records of leakage events will be retained in the electronic environmental documentation and

30

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reporting system, which consists of reports stored on servers, with information uploaded into third
party software.

5 Strategy for Determining CO2 Baselines for CO2 Monitoring

5.1 Site Characterization and Monitoring

5.2 Groundwater monitoring

5.3 Soil CO2 monitoring

5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report and
act upon any event indicating leakage.

5.5 Well Surveillance

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rules include special conditions regarding monitoring, reporting, and testing in the individual
permits for each injection well if they are deemed necessary.

CapturePoint also adheres to the requirements of OAC Title 165:10-7 for the OCC and TAC Rule 20
for the TRRC governing the notification of fires, breaks, leaks, or escapes. Rule 20 requires that all
operators report leaks to the OCC or the TRRC including measured or estimated quantities of
product leaked.

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1	Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the Arkalon
Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02 from its production wells in the
CFA.

C02T,r = Ep=i (Qr,p - sr,p) *D* CCo2vr (Equation RR-2)
where:

C02r,r = Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02,u = Ip=i QP,u *D* Cc02pu (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3 Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in the CFA.
Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol. percent C02,
expressed as a decimal fraction).

p = Quarter of the year.

w= Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at each
gas-liquid separator in accordance with the procedure specified in Equation RR-9 below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators
in the reporting year (weight percent C02, expressed as a decimal fraction), CU is 0.00236 and NPU
is 0.00454 at the last sample.

w= Separator.

33

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6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant surface
equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233 (r) (2) of
Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to estimate all
streams of gases, including recycle C02 stream, for facilities that conduct EOR operations.

CapturePoint will calculate the total annual mass of CO2 emitted from all leakage pathways in
accordance with the procedure specified in Equation RR-10 below:

C02E = Y^=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural gas.

C02 = C02I - C02P - C02E - C02FI - C02FP (Equation RR-11)

Where:

C02= Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the reporting
year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.

C02pi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 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
theGHGRP.

C02FP= Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 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 the GHGRP.

7 Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

34

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8 GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the collection
of emissions data includes the following:

• Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

• Explanation of the processes and methods used to collect the necessary data for the GHG
calculations.

8.1.1 General

8.1.2 CO2 Received

8.1.3 CO2 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

-------
8.1.5	C02 Emissions from equipment leaks and vented emissions of CO2

As required by 98.444 (d), CapturePoint will follow the monitoring and QA/QC requirements
specified in Subpart W of the GHGRP for equipment located on the surface between the
flow meter used to measure injection quantity and the injection wellhead and between the
flow meter used to measure production quantity and the production wellhead.

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations. The default emission factors for production equipment are applied to the
carbon capture utilization and storage (CCUS) injection operations reporting under Subpart
RR.

8.1.6	Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

•	All flow meters are operated continuously except as necessary for maintenance and
calibration.

•	All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

•	All measurement devices are operated according to an appropriate standard
method published by a consensus-based standards organization 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 Gas Producers Association
(GPA), the American Society of Mechanical Engineers (ASME), the American
Petroleum Institute (API), and the North American Energy Standards Board (NAESB).

•	All flow meters are National Institute of Standards and Technology (NIST) traceable.

8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP, as
required in the development of this MRV plan under Subpart RR. Any measurement devices used to
acquire data will be operated and maintained according to the relevant industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR 98.445
of Subpart RR of the GHGRP, as required.

A quarterly flow rate of CO2 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.

36

-------
A quarterly quantity of C02 injected that is missing would be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.

For any values associated with CO2 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing would
be estimated using a representative quantity of C02 produced from the nearest previous period of
time.

8.4 Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures for the
maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment
downtime.

37

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9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

-------
10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

C02

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

C02

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

C02

1

0

CU 2731

35007359750000

Oi

Prod

Active

C02

1

0

CU 2761

35007350590000

Oi

Prod

Active

C02

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

C02

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

C02

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

C02

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

co2

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

co2

1

0

CU 3171

35007359600000

Oi

Prod

Active

co2

1

0

CU 3182

35007249250000

Oi

Prod

Active

co2

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

co2

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

co2

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

co2

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

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TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

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Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

-------
Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas: Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

-------
Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

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Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

-------
Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

CFR - Code of Federal Regulations

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

-------
NIST - National Institute of Standards and Technology

NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

-------
Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas-The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

-------
Request for Additional Information: Camrick Unit
October 18, 2022

Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses,
references, or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic
Greenhouse Gas Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.

1

-------
No.

MRV Plar
Section

Page

EPA Questions

Responses

1.

3.1

19-20

Per 40 CFR 98.449, "Maximum monitoring area (MMA) 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."

In the Request for Additional Information (RFAI) sent on September 1, 2022, EPA
requested that the MRV plan clarify specific details regarding the expansion into
other portions of the CFA which is mentioned in Section 3. Although your
resubmitted MRV plan includes additional details on the projected injection
volumes, please clarify whether the current delineated MMA accounts for the area
expansions and any increased injection volumes. You may consider adding a
clarifying statement, such as:

"...As delineated in this MRV plan, the MMA accounts for an injected volume of up
to Bscf and includes all areas of the CFA that could be utilized in the future
for CO2 injection. The MMA will contain the free phase CO2 plume until the CO2
plume has stabilized plus an all-around buffer zone of at least one-half mile. If
there are any material changes to the monitoring/operational parameters not
outlined in this MRV plan, the plan will be resubmitted in accordance with 40 CFR
98.448(d)(1)."

If the above is accurate for your facility, then please add a similar statement to the
MRV plan to ensure it is clear what is accounted for in the current MMA.

Otherwise, please clarify what is and is not accounted for in the current MMA.

Added the following "As delineated in this MRV plan,
the MMA account for an injected volume of up to 140
Bscf and includes all areas of the CFA that could be
utilized in the future for C02 injection. The MMA will
contain the free phase C02 plume until the C02 plume
has stabilized plus an all-around buffer zone of at least
one-half mile. If there are any material changes to the
monitoring/operational parameters not outlined in this
MRV plan, the plan will be resubmitted in accordance
with 40 CFR 98.448(d)(1)."

2

-------
3.2

21

Per 40 CFR 98.449, "Active monitoring area" (AMA) 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.

In the Request for Additional Information (RFAI) sent on September 1, 2022, EPA
requested that you ensure that the discussion in section 3.2 clearly identifies the
AMA boundaries and describes whether the AMA for the CFA presented in the MRV
plan conforms to the definition of the AMA in 40 CFR 98.449.

Although you added details on CO2 injection at CFA, we are requesting a more
direct statement regarding whether the AMA delineation meets the definition
provided in in 40 CFR 98.449. Please note that the subpart RR definition of AMA is
based on expected plume boundaries, not well locations or lease boundaries. You
may consider adding a clarifying statement, such:

"...Based on our projections, CapturePoint expects the free phase C02 plume to
remain within the CFA for the entire length of the project and through year [t+5].
Therefore, CapturePoint is defining the AMA as the CFA plus an all-around one-
half mile buffer, consistent with the definitions in 40 CFR 98.449. If there are any
material changes to the monitoring/operational parameters not outlined in this
MRV plan, the plan will be resubmitted in accordance with 40 CFR 98.448(d)(1)."

If the above is accurate for your facility, then please add a similar statement to the
MRV plan to ensure it is clear whether the delineated AMA is consistent with
Subpart RR definitions. Otherwise, please clarify and/or revise the AMA as
necessary.

Added the following "Based on our projections,
CapturePoint expects the free phase C02 plume to
remain within the CFA for the entire length of the
project and through year [t + 5], Therefore,
CapturePoint is defining the AMA as the CFA plus an all-
around one-half mile buffer, consistent with the
definitions in 40 CFR 98.449. If there are any material
changes to the monitoring/operational parameters not
outlined in this MRV plan, the plan will be resubmitted
in accordance with 40 CFR 98.448(d)(1)."

3

-------
Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	22

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	32

5.5	Well Surveillance	32

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	33

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	35

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	36

8.1.3	CO2 Injected	36

8.1.4	CO2 Produced	36

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	37

8.3	Estimating missing data	37

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 Code of Federal Regulations (CFR) 98.440 (c)(1), Subpart RR of the
Greenhouse Gas Reporting Program (GHGRP) for the purpose of qualifying for the tax credit in section
45Q of the federal Internal Revenue Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

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Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood had reported under Greenhouse Gas Reporting Program Identification
number 544678 and the NPU C02 Flood had reported under Greenhouse Gas Reporting
Program Identification number 544679. The EPA has been notified that the NPU will not be
reporting for 2022, and that the facility has been merged into the Camrick Unit Facility
Identification number 544678.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through
165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules
under OAC 165:5-7-29, and other governing filing forms. Also, the TRRC has issued UIC Class
II enhanced recovery permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the
CFA, including both injection and production wells, are regulated by the OCC and the TRRC,
which have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

-------
injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

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Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

-------
OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of C02
produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's
performance by separating and metering oil, gas, and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

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CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

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CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

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Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from the
Regulators and allow consideration of the suitability of the cement based on the use of
the well, the location, and setting of plugs.

2.4 Reservoir Characterization

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(Lower Right) Thickness map of Morrow sands.

15

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Purchase (Fermentation) Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

-------
Camrick Field Area Purchase vs Time

120

100

8 60
m

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Purchase (Fermentation) Volume.

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than
the area expected to contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. The purchase volumes that are
displayed in Figure 2.4-6 were mapped and are displayed in Section 3.1.1 indicating that C02
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Ferm entatio n
C02

-------
Figure 3.1-2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres per pattern can be filled. The volumetric storage capacity calculated for the
49 patterns identified for continued injection indicates an additional 90 Bscf of C02 can be
stored and with 50 Bscf already stored results in 140 Bscf of total storage. With the
anticipated 12 MMCFD rate of purchased C02, this storage volume will only be 60 percent
utilized.

Areas that do not have C02 storage posted on Figure 3.1-2 will be evaluated if existing C02
injection operations experience any rate restriction or develop any operational issues in the
future. If necessary, replacement wells or additional injection locations in inactive areas of
the CFA will be drilled or activated. This will be accomplished by utilizing existing plugged
and abandoned wells or redrilling old locations as described in Section 3.2.







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20

-------
CapturePoint LLC

CAMRICK

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Figure 3.1-2. Potential Total CO2 Storage in the CFA.

The AM A is the land area inside the solid line polygon except for the red hashed rectangle.

The MM A extends to dotted red line and includes the red hashed rectangle.

3.2 AMA

The Active Monitoring Area (AMA) is defined by Capture Point's exclusive right to operate
the CFA unitized leases, as described in the INTRODUCTION and Section 2.2.1. Currently,
CapturePoint's operations are focused on the western portion of the CU and the entire NPU.
However, it is anticipated as time passes, or additional C02 volumes become available
additional areas within the CFA may be developed. Additional development is driven by the
market price of oil coupled with the availability of sufficient C02 volumes and thus the
timing of additional development is uncertain at this time. As C02 injection operations are
expanded beyond the currently active C02 EOR portion of the CFA, all additional C02
injection wells will be permitted under the UIC program and will be included in the annual
submittal per 40 CFR 98.446(f)(13). All future C02 injection wells permitted will be within the
AMA.

Therefore, for the purposes of this MRV plan, CapturePoint is continuously monitoring the
entire CFA, which is the AMA.

-------
4 Identification and Evaluation of Leakage Pathways

4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

-------






















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4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

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4.2.3 Production Wells

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

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4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

At the CFA, the work done at the Farnsworth Unit is analagous, where small aperture
fractures were noted but not common in most of the reservoir cores examined but most of
these fractures appear to be drilling induced. Fractures in the Thirteen Finger limestone
caprock were described using an industry-standard format for fracture class type,
orientation, fracture dip, type of mineral fill, fracture porosity, fracture spacing, and
intensity. Again, drilling induced fractures are most common. Natural mineral-filled fractures
are quite rare, were formed during diagenesis at shallow depths, and are of late
Carboniferous age. Unless significantly damaged by large changes in reservoir pressure, they
are highly unlikely to provide migration pathways.

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4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates, and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight
rocks, and mercury injection porosimetry, which is also known as mercury injection capillary
pressure (MICP). Geomechanical analysis involved a standard series of mechanical tests:
Brazil tension, unconfined compression, triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone layers
are strong but brittle, while the shale layers are weaker but sufficiently ductile to prevent
extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint
has strategies for leak detection in place that are discussed in Section 4.5 and the strategy to
quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

-------
waterflood operations were initiated in 1969 implies the area is not seismically sensitive to
injection. Also, no documentation exists that any of the distant earthquake events caused a
disruption in injectivity or damage to any of the wellbores in CFA.

SO km
SO mi

Lubbock

a

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

Liberal

Q

*

o

Dodge City

£

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02
to the surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,

29

-------
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02 Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will use
Subpart W techniques to estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven leakage quantification
reported in Subpart RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

30

-------
Any volume of C02 detected leaking to the surface will be quantified using acceptable
emission factors such as those found in 40 CFR Part 98 Subpart W or engineering estimates
of leak amounts based on measurements in the subsurface, CapturePoint's field experience,
and other factors such as the frequency of inspection. As indicated in Section 6.4, leaks will
be documented, and the records of leakage events will be retained in the electronic
environmental documentation and reporting system, which consists of reports stored on
servers, with information uploaded into third party software.

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02
values for soil measurement in the CFA area, per the characterization, monitoring and well data
collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous
Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration of
C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of
fluid leakage has been identified from any of these in the CFA area. CapturePoint is unlikely
to continue monitoring USDW wells for C02 or brine contamination, as characterization of
the Morrow (see section 5.1) has suggested minimal risk of groundwater contamination
from C02 leakage from this depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

-------
5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

5.5 Well Surveillance

CapturePoint adheres to the requirements of OAC Title 165:10-5 for the OCC and of TAC
Rule 46 for the TRRC governing fluid injection into productive reservoirs. Rule 46 includes
requirements for monitoring, reporting, and testing of Class II injection wells. Furthermore,
the OCC and the TRRC rules include special conditions regarding monitoring, reporting, and
testing in the individual permits for each injection well if they are deemed necessary.

CapturePoint also adheres to the requirements of OAC Title 165:10-7 for the OCC and TAC
Rule 20 for the TRRC governing the notification of fires, breaks, leaks, or escapes. Rule 20
requires that all operators report leaks to the OCC or the TRRC including measured or
estimated quantities of product leaked.

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the
Arkalon Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02from its production
wells in the CFA.

C02T,r = Ep=i {Qr,p - sr,p) *D* CCo2vr (Equation RR-2)
where:

C02r,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

-------
6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02m = £p=i Qpu *D* Cc02pu (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3	Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in
the CFA. Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9
below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

-------
Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations.

CapturePoint will calculate the total annual mass of C02 emitted from all leakage pathways
in accordance with the procedure specified in Equation RR-10 below:

C02E = Yfx=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.

C02 x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural
gas.

C02 = C02I — C02P — C02E — C02FI — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the
reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

34

-------
C02e = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting
year.

C02fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

C02pp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the
collection of emissions data includes the following:

•	Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

•	Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

•	Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1 General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02
quantity will be conducted according to an appropriate standard method published by a
consensus-based standards organization or an industry standard practice such as the Gas
Producers Association (GSA) standards.

Measurement of CO? Volume - All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

35

-------
8.1.2 C02 Received

8.1.3 CO2 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

8.1.5 CO2 Emissions from equipment leaks and vented emissions of CO2

As required by 98.444 (d), CapturePoint will follow the monitoring and QA/QC requirements
specified in Subpart W of the GHGRP for equipment located on the surface between the
flow meter used to measure injection quantity and the injection wellhead and between the
flow meter used to measure production quantity and the production wellhead.

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations. The default emission factors for production equipment are applied to the
carbon capture utilization and storage (CCUS) injection operations reporting under Subpart
RR.

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

• All measurement devices are operated according to an appropriate standard method
published by a consensus-based standards organization 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 Gas Producers Association (GPA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and
the North American Energy Standards Board (NAESB).

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

-------
8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP,
as required in the development of this MRV plan under Subpart RR. Any measurement
devices used to acquire data will be operated and maintained according to the relevant
industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR
98.445 of Subpart RR of the GHGRP, as required.

A quarterly flow rate of C02 received that is missing would be estimated using invoices or
using a representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated
using invoices or using a representative concentration value from the nearest previous time
period.

A quarterly quantity of C02 injected that is missing would be estimated using a
representative quantity of C02 injected from the nearest previous period of time at a similar
injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions of
C02 from surface equipment at the facility that are reported in this subpart, missing data
estimation procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing
would be estimated using a representative quantity of C02 produced from the nearest
previous period of time.

8.4	Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures
for the maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

37

-------
9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

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10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

o
u

1

0

CU 2173

35007354140000

Oi

Prod

Active

co2

1

0

CU 2177

35007222340000

Oi

Prod

Active

o
u

1

0

CU 2272

35007224530000

Oi

Prod

Active

co2

1

0

CU 2651

35007362650000

Oi

Prod

Active

o
u

1

0

CU 2731

35007359750000

Oi

Prod

Active

co2

1

0

CU 2761

35007350590000

Oi

Prod

Active

o
u

1

0

CU 2853

35007250840000

Oi

Prod

Active

co2

1

0

CU 2854

35007250850000

Oi

Prod

Active

o
u

1

0

CU 2971A

35007256700000

Oi

Prod

Active

co2

1

0

CU 2973

35007213750000

Oi

Prod

Active

o
u

1

0

CU 2975

35007223730000

Oi

Prod

Active

co2

1

0

CU 3111

35007350600000

Oi

Prod

Active

o
u

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

o
u

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

o
u

1

0

CU 3171

35007359600000

Oi

Prod

Active

o
u

1

0

CU 3182

35007249250000

Oi

Prod

Active

o
u

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

o
u

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

o
u

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

o
u

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

-------
Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

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49

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Publishing, 2016. 10116887.

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Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
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Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

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Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

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compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

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Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

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Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

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Foundation under award no. 0234594.)

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Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

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Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

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Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

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Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
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history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
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G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
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(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

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Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

CFR - Code of Federal Regulations

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

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NIST - National Institute of Standards and Technology

NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

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Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas-The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

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Request for Additional Information: Camrick Unit
September 1, 2022

Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references, or
supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.

1

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No.

MRV Plar
Section

Page

EPA Questions

Responses

1.

3.1

19

Per 40 CFR 98.449, "Maximum monitoring area (MMA) 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."

In the Request for Additional Information (RFAI) sent on August 11, 2022, EPA requested that
the MRV plan more clearly identify the boundaries of the MMA and explain how the delineation
of the MMA in the MRV plan meets the definition in 40 CFR 98.449.

While the proposed MMA may account for the free phase CO2 plume of the current project,
we seek clarification regarding possible future expansion of the project. Section 3.1 of the MRV
plan states that CO2 storage pore space is available, and Figure 3.1-2 shows pore space within
the western portion of the Camrick Unit and the NPU. However, in reference to Figure 3.1-2,
Section 3.1.1 of the MRV plan states, "This assumed that only 78 percent of the average
injection pattern area or 80 acres could be filled. There are 49 injectors identified for further
injection that have room for an additional 90 Bscf of CO; storage volume or 140 Bscf total
storage."

Neither the discussion nor the figure provides specific details regarding the expansion into
other portions of the CFA which is mentioned in Section 3.2. In addition, it is not clear whether
the current MMA includes storage of the additional 90 Bscf to be created by the 49 injectors. If
the intent is to include CO2 stored through the 49 injection wells, this should be clarified in the
description of the MMA to confirm that the existing facility boundary will contain all stabilized
CO2 plumes from current and future injection wells and the boundary of the MMA will meet
the half-mile buffer requirement.

In the MRV plan, please expand upon any future injection plans in the CFA and explain whether
the MMA accommodates them. If applicable, the diagrams in Section 3 should show the extent
of the modeled plumes and the discussion in Section 3.1 should be consistent with Section 2.1.2
of the Project Description which presents the estimated volume of CO2 to be injected.

Lastly, please note that per 40 CFR 98.448(d)(1), changes in the volume of CO2 injected can
warrant a revision to your MRV plan. We recommend ensuring that this MRV plan accounts for
the different injection scenarios you may encounter.

Section 3.1.2 describes plume
containment as "the site characterization
and stratigraphic trapping of the Morrow
did not reveal any leakage pathways that
would allow free-phase CO2 to migrate
laterally thereby warranting a buffer
zone greater than one-half mile."

Changed and added 'The volumetric
storage capacity calculated for the 49
patterns identified for continued
injection indicates an additional 90 Bscf
of CO2 can be stored and with 50 Bscf
already stored results in 140 Bscf of total
storage. With the anticipated 12 MMCFD
rate of purchased C02, this storage
volume will only be 60 percent utilized."

Added "Areas that do not have CO2
storage posted on Figure 3.1-2 will be
evaluated if existing CO2 injection
operations experience any rate
restriction or develop any operational
issues in the future. If necessary,
replacement wells or additional injection
locations in inactive areas of the CFA will
be drilled or activated. This will be
accomplished by utilizing existing
plugged and abandoned wells or
redrilling old locations as described in
Section 3.2."

2

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2.

3.2

Per 40 CFR 98.449, "Active monitoring area" (AMA) 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.

Section 3.2 is the only section that addresses the AMA and states, "Currently, CapturePoint's
operations are focused on the western portion of the CD (Camrick Unit) and all of the NPU
(North Perryton Unit). However, it is anticipated as the project develops, additional activity will
occur in the NWCU (Northwest Camrick Unit) of the CFA (Camrick Field Area). However, project
development is driven by the market price of oil so CapturePoint is unable to provide a specific
time in the future when the eastern portion of the CFA will be developed. Therefore, for the
purposes of this MRV plan, CapturePoint is continuously monitoring the entire CFA, which is the
AMA."

Although Section 3.2 states that the CFA is the AMA, there is no explanation or rationale for this
decision. Please ensure that the discussion in section 3.2 clearly identifies the AMA boundaries,
describes how the AMA for the CFA presented in the MRV plan conforms to the definition of
the AMA in 40 CFR 98.449, and describes how the delineation of the AMA in the MRV plan
meets the requirements in 40 CFR 98.448(a)(1).

Reworded, "The Active Monitoring Area
(AMA) is defined by CapturePoint's
exclusive right to operate the CFA
unitized leases, as described in the
INTRODUCTION and Section 2.2.1.
Currently, CapturePoint's operations are
focused on the western portion of the CU
and the entire NPU. However, it is
anticipated as time passes, or additional
CO2 volumes become available
additional areas within the CFA may be
developed. Additional development is
driven by the market price of oil coupled
with the availability of sufficient CO2
volumes and thus the timing of additional
development is uncertain at this time. As
CO2 injection operations are expanded
beyond the currently active CO2 EOR
portion of the CFA, all additional CO2
injection wells will be permitted under
the UIC program and will be included in
the annual submittal per 40 CFR
98.446(f)(13). All future CO2 injection
wells permitted will be within the AMA."

Additionally, corrected some grammar.

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Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	21

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	32

5.5	Well Surveillance	32

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	33

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	35

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	36

8.1.3	CO2 Injected	36

8.1.4	CO2 Produced	36

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	37

8.3	Estimating missing data	37

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program
(GHGRP) for the purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue
Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

-------
Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood had reported under Greenhouse Gas Reporting Program Identification
number 544678 and the NPU C02 Flood had reported under Greenhouse Gas Reporting
Program Identification number 544679. The EPA has been notified that the NPU will not be
reporting for 2022, and that the facility has been merged into the Camrick Unit Facility
Identification number 544678.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through
165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules
under OAC 165:5-7-29, and other governing filing forms. Also, the TRRC has issued UIC Class
II enhanced recovery permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the
CFA, including both injection and production wells, are regulated by the OCC and the TRRC,
which have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

-------
injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

-------
Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

-------
OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of C02
produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's
performance by separating and metering oil, gas, and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

-------
CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

-------
CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

-------
Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from the
Regulators and allow consideration of the suitability of the cement based on the use of
the well, the location, and setting of plugs.

2.4 Reservoir Characterization

-------
(Lower Right) Thickness map of Morrow sands.

15

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Fermentation Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

-------
Camrick Field Area Purchase vs Time

120

100

8 60
m

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Fermentation Volume.

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than
the area expected to contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. The purchase volumes that are
displayed in Figure 2.4-6 were mapped and are displayed in Section 3.1.1 indicates that C02
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Figure 3.1-1 displays wells that have C02 retention on the 4,800 acres that have been under
EOR injection in the CFA since project initialization. The volume of the oil recovered since
August 1955, resulted in a voidage space of 36 MMscf of C02 per acre of surface area that
was later filled with water during waterflood. The average decimal fraction of C02 injection
to hydrocarbon pore volume left in the ground after accounting for C02 production through
2021 is 0.29. The lateral extent of C02 in the injection zone or the C02 storage radius for
each well was estimated based on cumulative C02 injected times the decimal fraction of C02
remaining divided by the voidage space. The largest C02 storage areas are around wells that
injected C02 for the most years.

Ferm entatio n
C02

-------
Figure 3.1-2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres could be filled. There are 49 injectors identified for further injection that
have room for an additional 90 Bscf of C02 storage volume or 140 Bscf total storage.

CapturePoint LLC
CAM RICK

L



C02 Retention Storage
5,000

Figure 3.1-1. Estimated C02 storage as of2021 in CFA.

The AM A is the land area inside the solid line polygon except for the red hashed rectangle.
The MMA extends to dotted red line and includes the red hashed rectangle.

20

-------




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3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization of the Morrow did not
reveal any leakage pathways that would allow free-phase C02 to migrate laterally thereby
warranting a buffer zone greater than one-half mile.

3.2 AMA

Currently, CapturePoint's operations are focused on the western portion of the CU and all of
the NPU. However, it is anticipated as the project develops, additional activity will occur in
the NWCU of the CFA. However, project development is driven by the market price of oil so
CapturePoint is unable to provide a specific time in the future when the eastern portion of
the CFA will be developed. Therefore, for the purposes of this MRV plan, CapturePoint is
continuously monitoring the entire CFA, which is the AMA.

4 Identification and Evaluation of Leakage Pathways

Since its discovery in 1955, the unitization of the different units from 1969 to 1972, and the
commencement of C02 EOR in 2001; the CFA is an analogous field to the Farnsworth Unit, which has
undergone extensive investigation and documentation as indicated in Section 2. From this body of work,
CapturePoint has identified the following potential pathways of C02 leakage to the surface. This section
will also address detection, verification, and quantification of leakage from each pathway.

21

-------
4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

-------






















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4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

-------
4.2.3 Production Wells

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

-------
4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

-------
4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates, and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight
rocks, and mercury injection porosimetry, which is also known as mercury injection capillary
pressure (MICP). Geomechanical analysis involved a standard series of mechanical tests:
Brazil tension, unconfined compression, triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone layers
are strong but brittle, while the shale layers are weaker but sufficiently ductile to prevent
extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint
has strategies for leak detection in place that are discussed in Section 4.5 and the strategy to
quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

-------
waterflood operations were initiated in 1969 implies the area is not seismically sensitive to
injection. Also, no documentation exists that any of the distant earthquake events caused a
disruption in injectivity or damage to any of the wellbores in CFA.

SO km
SO mi

Lubbock

a

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

Liberal

Q

*

o

Dodge City

£

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02
to the surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,

29

-------
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will use
Subpart W techniques to estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven leakage quantification
reported in Subpart RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

30

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02
values for soil measurement in the CFA area, per the characterization, monitoring and well data
collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous
Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration of
C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of
fluid leakage has been identified from any of these in the CFA area. CapturePoint is unlikely
to continue monitoring USDW wells for C02 or brine contamination, as characterization of
the Morrow (see section 5.1) has suggested minimal risk of groundwater contamination
from C02 leakage from this depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

-------
5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

5.5 Well Surveillance

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the
Arkalon Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02from its production
wells in the CFA.

C02T,r = Ep=i {Qr,p - sr,p) *D* CCo2vr (Equation RR-2)
where:

C02r,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

-------
6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02m = £p=i Qpu *D* Cc02pu (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3	Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in
the CFA. Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9
below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

-------
Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations.

CapturePoint will calculate the total annual mass of C02 emitted from all leakage pathways
in accordance with the procedure specified in Equation RR-10 below:

C02E = Yfx=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.

C02 x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural
gas.

C02 = C02I — C02P — C02E — C02FI — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the
reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

34

-------
C02e = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting
year.

C02fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

C02pp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the
collection of emissions data includes the following:

•	Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

•	Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

•	Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1 General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02
quantity will be conducted according to an appropriate standard method published by a
consensus-based standards organization or an industry standard practice such as the Gas
Producers Association (GSA) standards.

Measurement of C O? Volume- All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

35

-------
8.1.2 C02 Received

8.1.3 CO2 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

8.1.5 CO2 Emissions from equipment leaks and vented emissions of CO2

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

-------
8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP,
as required in the development of this MRV plan under Subpart RR. Any measurement
devices used to acquire data will be operated and maintained according to the relevant
industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR
98.445 of Subpart RR of the GHGRP, as required.

A quarterly flow rate of C02 received that is missing would be estimated using invoices or
using a representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated
using invoices or using a representative concentration value from the nearest previous time
period.

A quarterly quantity of C02 injected that is missing would be estimated using a
representative quantity of C02 injected from the nearest previous period of time at a similar
injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions of
C02 from surface equipment at the facility that are reported in this subpart, missing data
estimation procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing
would be estimated using a representative quantity of C02 produced from the nearest
previous period of time.

8.4	Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures
for the maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

37

-------
9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

-------
10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

C02

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

C02

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

C02

1

0

CU 2731

35007359750000

Oi

Prod

Active

C02

1

0

CU 2761

35007350590000

Oi

Prod

Active

C02

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

C02

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

C02

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

C02

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

co2

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

co2

1

0

CU 3171

35007359600000

Oi

Prod

Active

co2

1

0

CU 3182

35007249250000

Oi

Prod

Active

co2

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

co2

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

co2

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

co2

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

-------
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stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
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Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

-------
Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

-------
Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
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http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
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Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
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Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

-------
Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

-------
Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

NIST - National Institute of Standards and Technology

-------
NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

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Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas—The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

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Request for Additional Information: Camrick Unit
August 11, 2022

Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references,
or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.

No.

MRV Plan
Section

Page

EPA Questions

Responses

1.

3.1

21

Figure 3.1-1 and Figure 3.1-2 are difficult to follow due to a lack of
clear labels/legends. For example, it is not clear what the outermost
dotted line represents.

We recommend adjusting these legends and/or figures to clearly
delineate the Maximum Monitoring Area (MMA) and the Active
Monitoring Area (AMA).

Adjusted the figures and legends to clearly delineate the Active
Monitoring Area (AMA) and the Maximum Monitoring Area (MMA).

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No.

MRV Plan
Section

Page

EPA Questions

Responses

2.

3

21

Per 40 CFR 98.449, "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 C02 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 C02 plume at the
end of year t + 5. From the discussion in this section, it is not clear
how the delineation of the AMA and the MMA comply with the
definitions for the AMA and MMA in 40 CFR 98.449 or the
requirements to delineate the AMA and MMA in 40 CFR
98.448(a)(1).

Per 40 CFR 98.449, "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 C02 plume until the C02 plume has stabilized plus an all-
around buffer zone of at least one-half mile.

Please ensure that the discussion in sections 3.1 and 3.2 clearly
identifies the AMA and MMA boundaries. Furthermore, please
explain in the MRV plan whether the AMA and MMA conform to
the definitions above.

These items were addressed in Section 2.1, Section 2.4, Section3 .1
and in the correction described in the answer to EPA Question 1
(previous page).

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No.

MRV Plan
Section

Page

EPA Questions

Responses

3.

3

21

"Currently, CapturePoint's operations are focused on the western
portion of the CFA. However, it is anticipated as the project
develops, additional activity will occur in the NWOJ of the CFA;
therefore, requiring active monitoring in that area. However,
project development is driven by the market price of oil so
CapturePoint is unable to provide a specific time in the future when
the eastern portion of the CFA will be actively monitored.
Therefore, for the purposes of this MRV plan, CapturePoint has
chosen to include the entire CFA in the AIVIA,"

It is unclear whether CapturePoint intends to monitor the eastern
portion of the CFA or include it in the AMA. Similarly, it is also
unclear if CapturePoint anticipates that the western portion or the
eastern portion of the CFA will encounter additional activity. Please
update the MRV plan to clarify this section. Furthermore, please
note that 40 CFR 98.448(d) contains requirements for resubmitting
an MRV plan if there are material changes, such as a change to the
Active Monitoring Area.

Reworded.

"Currently, CapturePoint's operations are focused on the western
portion of the CU and all of the NPU. However, it is anticipated as
the project develops, additional activity will occur in the NWCU of
the CFA. However, project development is driven by the market
price of oil so CapturePoint is unable to provide a specific time in
the future when the eastern portion of the CFA will be developed.
Therefore, for the purposes of this MRV plan, CapturePoint is
continuously monitoring the entire CFA, which is the AMA."

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Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	21

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	32

5.5	Well Surveillance	32

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	33

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	35

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	36

8.1.3	CO2 Injected	36

8.1.4	CO2 Produced	36

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	37

8.3	Estimating missing data	37

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program
(GHGRP) for the purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue
Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

-------
Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood had reported under Greenhouse Gas Reporting Program Identification
number 544678 and the NPU C02 Flood had reported under Greenhouse Gas Reporting
Program Identification number 544679. The EPA has been notified that the NPU will not be
reporting for 2022, and that the facility has been merged into the Camrick Unit Facility
Identification number 544678.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through
165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules
under OAC 165:5-7-29, and other governing filing forms. Also, the TRRC has issued UIC Class
II enhanced recovery permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the
CFA, including both injection and production wells, are regulated by the OCC and the TRRC,
which have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

-------
injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

-------
Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

-------
System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

-------
OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of C02
produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's
performance by separating and metering oil, gas, and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

-------
CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

-------
CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

-------
Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from the
Regulators and allow consideration of the suitability of the cement based on the use of
the well, the location, and setting of plugs.

2.4 Reservoir Characterization

-------
(Lower Right) Thickness map of Morrow sands.

15

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Fermentation Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

-------
Camrick Field Area Purchase vs Time

120

100

8 60
m

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Fermentation Volume.

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than
the area expected to contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. The purchase volumes that are
displayed in Figure 2.4-6 were mapped and are displayed in Section 3.1.1 indicates that C02
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Ferm entatio n
C02

-------
Figure 3.1-2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres could be filled. There are 49 injectors identified for further injection that
have room for an additional 90 Bscf of C02 storage volume or 140 Bscf total storage.

r ~ " i

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-v—

CapturePoint LLC

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C02 Retention Storage

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Figure 3.1-1. Estimated C02 storage as of2021 in CFA.

20

-------
CapturePoint LLC

CAMRICK

C02 Potential Storage

5.000 10,000

FEET

5 § S Z S S Si t

Figure 3.1-2. Potential Total CO2 Storage in the CFA.

3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization of the Morrow did not
reveal any leakage pathways that would allow free-phase C02 to migrate laterally thereby
warranting a buffer zone greater than one-half mile.

3.2 AMA

Currently, CapturePoint's operations are focused on the western portion of the CFA.
However, it is anticipated as the project develops, additional activity will occur in the NWCU
of the CFA; therefore, requiring active monitoring in that area. However, project
development is driven by the market price of oil so CapturePoint is unable to provide a
specific time in the future when the eastern portion of the CFA will be actively monitored.
Therefore, for the purposes of this MRV plan, CapturePoint has chosen to include the entire
CFA in the AMA.

4 Identification and Evaluation of Leakage Pathways

-------
4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

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Figure 4.2-1. Plugged and Abandoned Wells in the CFA.

4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

-------
4.2.3 Production Wells

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

-------
4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

-------
4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates, and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight
rocks, and mercury injection porosimetry, which is also known as mercury injection capillary
pressure (MICP). Geomechanical analysis involved a standard series of mechanical tests:
Brazil tension, unconfined compression, triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone layers
are strong but brittle, while the shale layers are weaker but sufficiently ductile to prevent
extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint
has strategies for leak detection in place that are discussed in Section 4.5 and the strategy to
quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

-------
waterflood operations were initiated in 1969 implies the area is not seismically sensitive to
injection. Also, no documentation exists that any of the distant earthquake events caused a
disruption in injectivity or damage to any of the wellbores in CFA.

SO km
SO mi

Lubbock

a

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

Liberal

Q

*

o

Dodge City

£

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02
to the surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,

29

-------
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will use
Subpart W techniques to estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven leakage quantification
reported in Subpart RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

30

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02
values for soil measurement in the CFA area, per the characterization, monitoring and well data
collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous
Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration of
C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of
fluid leakage has been identified from any of these in the CFA area. CapturePoint is unlikely
to continue monitoring USDW wells for C02 or brine contamination, as characterization of
the Morrow (see section 5.1) has suggested minimal risk of groundwater contamination
from C02 leakage from this depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

-------
5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

5.5 Well Surveillance

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the
Arkalon Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02from its production
wells in the CFA.

C02T,r = Ep=i {Qr,p - sr,p) *D* CCo2vr (Equation RR-2)
where:

C02r,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

-------
6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02m = £p=i Qpu *D* Cc02pu (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3	Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in
the CFA. Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9
below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

-------
Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations.

CapturePoint will calculate the total annual mass of C02 emitted from all leakage pathways
in accordance with the procedure specified in Equation RR-10 below:

C02E = Yfx=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.

C02 x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural
gas.

C02 = C02I — C02P — C02E — C02FI — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the
reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

34

-------
C02e = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting
year.

C02fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

C02pp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the
collection of emissions data includes the following:

•	Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

•	Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

•	Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1 General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02
quantity will be conducted according to an appropriate standard method published by a
consensus-based standards organization or an industry standard practice such as the Gas
Producers Association (GSA) standards.

Measurement of C O? Volume- All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

35

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8.1.2 C02 Received

8.1.3 CO2 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

8.1.5 CO2 Emissions from equipment leaks and vented emissions of CO2

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

-------
8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP,
as required in the development of this MRV plan under Subpart RR. Any measurement
devices used to acquire data will be operated and maintained according to the relevant
industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR
98.445 of Subpart RR of the GHGRP, as required.

A quarterly flow rate of C02 received that is missing would be estimated using invoices or
using a representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated
using invoices or using a representative concentration value from the nearest previous time
period.

A quarterly quantity of C02 injected that is missing would be estimated using a
representative quantity of C02 injected from the nearest previous period of time at a similar
injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions of
C02 from surface equipment at the facility that are reported in this subpart, missing data
estimation procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing
would be estimated using a representative quantity of C02 produced from the nearest
previous period of time.

8.4	Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures
for the maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

37

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9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

-------
10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

C02

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

C02

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

C02

1

0

CU 2731

35007359750000

Oi

Prod

Active

C02

1

0

CU 2761

35007350590000

Oi

Prod

Active

C02

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

C02

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

C02

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

C02

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

co2

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

co2

1

0

CU 3171

35007359600000

Oi

Prod

Active

co2

1

0

CU 3182

35007249250000

Oi

Prod

Active

co2

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

co2

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

co2

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

co2

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

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Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

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Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

-------
Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

-------
Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

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Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

-------
Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

NIST - National Institute of Standards and Technology

-------
NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

-------
Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas—The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

-------
Request for Additional Information: Camrick Unit
July 13, 2022

Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references,
or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.

No.

MRV Plan

EPA Questions |Responses

Section

Page

4.2.3

Original EPA Question

"Once EOR operations commence, the energy content of the produced gas drops and
cannot be sold; therefore, no gas wells are identified."

Can you please clarify whether there are gas wells in the CFA and if they are identified
in any section of the MRV plan? Even if the gas is not marketable, any gas wells could
be source of potential leakage/emissions. Please update the MRV Plan as necessary.

Camrick Unit Response:

Changed "no gas wells are identified" to "any inactive gas wells are reclassified to
either oil producer or WAG injector".

New EPA Question:

In the MRV plan, please clarify what actions will be taken to convert inactive gas wells
to become an oil producer or WAG injector. Would this be a reclassification in name, or
would well conversion or workover take place? Would the wells be assumed to have
the same potential leakage characteristics, monitoring activities, and quantification of
leakage as others already identified in the MRV plan? Please describe how these wells
may differ from others in the plan and what actions will be taken to monitor and
quantify potential leakage.

Added... "Some of the original field wells drilled
as oil wells were reclassified, administratively, to
gas wells per OAC Title 165:10-1-6 paragraph (d),
because of the gas-oil ratio growth due to
reservoir depletion. Hence, there is no difference
in well construction as described in Section 2.3.6.
As the field is being further developed for
enhanced oil recovery, these gas wells have been
reclassified to oil wells per OCC regulations and
will be monitored for leakage as described in
Section 4.7."

Changed... "are reclassified to either oil producer
or WAG injector." ...to... "are either reclassified
to oil producers, or activated to WAG injectors,
as described earlier. (See Section 4.2.2)"

Please see Attached Appendix for
supplemental information

-------
Appendix:

In MRV Section 2.3.6, Well Operation and Permitting, in Oklahoma, requires adhering to OCC regulations for such operations of oil and gas wells. The resulting wells
will have the same potential leakage characteristics, monitoring activities, and quantification of leakage as any well already identified. The MRV Section 4.7, Strategy
for Detection and Response to C02 Loss, will apply directly to these well reclassifications.

The three OCC regulations for Form 1002A referenced in the answer above are listed as follows.

"OAC Title 165:10-1-6. Duties and authority of the Conservation Division"

(d) The Director of the Conservation Division may administratively reclassify a well according to the gas-oil ratio as specified in 165:10-13-2 if the retesting of a well
pursuant to this Section indicates a change in the original gas-oil ratio.

"OAC Title 165:10-13-2. Classification of wells for allowable purposes"

(a) For purposes of this Subchapter the terms gas, oil, and gas-oil ratio are defined in 165:10-1-2.

(b) Any well having a gas-oil ratio of 15,000 to one or more shall be classified as a gas well for allowable purposes.

"OAC Title 165:10-15-7. Procedure for obtaining discovery allowable"

(c) If a gas well in a discovery oil pool is reclassified as an oil well for allowable purposes, the operator must file the appropriate form, information and material
specified in (a) of this Section within 30 days of reclassifying the well to obtain a discovery allowable. The allowable shall be effective the date the well was reclassified
as an oil well as indicated on Form 1002A.

-------
Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	21

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

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4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	32

5.5	Well Surveillance	32

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	33

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	35

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	36

8.1.3	CO2 Injected	36

8.1.4	CO2 Produced	36

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	37

8.3	Estimating missing data	37

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program
(GHGRP) for the purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue
Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

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Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood had reported under Greenhouse Gas Reporting Program Identification
number 544678 and the NPU C02 Flood had reported under Greenhouse Gas Reporting
Program Identification number 544679. The EPA has been notified that the NPU will not be
reporting for 2022, and that the facility has been merged into the Camrick Unit Facility
Identification number 544678.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through
165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules
under OAC 165:5-7-29, and other governing filing forms. Also, the TRRC has issued UIC Class
II enhanced recovery permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the
CFA, including both injection and production wells, are regulated by the OCC and the TRRC,
which have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02

-------
injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4-6)

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

-------
Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

-------
OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2-3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of C02
produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's
performance by separating and metering oil, gas, and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

-------
CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

-------
CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

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Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from the
Regulators and allow consideration of the suitability of the cement based on the use of
the well, the location, and setting of plugs.

2.4 Reservoir Characterization

-------
(Lower Right) Thickness map of Morrow sands.

15

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-2. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-3. Dimensionless curves for C02 injection (left) with rate time curves (right).

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-4. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4-5)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-5. Dimensionless C02 Fermentation Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4-6).

18

-------
Camrick Field Area Purchase vs Time

120

100

8 60
m

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-6. C02 Fermentation Volume.

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than
the area expected to contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. The purchase volumes that are
displayed in Figure 2.4-6 were mapped and are displayed in Section 3.1.1 indicates that C02
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Ferm entatio n
C02

-------
Figure 3.1-2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres could be filled. There are 49 injectors identified for further injection that
have room for an additional 90 Bscf of C02 storage volume or 140 Bscf total storage.

r ~ " i

| NVreAMRICKUNiTl

' -I

Jr

K J MIT

-v—

CapturePoint LLC

CAMRICK

C02 Retention Storage

5.000	10,000

FEET

"L,

^ ;

.i •



I N PERRYTON UNIT

Figure 3.1-1. Estimated C02 storage as of2021 in CFA.

20

-------
CapturePoint LLC

CAMRICK

C02 Potential Storage

5.000 10,000

FEET

5 § S Z S S Si t

Figure 3.1-2. Potential Total CO2 Storage in the CFA.

3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization of the Morrow did not
reveal any leakage pathways that would allow free-phase C02 to migrate laterally thereby
warranting a buffer zone greater than one-half mile.

3.2 AMA

4 Identification and Evaluation of Leakage Pathways

-------
4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

-------






















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Figure 4.2-1. Plugged and Abandoned Wells in the CFA.

4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

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4.2.3 Production Wells

Figure 4.2-3 shows the active oil production wells in the CFA. Once EOR operations
commence, the energy content of the produced gas drops and cannot be sold; therefore,
any inactive gas wells are reclassified to either oil producer or WAG injector. However, as
the project develops in the CFA additional production wells may be added and will be
constructed according to the relevant rules of the OCC and the TRRC. Additionally, inactive
wells may become active according to the rules of the OCC and the TRRC.

During production, oil, gas, and water flow from the reservoir into the wellbore. This flow is
caused by a differential pressure where the bottom hole wellbore pressure is less than the
reservoir pressure. These lower pressure fluids, which also contains C02, are contained by
the casing, tubing, wellhead, and flowline all the way to the CTB. CapturePoint concludes
that leakage of C02 to the surface through production wells is unlikely.

24

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate the reservoir from the surface. The wellhead pressures are then
checked per operation schedule for any change. CapturePoint concludes that leakage of C02
to the surface through inactive wells is unlikely.

25

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4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

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4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates, and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight
rocks, and mercury injection porosimetry, which is also known as mercury injection capillary
pressure (MICP). Geomechanical analysis involved a standard series of mechanical tests:
Brazil tension, unconfined compression, triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone layers
are strong but brittle, while the shale layers are weaker but sufficiently ductile to prevent
extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint
has strategies for leak detection in place that are discussed in Section 4.5 and the strategy to
quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

-------
waterflood operations were initiated in 1969 implies the area is not seismically sensitive to
injection. Also, no documentation exists that any of the distant earthquake events caused a
disruption in injectivity or damage to any of the wellbores in CFA.

SO km
SO mi

Lubbock

a

Figure 4.6-1. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

Liberal

Q

*

o

Dodge City

£

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02
to the surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,

29

-------
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will use
Subpart W techniques to estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven leakage quantification
reported in Subpart RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

30

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02
values for soil measurement in the CFA area, per the characterization, monitoring and well data
collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous
Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration of
C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of
fluid leakage has been identified from any of these in the CFA area. CapturePoint is unlikely
to continue monitoring USDW wells for C02 or brine contamination, as characterization of
the Morrow (see section 5.1) has suggested minimal risk of groundwater contamination
from C02 leakage from this depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

-------
5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

5.5 Well Surveillance

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the
Arkalon Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02from its production
wells in the CFA.

C02T,r = Ep=i {Qr,p - sr,p) *D* CCo2vr (Equation RR-2)
where:

C02r,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

-------
6.2	Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02m = £p=i Qpu *D* Cc02pu (Equation RR-5)
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3	Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in
the CFA. Therefore, the following equation is relevant to its operations.

C02,w = £p=i QP,W *D* CCo2vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9
below:

C02P = (1 + X) * Y,w=i C02,w (Equation RR-9)

-------
Where:

C02p = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations.

CapturePoint will calculate the total annual mass of C02 emitted from all leakage pathways
in accordance with the procedure specified in Equation RR-10 below:

C02E = Yfx=iC02iX (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.

C02 x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural
gas.

C02 = C02I — C02P — C02E — C02FI — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the
reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

34

-------
C02e = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting
year.

C02fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

C02pp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, September 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the
collection of emissions data includes the following:

•	Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

•	Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

•	Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1 General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02
quantity will be conducted according to an appropriate standard method published by a
consensus-based standards organization or an industry standard practice such as the Gas
Producers Association (GSA) standards.

Measurement of C O? Volume- All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

35

-------
8.1.2 C02 Received

8.1.3 CO2 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

8.1.5 CO2 Emissions from equipment leaks and vented emissions of CO2

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

-------
8.2	QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP,
as required in the development of this MRV plan under Subpart RR. Any measurement
devices used to acquire data will be operated and maintained according to the relevant
industry standards.

8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR
98.445 of Subpart RR of the GHGRP, as required.

A quarterly flow rate of C02 received that is missing would be estimated using invoices or
using a representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated
using invoices or using a representative concentration value from the nearest previous time
period.

A quarterly quantity of C02 injected that is missing would be estimated using a
representative quantity of C02 injected from the nearest previous period of time at a similar
injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions of
C02 from surface equipment at the facility that are reported in this subpart, missing data
estimation procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing
would be estimated using a representative quantity of C02 produced from the nearest
previous period of time.

8.4	Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures
for the maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

37

-------
9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

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10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

o
u

1

0

CU 2173

35007354140000

Oi

Prod

Active

co2

1

0

CU 2177

35007222340000

Oi

Prod

Active

o
u

1

0

CU 2272

35007224530000

Oi

Prod

Active

co2

1

0

CU 2651

35007362650000

Oi

Prod

Active

o
u

1

0

CU 2731

35007359750000

Oi

Prod

Active

co2

1

0

CU 2761

35007350590000

Oi

Prod

Active

o
u

1

0

CU 2853

35007250840000

Oi

Prod

Active

co2

1

0

CU 2854

35007250850000

Oi

Prod

Active

o
u

1

0

CU 2971A

35007256700000

Oi

Prod

Active

co2

1

0

CU 2973

35007213750000

Oi

Prod

Active

o
u

1

0

CU 2975

35007223730000

Oi

Prod

Active

co2

1

0

CU 3111

35007350600000

Oi

Prod

Active

o
u

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

o
u

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

o
u

1

0

CU 3171

35007359600000

Oi

Prod

Active

o
u

1

0

CU 3182

35007249250000

Oi

Prod

Active

o
u

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

o
u

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

o
u

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

o
u

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

-------
Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

-------
Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

-------
Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

-------
Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

-------
Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

NIST - National Institute of Standards and Technology

-------
NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

-------
Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas—The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

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Request for Additional Information: Camrick Unit
May 26, 2022

No.

MRV Pic
Section

Page

EPA Questions

Responses

N/A

While the resolution and overall quality of the figures have
increased markedly in this version of the draft MRV plan,
there are now issues with the naming and referencing of
figures throughout the MRV plan.

Specifically, there is an inconsistency in using dashes vs.
dots as separators in the figure names, such as "Figure 2.2-
1" vs. "Figure 2.2.3" Additionally, the MRV plan goes from
"Figure 2.4-1" to "Figure 2.4-4" while still referencing a
now non-existent "Figure 2.4.3" in section 2.4.2 of the
draft MRV plan.

Please review figure numbering and references to figures
in the text and correct these errors.

Corrected figure numbering and references.

2.1.2

"Historical and forecasted cumulative C02 retention
volumes are approximately 100 billion standard cubic feet
(Bscf) or 5.3 million metric tonnes (MMMT) from the start
of C02 injection through October 2034. During the MRV
plan, the period September 2022 through October 2034,
52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See
Figure 2.4.8)"

The beginning date of the time period differs from that
stated in Section 7 which declares November 1, 2022 as
the beginning date. Please clarify and update the MRV
plan as necessary.

Corrected Section 7 to September 1, 2022

-------
No.

MRV Pic
Section

n

Page

EPA Questions

Responses

3.

2.3.2

11

"Although CapturePoint is not required to determine or
report the amount of dissolved C02 in the water as it is
reinjected into the ground and not emitted to the
atmosphere. The analyses have shown the water typically
contains <690 ppm (0.069%) C02."

The edit to the above phrase has introduced a new
sentence fragment. Replacing the period with a comma
would fix this error.

Corrected sentence fragment by replacing period with a
co mm 3.

4.

4.2.3

24

"Once EOR operations commence, the energy content of
the produced gas drops and cannot be sold; therefore, no
gas wells are identified."

Can you please clarify whether there are gas wells in the
CFA and if they are identified in any section of the MRV
plan? Even if the gas is not marketable, any gas wells could
be source of potential leakage/emissions. Please update
the MRV Plan as necessary.

Changed "no gas wells are identified" to "any inactive gas
wells are reclassified to either oil producer or WAG injector".

5.

4.2.4

25

"Inactive wells have a cast iron bridge plug set or long
cement plugs placed above the existing perforations to
isolate reservoir from the surface."

It appears there is typo in the above phrase with "the"
missing before reservoir. Please correct it.

Added "the" before "reservoir".

6.

4.8

31

"As indicated in Section 6.4, leaks will be documented, and
the records of leakage events will be retained in the
electronic environmental documentation and reporting
system."

Is the electronic documentation and reporting system an
internal system for documenting and reporting leaks?
Please clarify and provide a brief description.

Added the descriptive phrase ", which consists of reports
stored on servers, with information uploaded into third party
software."

-------
No.

MRV Pic
Section

n

Page

EPA Questions

Responses

7.

Email
From:
Melinda
Miller

N/A

"determine whether one or more facilities is represented
by the Camrick Field"

The production reservoir is the same for both units, is
continuous and the facilities and boundaries are contiguous,
however they extend across the Texas and Oklahoma border.
The EPA has been notified through eGGRT that the North
Perryton Unit will not be reporting for 2022, and that the
facility has been merged into the Camrick Unit Facility ID.
Appropriate edits were made to reflect this in the MRV Plan
for Camrick Unit prior to resubmittal.

-------
Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

Point LLC

' I POINT

April 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years ofCC>2 injection	4

2.1.2	Estimated volume ofCC>2 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	CO2 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location, and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	16

2.4.3	CO2 Analogy Field Study	16

2.4.4	CO2 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	19

3.1	MMA	19

3.1.1	Determination of Storage Volumes	19

3.1.2	Determination of Buffer Zone	21

3.2	AMA	21

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAYS	21

4.1	Leakage from Surface Equipment	22

4.2	Leakage from Wells	22

4.2.1	Abandoned Wells	22

4.2.2	Injection Wells	23

4.2.3	Production Wells	24

4.2.4	Inactive Wells	25

4.2.5	New Wells	26

4.3	Leakage from Faults and Bedding Plane Partings	27

4.3.1	Prescence of Hydrocarbons	27

4.3.2	Fracture an alysis	27

4.4	Lateral Fluid Movement	28

4.5	Leakage through Confining/Seal system	28

4.6	Natural and Induced Seismic Activity	28

-------
4.7	Strategy for Detection and Response to CO2 loss	29

4.8	Strategy for Quantifying CO2 loss	30

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	31

5.1	Site Characterization and Monitoring	31

5.2	Groundwater monitoring	31

5.3	Soil CO2 monitoring	31

5.4	Visual Inspection	31

5.5	Well Surveillance	32

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	32

6.1	Determining Mass of CO2 received	32

6.2	Determining Mass of CO2 Injected	32

6.3	Determining Mass of CO2 produced from Oil Wells	33

6.4	Determining Mass of CO2 emitted by Surface Leakage	34

6.5	Determining Mass of CO2 sequestered	34

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	35

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	35

8.1	GHG MONITORING 	35

8.1.1	General	35

8.1.2	CO2 Received	35

8.1.3	CO2 Injected	36

8.1.4	CO2 Produced	36

8.1.5	CO2 Emissions from equipment leaks and vented emissions ofCC>2	36

8.1.6	Measurement Devices	36

8.2	QA/QC procedures	36

8.3	Estimating missing data	37

8.4	Revisions of the MRV plan	37

9	RECORDS RETENTION	38

10	APPENDICES	39

Appendix 1-CFA Wells	39

Appendix 2 - Referenced Regulations	45

Appendix 3 - References	49

Appendix 4 - Abbreviations and Acronyms	53

Appendix5-Conversion Factors	55

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with retention of C02 serving a subsidiary purpose of geologic
sequestration of C02 in a subsurface geologic formation. The CFA was discovered in 1955 and is
composed of three units, the Camrick Unit (CU) that was unitized by Humble Oil Company on October

14,	1969, the North Perryton Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969,
and the Northwest Camrick Unit (NWCU) that was unitized by Atlantic Rich Field Company on September

15,	1972. The Units were formed for the purpose of waterflooding with salt water sourced from the
Wolfcamp formation. The field structure is a lenticular bedding sand trending northwest to southeast
with the average top of sand at 7,250 feet, true vertical depth. CapturePoint has been operating the CFA
since 2017. CapturePoint acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R
project in March 2001 for the CU and January 2007 for the NPU. No C02 has been injected in the NWCU.
CapturePoint intends to continue C02-EOR operations until the end of the economic life of the C02-EOR
program using various Class II injection wells as defined by Underground Injection Control (UIC)
regulations and permitted under Texas Railroad Commission (TRRC) Rule 46 of the Texas Administrative
Code (TAC) and the Oklahoma Corporation Commission (OCC) Title 165:10 of the Oklahoma
Administrative Code (OAC). In this document, the term "gas" means a mixture of hydrocarbon light end
components and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program
(GHGRP) for the purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue
Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin; and a detailed
characterization of the injection reservoir modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449 and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

3

-------
Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood reports under Greenhouse Gas Reporting Program Identification number
544678 and the NPU C02 Flood reports under Greenhouse Gas Reporting Program
Identification number 544679.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OACTitle 165:10-5-1 through
165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30, the request for an exception to UIC rules
under OAC 165:5-7-29, and other governing filing forms. Also, the TRRC has issued UIC Class
II enhanced recovery permits under its Rule 46, TAC Title 16 Part 1 Chapter 3. All wells in the
CFA, including both injection and production wells, are regulated by the OCC and the TRRC,
which have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

The CFA has been injecting C02 for the last 20+ years and it is currently projected that
CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

Historical and forecasted cumulative C02 retention volumes are approximately 100 billion
standard cubic feet (Bscf) or 5.3 million metric tonnes (MMMT) from the start of C02
injection through October 2034. During the MRV plan, the period September 2022 through
October 2034, 52.5 Bscf or 2.77 MMMT will be stored in the CFA. (See Figure 2.4.8)

-------
2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

-------
Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1. Location of the CFA on the Northwest Shelf of the Anadarko Basin in West Texas.
Red lines are approximate locations of faults that have been documented in the region.

6

-------
System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

c
.2

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogshooter

•
(A

Kansas
City

Checkerboard
Cleveland

$
HI
1-

0)
Q.

Marmaton

Oswego

z
<
X

Cherokee Shale

<
o

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

a.
S
«

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2. Stratigraphic section.

Tectonic Setting

-------
OKLAHOMA	North

(panhandle)	KANSAS

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

TEXAS

TERTIARY

SHALLOW
SHELF PROVINCE

0	TO 20 30 40 50 MILES

	1	1 1	I	I	I

Granite wash
Carbonate
\.i Sandstone ~ shale
* Fault

DEEP BASIN PROVINCE

Figure 2.2.3. Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy
Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone. The upper Morrowan facies, with sequences of basal
conglomerate, coarse-grained sandstone, and fine-grained sandstone appear to be typical of
incised valley deposits, as described by Wheeler et al. (1990), Krystinik and Blakeney (1990),
Bowen et al. (1990), Blakeney et al. (1990), Sonnenberg et al. (1990) and Puckette et al.
(2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale both
below and above the sandstone are sharp and irregular. The Morrow shale generally fines
upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

8

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of C02
produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's
performance by separating and metering oil, gas, and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

-------
3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas, and water using a series of vessels and storage tanks.

CTB - Central Tank Battery

High Pressure C02 Injection System

CQ2

Figure 2.3-1. Simplified flow diagram of the facilities arid equipment within the boundaries of the CFA.

The water is transferred from the separation vessels to tanks for reinjection. After the water
is conditioned, it is either reinjected at the WAG skids or disposed of into permitted disposal
wells. Although CapturePoint is not required to determine or report the amount of dissolved
C02 in the water as it is reinjected into the ground and not emitted to the atmosphere. The
analyses have shown the water typically contains <690 ppm (0.069%) C02.

-------
CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of the
H2S detectors is protecting people from the risk of being harmed. The detection limit of the
H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an alarm
above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4, and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

2.3.4 Facilities Locations

-------
CAMRICK - CAMRICK

2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference. This oil is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The OCC and TRRC rules (Appendix 2) govern well location, construction, operation,
maintenance, and plugging for all wells in permitted units and wells. CapturePoint follows
these rules and regulations to maintain safe and efficient operations. This includes
complying with all current and updated information for mechanical integrity testing, well
repairs for injection wells, drilling and completion, permitting, and reporting.

13

-------
Briefly, the following bulleted list is what the current rules require, among other provisions:

• That fluids be constrained in the strata in which they are encountered.

• That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

• That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

• And that all wells follow plugging procedures that require advance approval from the
Regulators and allow consideration of the suitability of the cement based on the use of
the well, the location, and setting of plugs.

2.4 Reservoir Characterization

-------
(Lower Right) Thickness map of Morrow sands.

15

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2.4.2 Reservoir Fluid Modeling
The compositional fluid model was constructed for the CapturePoint operated Farnsworth
Unit. From laboratory compositional analysis an equation of state was tuned (Gunda et al.,
2015). The minimum miscibility pressure (MMP) experiment was then simulated using a
one-dimensional model (Figure 2.4.3). The simulated Farnworth Unit MMP of 4,009 psia
compared to an MMP value of 4,200 psia derived from laboratory experiments provided by
the operator represents a less than 5% error (Gunda et al., 2015).

Oil recovery vs Pressure

Pressure (psia)

Recovery at 168.00 *F

Figure 2.4-4. Oil recovery plot for ID slim tube test for Farnsworth Unit.

2.4.3 CO2 Analogy Field Study

2.4.4 CO2 - EOR Performance Projections

For years, the oil industry has used dimensionless equations to predict the amount of oil
that can be recovered using C02 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The

The CFA has been injecting C02 since March 2001. The dimensionless curves were matched
to historical performance through early 2020 (Figure 2.4.5). The supply of C02 was curtailed
from March 2020 until present, due to oil price uncertainty, and will resume after the
Arkalon Plant upgrade that will be finished in the 4th quarter of 2022.

Camrick/N Perryton Forecast Type Curve

Oil Type Curve

Gas

Gas I vpe Curve
Wat

Wat l vpe Curve

c=>

011 iax|

— — «• Oil Tvpe Curve '

War Type Curve

— — — GssType Cuiw 300

1/1/7001 1/1/7005 1/1/J (TOT 1/1/7013 1/1/7017 t/1/2f»1 1/1/7075 1/1/70M 1/1/7033 1/1/7037

Figure 2.4-5. Dimensionless curves for C02 injection (left) with rate time curves (right).

The dimensionless water oil ratio and the gas oil ratio trends (Figure 2.4.6) for the CFA
flooded acreage are very similar to what was forecasted by simulation in the Farnsworth
Field as expected because of the porosity, permeability, and sand similarities.

too

Camrick/N Perryton Forecast Type Curve

GOR Type Ounff.

_«• n

wc...'*'

WWC" Type Ctiive

1/1/2001

1/VZ005

1/1/2009 1/1/2013 1/1/201/ 1/1/2021 1/1/2025

1/1/2029 1/1/2033 1/1/2037

Figure 2.4-6. Dimensionless water cut and GOR vs. observed EOR data.

-------
The C02 storage volumes for Arkalon fermentation C02 were also forecasted (Figure 2.4.7)
using the same dimensionless technique. This technique indicates that the flooded acreage
still has significant additional storage potential. The maximum C02 storage is limited to the
amount of space available by the removal of the produced hydrocarbon. The projection
indicates that there is pore space available to store approximately 0.4 to 0.5 decimal
fraction of HPV amounting to 30 to 40 MMB.

Figure 2.4-7. Dimensionless C02 Fermentation Curves

The barrels of reservoir volume were converted to standard cubic feet of gas and is
displayed in the CFA Purchase C02, or Fermentation C02, vs Time chart (Figure 2.4.8).

18

-------
Camrick Field Area Purchase vs Time

120

100

8 60
m

40
20
0

Jan-22 Jan-26 Jan-30 Jan-34 Jan-38

Figure 2.4-8. C02 Fermentation Volume.

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is equal to or greater than
the area expected to contain the free phase C02 plume until the C02 plume has stabilized
plus an all-around buffer zone of at least one-half mile. The purchase volumes that are
displayed in figure 2.4.7 were mapped and are displayed in Section 3.1.1 indicates that C02
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Ferm entatio n
C02

-------
Figure 3.1.2 displays the potential area of the reservoir that can be filled with C02 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres could be filled. There are 49 injectors identified for further injection that
have room for an additional 90 Bscf of C02 storage volume or 140 Bscf total storage.

r ~ " i

| NVreAMRICKUNiTl

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-v—

CapturePoint LLC

CAMRICK

C02 Retention Storage

5.000	10,000

FEET

"L,

^ ;

.i •



I N PERRYTON UNIT

Figure 3.1.1. Estimated C02 storage as of2021 in CFA.

20

-------
CapturePoint LLC

CAMRICK

C02 Potential Storage

5.000 10,000

FEET

5 § S Z S S Si t

Figure 3.1.2. Potential Total CO2 Storage in the CFA.

3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization of the Morrow did not
reveal any leakage pathways that would allow free-phase C02 to migrate laterally thereby
warranting a buffer zone greater than one-half mile.

3.2 AMA

4 Identification and Evaluation of Leakage Pathways

-------
4.1 Leakage from Surface Equipment

4.2 Leakage from Wells

4.2.1 Abandoned Wells

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Figure 4.2-1. Plugged and Abandoned Wells in the CFA.

4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the UIC program in
demonstrating that injection wells themselves do not act as conduits for leakage into
underground sources of drinking water (USDW) and to the surface environment. TRRC Rule
46 requirements include special equipment requirements (e.g., tubing and packer) and
modification; records maintenance; monitoring and reporting; testing; plugging; and
penalties for violations of the rule. Permit revocation may result as a consequence of
noncompliance. (See Section 2.3.6) The TRRC and the OCC detail all the requirements for the
Class II permits issued to CapturePoint. These rules ensure that active injection wells
operate to be protective of subsurface and surface resources and the environment. Figure
4.2-2 shows the active injection wells in the CFA. CapturePoint concludes that leakage of
C02 to the surface through active injection wells is unlikely.

23

-------
4.2.3 Production Wells

Figure 4.2-3 shows the active oil production wells in the CFA. Once EOR operations
commence, the energy content of the produced gas drops and cannot be sold; therefore, no
gas wells are identified. However, as the project develops in the CFA additional production
wells may be added and will be constructed according to the relevant rules of the OCC and
the TRRC. Additionally, inactive wells may become active according to the rules of the OCC
and the TRRC.

During production, oil, gas, and water flow from the reservoir into the wellbore. This flow is
caused by a differential pressure where the bottom hole wellbore pressure is less than the
reservoir pressure. These lower pressure fluids, which also contains C02, are contained by
the casing, tubing, wellhead, and flowline all the way to the CTB. CapturePoint concludes
that leakage of C02 to the surface through production wells is unlikely.

24

-------
4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

Inactive wells have a cast iron bridge plug set or long cement plugs placed above the existing
perforations to isolate reservoir from the surface. The wellhead pressures are then checked
per operation schedule for any change. CapturePoint concludes that leakage of C02 to the
surface through inactive wells is unlikely.

25

-------
4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources, and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water.

•	That wells file a completion report including basic electric logs.

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected.

26

4.3 Leakage from Faults and Bedding Plane Partings

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1 Prescence of Hydrocarbons

4.3.2 Fracture analysis

-------
4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates, and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir, it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA, the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort analysis,
pulse-decay permeability measurement, pressure decay permeability analysis for tight
rocks, and mercury injection porosimetry, which is also known as mercury injection capillary
pressure (MICP). Geomechanical analysis involved a standard series of mechanical tests:
Brazil tension, unconfined compression, triaxial compression, and multi-stress compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone layers
are strong but brittle, while the shale layers are weaker but sufficiently ductile to prevent
extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

In the unlikely event C02 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any C02 leakage, CapturePoint
has strategies for leak detection in place that are discussed in Section 4.5 and the strategy to
quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

Figure 4.6 shows the map of earthquakes with magnitudes measured at greater than 2.5 as
defined by the United States Geological Survey (USGS). While past earthquake data cannot
predict future earthquakes, the small number of events near CFA after the waterflood

-------
operations were initiated in 1969 implies the area is not seismically sensitive to injection.
Also, no documentation exists that any of the distant earthquake events caused a disruption
in injectivity or damage to any of the weilbores in CFA,

I SO km |
SO mi

Lubbock

a

Figure 4.6. USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red.

Liberal

Q

*

o

Dodge City

£

There is no direct evidence that natural seismic activity poses a significant risk for loss of C02
to the surface in the CFA.

In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,

29

-------
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will use
Subpart W techniques to estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven leakage quantification
reported in Subpart RR for surface leaks will use other techniques.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

30

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02

values for soil measurement in the CFA area, per the characterization, monitoring and well data

collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous

Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration of
C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells. However,
samples are pulled when OCC injection permits are submitted in Oklahoma. No indication of
fluid leakage has been identified from any of these in the CFA area. CapturePoint is unlikely
to continue monitoring USDW wells for C02 or brine contamination, as characterization of
the Morrow (see section 5.1) has suggested minimal risk of groundwater contamination
from C02 leakage from this depth.

5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

-------
5.5 Well Surveillance

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations.

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 at its CFA facility through its own pipeline from the
Arkalon Ethanol plant in Liberal, Kansas. CapturePoint also recycles C02from its production
wells in the CFA.

C02T,r = Ep=i (Qr,p ~ Sr,p) *D* Cco2pr (Equation RR-2)
where:

C02r,r= Net annual mass of C02 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 the well in quarter p (standard cubic meters).

D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.

Cco2pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).

p = Quarter of the year.

r = Receiving flow meter.

6.2 Determining Mass of CO2 Injected

CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02,u = Ep=i QP,u *D* Cc02pu (Equation RR-5)

-------
where:

C02,u = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):

0.0018682.

Cco2pu = concentration measurement in flow for flow meter u in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

u = Flow meter.

6.3 Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02 from its production wells which are part of its operations in
the CFA. Therefore, the following equation is relevant to its operations.

C02,w = Ip=i Qp,w *D* Cc02vw (Equation RR-8)

Where:

C02,w = Annual C02 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 C02 at standard conditions (metric tons per standard cubic meter):

0.0018682.

Cco2pw = CO2 concentration measurement in flow for separator w in quarter p (vol.
percent C02, expressed as a decimal fraction).

p = Quarter of the year.

w = Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at
each gas-liquid separator in accordance with the procedure specified in Equation RR-9
below:

C02P = (1 + X) * £w=1 C02 w (Equation RR-9)

Where:

C02P = Total annual C02 mass produced (metric tons) through all separators in the
reporting year.

C02 w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

-------
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction), CU is
0.00236 and NPU is 0.00454 at the last sample.

w = Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant
surface equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233
(r) (2) of Subpart W, the emissions factor listed in Table W-1A of Subpart W shall be used to
estimate all streams of gases, including recycle C02 stream, for facilities that conduct EOR
operations.

CapturePoint will calculate the total annual mass of C02 emitted from all leakage pathways
in accordance with the procedure specified in Equation RR-10 below:

C02E = Yjx=iC02,x (Equation RR-10)

where:

C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.

C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5	Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural
gas.

C02 — C02I — C02p — C02e — C02fi — C02fp (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the
reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting
year.

C02Fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

34

-------
C02pp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, November 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), Capture Point's internal documentation regarding the
collection of emissions data includes the following:

•	Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

•	Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

•	Description of the procedures and methods that are used for quality assurance,
maintenance, and repair of all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

8.1.1	General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02
quantity will be conducted according to an appropriate standard method published by a
consensus-based standards organization or an industry standard practice such as the Gas
Producers Association (GSA) standards.

Measurement of C O? Volume- All measurements of C02 volumes will be converted to the
following standard industry temperature and pressure conditions for use in Equations RR-2,
RR-5, and RR-8 of Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere. CapturePoint will adhere
to the American Gas Association (AGA) Report #3 - (ORIFICE METERING OF NATURAL GAS
AND OTHER RELATED HYDROCARBON FLUIDS)

8.1.2	CO2 Received

Daily fermentation C02 purchased is received via the pipeline from the Arkalon ethanol
plant in Liberal, Kansas, and is measured using a volumetric totalizer, which uses accepted
flow calculations for C02 according to the AGA Report #3.

35

-------
8.1.3 C02 Injected

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors
prior to being combined with purchase C02. The produced gas is sampled at least quarterly
for the C02 content.

8.1.5 CO2 Emissions from equipment leaks and vented emissions of CO2

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

8.2 QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP,
as required in the development of this MRV plan under Subpart RR. Any measurement
devices used to acquire data will be operated and maintained according to the relevant
industry standards.

-------
8.3	Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR
98.445 of Subpart RR of the GHGRP, as required.

A quarterly flow rate of C02 received that is missing would be estimated using invoices or
using a representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated
using invoices or using a representative concentration value from the nearest previous time
period.

A quarterly quantity of C02 injected that is missing would be estimated using a
representative quantity of C02 injected from the nearest previous period of time at a similar
injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions of
C02 from surface equipment at the facility that are reported in this subpart, missing data
estimation procedures specified in subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing
would be estimated using a representative quantity of C02 produced from the nearest
previous period of time.

8.4	Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes,
monitoring instrumentation, and quality assurance procedures; or to improve procedures
for the maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

37

-------
9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1)	A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2)	The data used to calculate the GHG emissions for each unit, operation, process, and activity.
These data include:

(i)	The GHG emissions calculations and methods used.

(ii)	Analytical results for the development of site-specific emissions factors, if
applicable.

(iii)	The results of all required analyses.

(iv)	Any facility operating data or process information used for the GHG emission
calculations.

(3)	The annual GHG reports.

(4)	Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring
equipment.

(5)	A copy of the most recent revision of this MRV Plan.

(6)	The results of all required certification and quality assurance tests of continuous monitoring
systems, fuel flow meters, and other instrumentation used to provide data for the GHGs
reported.

(7)	Maintenance records for all continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHGs reported.

(8)	Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and
pressure, and concentration of these streams.

(9)	Quarterly records of produced C02, including mass flow or volumetric flow at standard
conditions and operating conditions, operating temperature and pressure, and concentration of
these streams.

(10)Quarterly	records of injected C02 including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these
streams.

(11)Annual	records of information used to calculate the C02 emitted by surface leakage from
leakage pathways.

(12)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead.

(13)Annual	records of information used to calculate the C02 emitted from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production
wellhead and the flow meter used to measure production quantity.

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

38

-------
10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

C02

1

0

CU 2171

35007354120000

Oi

Prod

Active

C02

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

C02

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

C02

1

0

CU 2731

35007359750000

Oi

Prod

Active

C02

1

0

CU 2761

35007350590000

Oi

Prod

Active

C02

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

C02

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

C02

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

C02

1

0

CU 3113

35007359460000

Oi

Prod

Active

co2

1

0

CU 3115

35007251710000

Oi

Prod

Active

co2

1

0

CU 3116

35007252570000

Oi

Prod

Active

co2

1

0

CU 3143

35007250860000

Oi

Prod

Active

co2

1

0

CU 3171

35007359600000

Oi

Prod

Active

co2

1

0

CU 3182

35007249250000

Oi

Prod

Active

co2

1

0

CU 3211

35007352150000

Oi

Prod

Active

co2

1

0

CU 3212

35007352690000

Oi

Prod

Active

o
u

1

0

CU 3231

35007001820000

Oi

Prod

Active

co2

1

0

CU 3232

35007352720000

Oi

Prod

Active

o
u

1

0

CU 3234

35007212010000

Oi

Prod

Active

co2

1

0

CU 3261

35007352170000

Oi

Prod

Active

o
u

1

0

CU 3263

35007251640000

Oi

Prod

Active

co2

1

0

CU 3271

35007352160000

Oi

Prod

Active

o
u

1

0

CU 3273

35007252580000

Oi

Prod

Active

co2

1

0

CU 3274

35007253140000

Oi

Prod

Active

co2

1

0

CU 3275

35007254040000

Oi

Prod

Active

co2

1

0

CU 3312

35007360800000

Oi

Prod

Active

co2

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

o
u

1

0

CU 3332

35007254020000

Oi

Prod

Active

co2

1

0

CU 3381

35007360780000

Oi

Prod

Active

o
u

1

0

CU 3411

35007351700000

Oi

Prod

Active

co2

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name API	Well Type Status Gas Active	Active

Makeup Production Injection

NWCU 19-4

35007360930000

Oi

Prod

Inactive

o

u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

0
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

co2

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

n
O

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

O
U

0

0

CU 1551

35007350740000

Oi

Prod

P&A

C02

0

0

CU 1671

35007352180000

Oi

Prod

P&A

O
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

co2

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

co2

0

0

CU 2531

35007361090000

Oi

Prod

P&A

0
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

n
O

0

0

CU 2552

35007359760000

Oi

Prod

P&A

O
U

0

0

CU 2571

35007350730000

Oi

Prod

P&A

C02

0

0

CU 2572

35007359320000

Oi

Prod

P&A

O
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

co2

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

0
u

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

co2

0

0

41

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

o

U

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o

U

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

o

U

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o

U

0

0

CU 3561

35007359830000

Oi

Prod

P&A

o

U

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o

U

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

co2

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o
u

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

n
o

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o

U

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

42

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name	API	Well Type Status Gas Active	Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

co2

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

o
u

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

n
O

N)

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

o
u

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

co2

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

0
u

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

co2

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

0
u

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

n
O

N)

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

O
U

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

O
u

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

co2

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

0
u

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

n
O

N)

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

O
U

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

O
u

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

n
O

N)

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

O
U

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

O
u

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

co2

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

0
u

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

co2

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

0
u

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

co2

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

0
u

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

n
0

N)

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

O
U

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

C02

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

O
u

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

n
O

N)

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

O
U

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

O
u

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

co2

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

n
O

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

0
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

0
0

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

0
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

0
0

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

0
0

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

0
0

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

0
0

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

co2

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

0
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

0
0

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

0
u

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

O
u

0

0

CU 2551

35007350750000

Wtr Inj

P&A

0
0

0

0

44

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26, INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1, NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits >

Section 45Q	Credit for carbon oxide sequestration

OCC > Title 165: CORPORATION COMMISSION > UNDERGROUND INJECTION CONTROL
Section

165

10-5-1	

165

10-5-2	

165

10-5-3

165

10-5-4	

165

10-5-5	

165

10-5-6	

165

10-5-7	

165

10-5-8	

165

10-5-9	

165

10-5-10	

165

10-5-11	

165

10-5-12

165

10-5-13	

165

10-5-14

disposal wells

165

reserve pit fluids

10-5-15	Application for permit for simultaneous injection well

165:5-7-27	Application for approval of injection and disposal wells

165:5-7-29	Request for exception to certain underground injection well requirements

165:5-7-30	Amending existing orders or permits authorizing injection for injection,

disposal, or LPG storage wells

45

-------
TAC > Title 16 - Economic Regulation> Part 1 TRRC > Chapter 3 - Oil and Gas Division >

Rules

§3.1	Organization Report; Retention of Records; Notice Requirements

§3.2	Commission Access to Properties

§3.3	Identification of Properties, Wells, and Tanks

§3.4	Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on

All Forms

§3.5	Application to Drill, Deepen, Reenter, or Plug Back

§3.6	Application for Multiple Completion

§3.7	Strata to Be Sealed Off

§3.8	Water Protection

§3.9	Disposal Wells

§3.10	Restriction of Production of Oil and Gas from Different Strata

§3.11	Inclination and Directional Surveys Required

§3.12	Directional Survey Company Report

§3.13	Casing, Cementing, Drilling, Well Control, and Completion Requirements

§3.14	Plugging

§3.15	Surface Equipment Removal Requirements and Inactive Wells

§3.16	Log and Completion or Plugging Report

§3.17	Pressure on Bradenhead

§3.18	Mud Circulation Required

§3.19	Density of Mud-Fluid

§3.20	Notification of Fire Breaks, Leaks, or Blow-outs

§3.21	Fire Prevention and Swabbing

§3.22	Protection of Birds

§3.23	Vacuum Pumps

§3.24	Check Valves Required

§3.25	Use of Common Storage

§3.26	Separating Devices, Tanks, and Surface Commingling of Oil

§3.27	Gas to be Measured and Surface Commingling of Gas

§3.28	Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29	Hydraulic Fracturing Chemical Disclosure Requirements

§3.30	Memorandum of Understanding between the Railroad Commission of Texas

(RRC) and the Texas Commission on Environmental Quality (TCEQ)
§3.31	Gas Reservoirs and Gas Well Allowable

§3.32	Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes

§3.33	Geothermal Resource Production Test Forms Required

§3.34	Gas To Be Produced and Purchased Ratably

§3.35	Procedures for Identification and Control of Wellbores in Which Certain

Logging Tools Have Been Abandoned
§3.36	Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

46

-------
§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste

Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

47

-------
§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt

Formations

§3.96	Underground Storage of Gas in Productive or Depleted Reservoirs

§3.97	Underground Storage of Gas in Salt Formations

§3.98	Standards for Management of Hazardous Oil and Gas Waste

§3.99	Cathodic Protection Wells

§3.100	Seismic Holes and Core Holes

§3.101	Certification for Severance Tax Exemption or Reduction for Gas Produced

From High-Cost Gas Wells
§3.102	Tax Reduction for Incremental Production

§3.103	Certification for Severance Tax Exemption for Casinghead Gas Previously

Vented or Flared

§3.106	Sour Gas Pipeline Facility Construction Permit

§3.107	Penalty Guidelines for Oil and Gas Violations

48

-------
Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995), Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618.

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990), Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990.

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991), Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W.

Bowen, D.W., Krystinik, L.F., and Grantz, R.E. (1990), Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003), Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004), Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., (2005), Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone
in the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979), Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021.

49

-------
Gallagher, S. R. (2014), Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016), Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018),
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX.

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015), Reservoir Fluid Characterization for
Miscible Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19, 2015,
Sugarland, Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015), Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014), Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019), Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019.

Jorgensen, D.G. (1989), Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990), Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018), Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964), "Calculating Viscosities of Reservoir Fluids from their
compositions" SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996), Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

50

-------
Munson, T., (1988), "Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State
University, Canyon, TX, 354 pp.

Munson, T. W. (1989), Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, (2014), Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,

Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index.php?globalnav=time_space§ionnav=state&state_id=42&period_id=12.

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989).

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT / HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982).

Peng, D.Y. and Robinson, D.B. (1976), A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64.

Perry, W. J., Jr. (1989), Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996), The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008), Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019), Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

51

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Rose-Coss, D. (2017), A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse.

Sonnenberg, S.A., (1985), Tectonic and Sedimentation Model for Morrow Sandstone Deposition,
Sorrento Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010), An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010.

Swanson, D., (1979), Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018), Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., (1990), Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016), Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017), Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

-------
Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API-American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

cf - cubic feet

CH4 - methane

C02 - carbon dioxide

EOR- Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA - Gas Producers Association

H2S - hydrogen sulfide

lb - pound

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metrictonnes

MT - Metric tonne

NIST - National Institute of Standards and Technology

-------
NAESB - North American Energy Standards Board

OAC - Oklahoma Administrative Code

OCC - Oklahoma Corporation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC - quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA-Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD - Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

-------
Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas—The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

DensityC02 77 = DensityC02 	—	 x MWC02 x Tr^7TT^rrr~

yC02\ft3J	sco2 y jrt3 j	co2 2,204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
Density C02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	MT

DensityC02 = 5.2734 x 10 or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

55

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Request for Additional Information: Camrick Unit
April 7, 2022 (Response April 25,2022)

No.

MRV Plan
Section

Page

EPA Questions

Responses

N/A

There is a semi-consistent lack of thousands place separators in
numbers throughout the MRV plan. Please add for clarity.

Added the thousands place separators for number and did not
change any name that contained a number.

N/A

Throughout the MRV plan, there is inconsistent spacing between
words and following punctuation. For example, see the following
passage reproduced from section 3, page 4 of the MRV plan:

"Also, all wells in the CFA..."

Please correct for clarity.

Removed all double spacing throughout the MRV plan document.

N/A

There is an inconsistent use of the Oxford comma (and commas in
general) throughout the MRV plan. For clarity, we recommend
consistent comma use.

Added the Oxford comma throughout the document.

N/A

There is a tendency to repeat acronym definitions throughout the
MRV plan. Please use the acronym each time a phrase is used after
an acronym has been defined. Additionally, please ensure that
acronyms are defined the first time they are used.

Added acronym definition the first time it is used then only used the
acronym definition.

N/A

Throughout the MRV plan, maps have difficult-to-read legends. We
recommend increasing the size and/or resolution of all figures and
legends to improve their readability. Examples include Figure 2.4-1
and Figure 3.1.1.

Increased the size of most figures and legends.

N/A

Throughout the MRV plan, maps have difficult to use scale bars. For
example, Figure 2.3-2 has a scale bar for 4,501 feet. We recommend
using easily divisible, round numbers for scale bars.

Changed the scale bars to 5000 feet per inch on maps generated by
company owned software.

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No.

MRV Plan
Section

Page

EPA Questions

Responses

7.

N/A

l

The title of Section 4 of the MRV is written as "...Leakage Pathway",
we suggest changing this to "...Leakage Pathways". Similarly, we
suggest changing the title of subsection 4.3 to "....Bedding Plane
Partings" and the title of subsection 4.3.1 to "....Hydrocarbons".

Added "s" per suggestion.

8.

Intro.

3

"...with the subsidiary or ancillary..."

Is the sequestration of CO2 subsidiary or ancillary to the EoR
operations in the Camrick Unit? These terms have distinctly
different meanings, specifically, ancillary suggests that
sequestration is necessary for normal operations.

Changed to "with retention of C02 serving a subsidiary".

9.

Intro.

3

"... and the Oklahoma Corporation Commission OAC 165:10. In this
document, the term "gas" usually..."

Is "OAC" supposed to be the acronym? If so, please put the
acronym in parentheses and check the spelling. We recommend
checking the use of "OAC" and "OCC" throughout the document.
Additionally, please remove the word "usually" and/or clarify when
the term "gas" has a different meaning.

Included Oklahoma Administrative Code (OAC) into document.
Checked the use of "OCC" and "OAC".

Removed the word "usually from the sentence.

10.

1.1

4

The relationship of the MRV plan to the facilities listed is unclear.
For example, does CapturePoint intend to report each unit
separately under Subpart RR using its respective facility ID? If so,
each facility should have its own MRV Plan. Please provide
clarification.

The Camrick Unit, which is in Oklahoma, and the North Perryton
Unit, which is in Texas, presently have two separate Greenhouse
Gas Program Reporting Identification numbers. However, the two
units share only one CO. processing injection facility and share the
same geologic reservoir. (See Question No. 26)

The oil is sold in their respective states as per royalty ownership
lease documents. Also, the water remains in the respective states
per water board requirement.

Should we use one GHG number for Camrick Field Area?

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No.

MRV Plan
Section

Page

EPA Questions

Responses

11.

1.2

4

"For injection wells (see Appendix 2) that are the subject of this
MRV plan, the Oklahoma Conservation Commission (OCC) has rules
governing Undergound Injection Control (UIC) Class II injection
wells; OAC 165:10-5-1 through OAC 165:10-5-15, OAC 165:5-7-27,
OAC 165:5-7-30, the request for an exception to UIC rules under
OAC 165:5-7-29, and other rules governing filing forms."

As written, this sentence is confusing. We suggest splitting into two
sentences such that OAC citations are in one sentence and the
remaining references are in a second sentence.

Additionally, please check for spelling and grammar.

Changed and split sentence for clarity to "For injection wells (see
Appendix 2) that are the subject of this MRV plan, the OCC has rules
governing UIC Class II injection wells. These OCC rules are OAC Title
165:10-5-1 through 165:10-5-15, OAC 165:5-7-27, OAC 165:5-7-30,
the request for an exception to UIC rules under OAC 165:5-7-29,
and other governing filing forms."

12.

2.1.1

4

"...for an additional 12 years..."

Please either remove "an additional" or further clarify what this
means.

Added additional words to clarify further "The CFA has been
injecting C02 for the last 20+ years and...".

13.

2.1.2

4

'The chart to the left in Figure 2.4-7 in Section 2.4"

We suggest either reproducing the chart here or moving it to this
location to improve readability. Additionally, this phrase reads
awkwardly and feels out of place. We recommend revising it.

Recreated charts for clarity and edited section to improve flow.

14.

2.1.2

4

"For the period September 2020 through October 2034, an
additional 52.5 Bscf or 2.77 MMMT will be stored in the CFA."

Seeing as this MRV plan was submitted in March 2022, has the
above been updated since September 2020?

Subpart RR reporters can only begin reporting to subpart RR in the
reporting year the MRV plan is approved. Reporters cannot
retroactively report quantities of C02 injected in reporting years
prior to the year of MRV approval. Please clarify.

Furthermore, will the 52.4 Bscf be in addition to the 100 Bscf in the
prior sentence? If so, why split these volumes? Please clarify.

Corrected period "September 2022 through October 2034".
Ditto.

The total CO. volume sequestered and the MRV CO. volume
sequestered were discussed in Section 2.1.2.

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No.

MRV Plan
Section

Page

EPA Questions

Responses

15.

2.2.2

5

'The geological discussions in Sections 2.2.2 and 4.3-4.4 are based
on analysis of logs from both the Farnsworth Unit../'

Please explain why the Farnsworth Unit is a good geologic analog
for the CFA and update the MRV plan accordingly.

Added sentence describing the similarities.

16.

2.2.2

5

'The descriptions of cores included sections from overlying seals as
well as the shale underlying the main reservoirs, petrographic thin
section descriptions and point counts as well as a variety of special
analytical techniques including X-ray diffraction (XRD), which is the
science of determining the atomic and molecular structure of rock
crystals with an X-ray beam; scanning electron microscope (SEM)
analysis; which uses a beam of electrons to define the surface of
crystals; carbon isotope analysis to estimate the age of the sample;
and a variety of mechanical tests"

This wording is confusing; please rephrase.

Split the sentence and rephrased.

17.

2.2.2

5

"...carbon isotope analysis to estimate the age of the sample..."

Our understanding is that carbon isotope analysis only provides
accurate dating back to a maximum of approximately 55,000 years
in the past. Can you please provide further characterization of its
use at the CFA?

Changed to "...carbon isotope analysis to estimate the age of the
CO. in the sample..."

This will determine the presence of Fermentation CO. .

18.

2.2.2.1

8

"...the Morrow B is described as a relatively coarse-grained
subarkosic sandstone and per depositional pathway ..."

This is not clear. Can you please clarify what is meant by the above
phrase?

Removed the following for clarity "and per depositional pathway."

19.

2.2.2.2

9

'The CFA C02 injection and production operations will not cause
water to flow..."

Please clarify the likelihood of this scenario.

Changed to 'The CFA C02 injection and production operations have
negligible likelihood of causing water to flow..."

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No.

MRV Plan
Section

Page

EPA Questions

Responses

20.

2.3

9

"C02 distribution and Injection"

It appears there is a capitalization inconsistency in the phrase
above, please correct it if so.

Changed the Capitalization on "injection".

21.

2.3

10

Figure 2.3-1 is difficult to follow. We recommend adjusting the sizes
and proportions of the pictures, text boxes, and/or arrows for
increased clarity.

Increased the size of the graphic.

22.

2.3

10

"...while only the gas from NPU is sent to the CTB the NPU oil and
water remains in Texas."

Can you please elaborate on this distinction?

See Question 10 above.

23.

2.3.1

10

"...C02 purchases will remain constant at 12 MMCFD for 12 years
and decline after 2034."

This statement seems to contradict Figure 2.4.7. Figure 2.4.7 makes
it seem as if C02 purchases will cease during 2034. Please adjust.

Changed the "decline" to "cease".

24.

2.3.2

11

"One for the liquid phase, a mixture of oil and water, and one for

the gas phase..."

This is not a complete sentence. Please revise and clarify its
meaning.

Rephrased sentence.

25.

2.3.2

12

"Although CapturePoint is not required to determine or report the
amount of dissolved C02 in the water..."

Equation RR-9 requires the reporting of X, the "Entrained C02 in
produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as
a decimal fraction)". Please clarify.

Changed to "CapturePoint is not required to determine or report
the amount of dissolved C02 in the water as it is reinjected into the
ground and not emitted to the atmosphere"

26.

2.3.4

13

Can you please provide a more descriptive legend to identify well
types for Figure 2.3-2?

The purpose of Figure 2.3-2 is to show the location of the one
Central Tank Battery and the location the various "All Well Test"
sites. Well identification is displayed in Figures 4.2.1 through 4.2.4.

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No.

MRV Plan
Section

Page

EPA Questions

Responses

27.

2.3.6

13

"Briefly current rules require, among other provisions:"

Please rephrase or reorganize statement to improve clarity and
grammar.

Changed to "Briefly the following bulleted list is what the current
rules require, among other provisions!"

28.

2.3.6

13

"...and closure for all wells in permitted units and wells."
This sentence is unclear, please revise.

Changed "closure" to "plugging".

29.

2.3.6

14

"And that all wells follow plugging procedures that require advance
approval from the Director and allow consideration of the suitability
of the cement based on the use of the well, the location and setting
of plugs."

It appears there is a formatting issue in the above phrase,
specifically it should likely be a final bullet attached to the list
preceding it. In addition, the spacing of this bulleted list is not
consistent. Please fix.

Reformatted items.

30.

2.4.1

14

'The CFA is approximately 8 mi by 7 mi that have areas that exhibit
different reservoir behavior."

This wording is confusing; please rephrase. Also, "mi" is spelled out
elsewhere in the document. Please review for consistency.

Changed to miles.

31.

2.4.1

14

'The southwest portion of CU was most prolific oil producer..."
It appears there is a typo in the phrase above, please correct it if so.

Revised sentence to 'The southwest portion of CU was most prolific
oil producing area of the CFA under primary and secondary
production".

32.

2.4.3

16

"...no production performance exists which indicates any plume will
move outside of the MMA at the end of year t + 5, per §98.449
definitions. "

This phrase is unclear, please revise.

Revised phrase to "Also, during CFA drilling and production
operations, no reports exist which would indicate any plume has
moved outside of the MMA. The Farnsworth Unit MRV and the CFA
data justifies the conclusion that C02 will continue to be contained
inside the MMA at the end of the C02 injection year t + 5, per
§98.449 definitions."

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No.

MRV Plan
Section

Page

EPA Questions

Responses

33.

2.4.4

17

"...oil ratio and the gas oil ration trends..."
It appears there is a typo. Please fix.

Fixed typo.

34.

3.1.1

18

Figure 3.1-1 displays the existing 4,800 acres in the CFA that has
been injecting C02 since March 2001.

This is grammatically confusing. Do you mean that the acres "have
been under injection?"

Changed to "Figure 3.1-1 displays wells that have C02 retention on
the 4,800 acres that have been under EOR injection in the CFA since
project initialization."

35.

3.1.1

18

There are 49 injectors identified for further injection that

Have room for an additional 90 Bscf or C02 storage or 140 Bscf total

space.

This is unclear. The first "or" should probably be "of." And should
"space" more appropriately be "storage volume"?

Changed "or" to "of"

Changed "space" to "volume"

36.

4.2.2

21

"Rule 46 and any special conditions pertaining to mechanical
integrity testing..."

We suggest you provide a brief description of what Rule 46
regulates in this section for clarity.

Added description for clarity "TRRC Rule §3.46 requirements include
special equipment requirements (e.g., tubing and packer) and
modification, records maintenance; monitoring and reporting;
testing; plugging; and penalties for violations of the rule. Permit
revocation may result as a consequence of noncompliance. This
TRRC and the OCC detail all the..."

37.

4.2.2

21

"Rule 46 and any special conditions pertaining to mechanical
integrity testing required by the OCC and the TRRC are included in
the Class II permits issued to CapturePoint, ensure that active
injection wells operate to be protective of subsurface and surface
resources and the environment."

The above is a run-on sentence, please revise.

See Question 36.

38.

4.2.3

22

"... shows the active oil production wells in the CFA."

Are there only oil wells, or are there also gas wells? Please clarify.

Added clarifying statement "Once EOR operations commence, the
energy content of the produced gas drops and cannot be sold;
therefore, no gas wells are identified."

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No.

MRV Plan
Section

Page

EPA Questions

Responses

39.

4.2.3

22

This section provides little characterization of the risk and
magnitude of potential leakage from production wells. Why does
CapturePoint conclude that leakage through production wells is
unlikely? Please expand upon this section.

Added "During production, oil, gas, and water flow from the
reservoir into the wellbore. This flow is caused by a differential
pressure where the bottom hole wellbore pressure is less than the
reservoir pressure. These lower pressure fluids, which also contains
C02, are contained by the casing, tubing, wellhead and flowline all
the way to the CTB."

40.

4.2.4

23

This section provides no characterization of the risk and magnitude
of potential leakage from inactive wells. Please expand upon this
section.

In general, please ensure that all leakage pathways have a leakage
likelihood characterization and evidence to support the
characterization.

Added "Inactive wells have a cast iron bridge plug set or long

cement plugs placed above the existing perforations to isolate

reservoir from the surface. The wellhead pressures are then

checked per operation schedule for any change."

Added to Section 4.2.1 "The cement used to plug wells when

exposed to C02 will form colloidal gels that further reduce any

flow."

41.

4.8

28

"CapturePoint will reconcile the Subpart W report and results from
any event-driven quantification to assure that surface leaks are not
double counted."

Does CapturePoint mean that they intended to use Subpart W
techniques to estimate equipment leakages, and ensure those are
consistently represented in the Subpart RR report? In addition, the
statement should emphasize that this statement only applies to
equipment leaks, and not surface leaks. Please address

Changed to "CapturePoint will use Subpart W techniques to
estimate leakages only on equipment and ensure those results are
consistently represented in the Subpart RR report. Any event-driven
leakage quantification reported in Subpart RR for surface leaks will
use other techniques."

Subpart RR will be consistently represented.

42.

4.8

28

"As indicated in Sections 6.4...."

It appears there is a typo in the above phrase, please correct it.

Removed "s"

43.

5.2

28

"...characterization of the Morrow (see section 5.1) have
suggested..."

Please review for grammar.

Changed "have" to "has"

44.

6

29-31

The formatting in this section is cluttered and difficult to follow.
Please revise it to improve readability. In particular, more spacing
between equations and description of variables will dramatically
improve readability.

Changed format adding space.

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No.

MRV Plan
Section

Page

EPA Questions

Responses

45.

6.1

29

"CapturePoint currently receives C02 to its CFA facility through
their own pipeline from the Arkalon Ethanol plant in Liberal, Kansas.
CapturePoint also recycles C02 from their production wells in the

CFA."

We recommend reviewing this sentence for grammar.

Changed "to" to "at".

Switched back from British English rules to American English rules
by changing "their" to "its".

46.

6.2

30

If aggregating C02 injection quantities for all wells, you must use
RR-6. Please add to Section 6 as necessary.

CapturePoint does not aggregate individual wells. We have master
meters at the CTB and allocate injection to individual well. (See
Section 2.3.1)

47.

6.2

30

"...(weight percent C02, expressed as a decimal fraction )."

Although the X factor (entrained C02) was reported earlier in the
document, we recommend reporting it again here.

Added ", CU is 0.00236 and NPU is 0.00454 at the last sample"

48.

6.4

3.1

'The following Equation RR-12 pertains to facilities... for which a
calculation procedure is provided in subpart W of the GHGRP."

In the future, CapturePoint intends to maintain Class II status and
will continue to evaluate the cash flow of oil and gas operations,
but.

Removed RR-12 from document.







Please clarify whether Camrick intends to not produce oil or gas in
the future. This may represent a material change in operations and
necessitate a resubmission of the MRV plan. If equation RR-12 is not
applicable to the operations described in this MRV plan, it can be
removed from this section.

49.

8

31-33

The formatting in this section is cluttered and difficult to follow.
Please revise it to improve readability. In particular, more spacing
between equations and description of variables will dramatically
improve readability. Please also review other sections of MRV plan
for consistent formatting.

Added formatting to add spacing

50.

8.1.2

32

"Daily totalized volumetric flow meters are used to record C02
received via pipeline from the Arkalon ethanol plant in Liberal,
Kansas, using a volumetric..."

It appears there is a typo in the phrase above, please correct it if so.

Changed to "Daily fermentation C02 purchased is received via the
pipeline from the Arkalon ethanol plant in Liberal, Kansas, and is
measured using a volumetric totalizer, which uses accepted flow
calculations for C02 according to the AGA Report #3"

-------
Camrick Field Area (CFA)

MONITORING, REPORTING AND VERIFICATION PLAN (MRV)

CapturePoint LLC

CAPTUREPOINT

March 2022

-------
Contents

INTRODUCTION	3

1	FACILITY	4

1.1	Reporter Number	4

1.2	UIC Permit Class	4

1.3	UIC Injection Well Numbers	4

2	PROJECT DESCRIPTION	4

2.1	Project Characteristics	4

2.1.1	Estimated years of C02 injection	4

2.1.2	Estimated volume of C02 injected over lifetime of project	4

2.2	Environmental Setting of MMA	5

2.2.1	Boundary of the MMA	5

2.2.2	Geology	5

2.3	Description of the Injection Process	9

2.3.1	C02 Distribution and Injection	10

2.3.2	Produced Fluids Handling	11

2.3.3	Produced Gas Handling	12

2.3.4	Facilities Locations	12

2.3.5	Water Conditioning and Injection	13

2.3.6	Well Operation and Permitting	13

2.3.7	Number, Location and Depth of Wells	14

2.4	Reservoir Characterization	14

2.4.1	Reservoir Description	14

2.4.2	Reservoir Fluid Modeling	15

2.4.3	C02 Analogy Field Study	16

2.4.4	C02 - EOR Performance Projections	16

3	DELINEATION OF MONITORING AREA	18

3.1	MMA	18

3.1.1	Determination of Storage Volumes	18

3.1.2	Determination of Buffer Zone	19

3.2	AMA	20

4	IDENTIFICATION AND EVALUATION OF LEAKAGE PATHWAY	20

4.1	Leakage from Surface Equipment	20

4.2	Leakage from Wells	20

4.2.1	Abandoned Wells	20

4.2.2	Injection Wells	21

4.2.3	Production Wells	22

4.2.4	Inactive Wells	23

4.2.5	New Wells	23

4.3	Leakage from Faults and Bedding Plane Parting	24

4.3.1	Prescence of Hydrocarbon	24

4.3.2	Fracture analysis	24

4.4	Lateral Fluid Movement	25

4.5	Leakage through Confining/Seal system	25

4.6	Naturaland Induced Seismic Activity	26

-------
4.7	Strategy for Detection and Response to C02 loss	27

4.8	Strategy for Quantifying C02 loss	27

5	STRATEGY FOR DETERMINING C02 BASELINES FOR C02 MONITORING	28

5.1	Site Characterization and Monitoring	28

5.2	Groundwater monitoring	28

5.3	Soil C02 monitoring	29

5.4	Visual Inspection	29

5.5	Well Surveillance	29

6	SITE SPECIFIC CONSIDERATIONS FOR DETERMINING THE MASS OF C02 SEQUESTERED	29

6.1	Determining Mass of C02 received	29

6.2	Determining MassofC02 Injected	30

6.3	Determining Mass of C02 produced from Oil Wells	30

6.4	Determining Mass ofC02 emitted by Surface Leakage	30

6.5	Determining Mass of C02 sequestered	31

7	ESTIMATED SCHEDULE FOR IMPLEMENTATION OF MRV PLAN	31

8	GHG MONITORING AND QUALITY ASSURANCE PROGRAM	31

8.1	GHG MONITORING 	31

8.1.1	General	32

8.1.2	C02 Received	32

8.1.3	C02 Injected	32

8.1.4	C02 Produced	32

8.1.5	C02 emissions from equipment leaks and vented emissions ofC02	32

8.1.6	Measurement Devices	32

8.2	QA/QC procedures	33

8.3	Estimating missing data	33

8.4	Revisions of the MRV plan	33

9	RECORDS RETENTION	33

10	APPENDICES	35

Appendix 1-CFA Wells	35

Appendix 2 - Referenced Regulations	41

Appendix 3 - References	45

Appendix 4 - Abbreviations and Acronyms	49

Appendix 5 - Conversion Factors	51

2

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INTRODUCTION

CapturePoint, LLC (CapturePoint) operates the Camrick Field Area (CFA) located in Beaver and Texas
Counties, Oklahoma and in Ochiltree County, Texas for the primary purpose of enhanced oil recovery
(EOR) using carbon dioxide (C02) with a subsidiary or ancillary purpose of geologic sequestration of C02
in a subsurface geologic formation. The CFA was discovered in 1955 and is composed of three units, the
Camrick Unit (CU) that was unitized by Humble Oil Company on October 14, 1969, the North Perryton
Unit (NPU) that was unitized by Humble Oil Company on March 17, 1969 and the Northwest Camrick
Unit (NWCU) that was unitized by Atlantic Rich Field Company on September 15, 1972. The Units were
formed for the purpose of waterflooding with salt water sourced from the Wolfcamp formation. The
field structure is a lenticular bedding sand trending northwest to southeast with the average top of sand
at 7250 feet, true vertical depth. CapturePoint has been operating the CFA since 2017. CapturePoint
acquired the CFA from Chaparral Energy LLC, which initiated the C02-E0R project in March 2001 for the
CU and January 2007 for the NPU. No C02 has been injected in the NWCU. CapturePoint intends to
continue C02-EOR operations until the end of the economic life of the C02-EOR program using various
Class II injection wells as defined by Underground Injection Control (UIC) regulations and permitted
under Texas Railroad Commission Statewide Rule 46 and the Oklahoma Corporation Commission OAC
165:10. In this document, the term "gas" usually means a mixture of hydrocarbon light end components
and the C02 component that can be produced as part of the EOR process.

CapturePoint has chosen to submit this Monitoring, Reporting, and Verification (MRV) plan to the EPA
for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program
(GHGRP) for the purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue
Code.

This MRV Plan contains ten sections:

Section 1 contains facility information.

Section 2 contains the project description including: a detailed description of the injection operation
including the duration and volume of C02 to be injected; a detailed description of the geology and
hydrogeology of the CFA located on the northwest shelf of the Anadarko basin and a detailed
characterization of the injection reservoir and modeling techniques employed.

Section 3 contains the delineation of the maximum monitoring area (MMA) and the active monitoring
area (AMA), both defined in 40 CFR 98.449, and as required by 40 CFR 98.448(a)(1), Subpart RR of the
GHGRP.

Section 4 identifies the potential surface leakage pathways for C02 in the MMA and evaluates the
likelihood, magnitude, and timing, of surface leakage of C02 through these pathways as required by 40
CFR 98.448(a)(2), Subpart RR of the GHGRP. This section also describes the strategy for detecting,
verifying, and quantifying any surface leakage of C02 as required by 40 CFR 98.448(a)(3), Subpart RR of
the GHGRP. Finally, this section also demonstrates that the risk of C02 leakage through the identified
pathways is minimal.

Section 5 describes the strategy for establishing the expected baselines for monitoring C02 surface
leakage as required by 40 CFR 98.448(a)(4), Subpart RR of the GHGRP.

-------
Section 6 provides a summary of the considerations used to calculate site-specific variables for the mass
balance equation as required by 40 CFR 98.448(a)(5), Subpart RR of the GHGRP.

Section 7 provides the estimated schedule for implementation of this MRV Plan as required by 40 CFR
98.448(a)(7).

Section 9 describes the records to be retained according to the requirements of 40 CFR 98.3(g) of
Subpart A of the GHGRP and 40 CFR 98.447 of Subpart RR of the GRGRP.

Section 10 includes Appendices supporting the narrative of the MRV Plan.

1 Facility

1.1 Reporter Number

The CU C02 Flood reports under Greenhouse Gas Reporting Program Identification number
544678 and the NPU C02 Flood reports under Greenhouse Gas Reporting Program
Identification number 544679.

1.2 UIC Permit Class

For injection wells (see Appendix 2) that are the subject of this MRV plan, the Oklahoma
Conservation Commission (OCC) has rules governing Undergound Injection Control (UIC)
Class II injection wells; OAC 165:10-5-1 through OAC 165:10-5-15, OAC 165:5-7-27, OAC
165:5-7-30, the request for an exception to UIC rules under OAC 165:5-7-29, and other
rules governing filing forms. Also, the Texas Railroad Commission (TRRC) has issued
Underground Injection Control (UIC) Class II enhanced recovery permits under its State Rule
46, Texas Administrative Code (TAC) Title 16 Part 1 Chapter 3. Also, all wells in the CFA,
including both injection and production wells, are regulated by the OCC and the TRRC, which
have primacy to implement the UIC Class II program.

1.3 UIC Injection Well Numbers

A list of the injection wells in the CFA is provided in Appendix 1. The details of the injection
process are provided in Section 2.3.

2 Project Description

2.1 Project Characteristics

2.1.1 Estimated years of CO2 injection

It is currently projected that CapturePoint will inject C02 for an additional 12 years.

2.1.2 Estimated volume of CO2 injected over lifetime of project

The chart to the left in Figure 2.4-7 in Section 2.4 - Forecasted cumulative C02 injection
volume of approximately 100 billion standard cubic feet (Bscf) or 5.3 million metric tonnes

-------
(MMMT) through October 2034. For the period September 2020 through October 2034, an
additional 52.5 Bscf or 2.77 MMMT will be stored in the CFA.

2.2 Environmental Setting of MMA

2.2.1 Boundary of the MMA

2.2.2 Geology

The geological discussions in Sections 2.2.2 and 4.3-4.4 are based on analysis of logs from
both the Farnsworth Unit, which is located 10 miles South-South-West of the CFA, and the
CFA. The descriptions of cores included sections from overlying seals as well as the shale
underlying the main reservoirs, petrographic thin section descriptions and point counts as
well as a variety of special analytical techniques including X-ray diffraction (XRD), which is
the science of determining the atomic and molecular structure of rock crystals with an X-ray
beam; scanning electron microscope (SEM) analysis; which uses a beam of electrons to
define the surface of crystals; carbon isotope analysis to estimate the age of the sample; and
a variety of mechanical tests. Two dimensional (2D) and three dimensional (3D) geophysical
surveys were also used as part of the Farnsworth Unit MRV Plan (2021). Details of recent
geological investigations can be found in Gallagher (2014), Gragg (2016), Rasmussen et al
(2019), Rose-Coss et al (2015), Trujillo (2018), Hobbs et al (2019), and Gragg et al (2018).

2.2.2.1 Tectonic Setting and Stratigraphy
The CFA is located on the northwest shelf of the Anadarko basin (Figure 2.2-1) and is one of
many oil fields in the area that produce from a sequence of alternating sandstones and
mudstones deposited during the late Pennsylvanian Morrowan period. Oil production and
C02 injection at CFA is restricted to the operationally named Morrow B sandstone; the
uppermost Morrow sandstone encountered below the Atokan Thirteen Finger limestone.
The primary caprock intervals at CFA are comprised of the upper Morrow shale and the
Thirteen Finger limestone (Figure 2.2-2). The Morrowan and Atokan intervals were
deposited approximately 315-300 million years ago. Overlying stratigraphy includes Late
Pennsylvanian through the middle Permian shales and limestones, with lesser amounts of
dolomite, sandstone and evaporites (Ball, 1991). The reservoir is approximately 60 feet
thick throughout the field and lies at a depth of approximately 6800-7600 feet. The primary
seal rocks of the Morrow shale and the Thirteen Finger Limestone comprise a package of
approximately 180-200 feet thick in the field and are overlain by thousands of feet of
Atokan and younger limestones and shales.

-------
Structure Map
Top of the Arbuckle Gp.
(Cambro-Ordovician)
C.I.: 1000/5000 Ft

Figure 2.2-1- Location of the Camrick Field Area (CFA) on the Northwest Shelf of the Anadarko Basin in West
Texas. Red lines are approximate locations of faults that have been documented in the region.

6

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System

Series

Group

Formation

Wabaunsee

Virgilian

Shawnee

Heebner
Endicott
Toronto

Douglas

Douglas
U.Tonkawa

Missourian

Lansing

L. Tonkawa
Cottage Grove
Hogs hooter

Kansas
City

Checkerboard
Cleveland

LU
1-

c
9
Q.

Marmaton

Oswego

Z
<
X

Cherokee Shale

<
a

Atoka

Upper
Dornick
Hills

Atoka

Thirteen Finger

<
z
<

Morrow

Lower
Dornick
Hills

Upper Morrow
Middle Morrow
Lower Morrow

Springer

Chester

as
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5

Meramec

St. Genevieve
St. Louis
Spergan
Warsaw

Osage

Kinderhook

Chattanooga

Figure 2.2-2- Stratigraphic section.

Tectonic Setting

-------
South

TEXAS

OKLAHOMA
(panhandle)

North

KANSAS

TERTIARY
CRETACEOUS

10.000- -

Granite wash
Carbonate
Sandstone ~ shale
Fault

DIAGRAMMATIC NORTH-SOUTH CROSS SECTION
THROUGH THE DEEP ANADARKO BASIN

DEEP BASIN PROVINCE

Figure 2.2.3 Diagrammatic North-South Section (Bottom) of the CFA.

Stratigraphy

Reservoir

Upper Morrowan sandstones in the Anadarko Basin margins have long been recognized as
fluvial deposits (Swanson, 1979; Sonnenberg, 1985; Munson, 1989; Krystinikand Blakeney,
1990; Bowen et al., 1990; Al-Shaieb et al., 1995; Mckay and Noah, 1996; Puckette et al.,
1996; Bowen and Weimer, 2003, 2004; Devries 2005; Puckette et al., 2008; Gallagher, 2014).
At the Farnsworth Unit and similarly at the CFA, the Morrow B is described as a relatively
coarse-grained subarkosic sandstone and per depositional pathway. The upper Morrowan
facies, with sequences of basal conglomerate, coarse-grained sandstone, and fine-grained
sandstone appear to be typical of incised valley deposits, as described by Wheeler et al.
(1990), Krystinik and Blakeney (1990), Bowen et al. (1990), Blakeney et al. (1990),
Sonnenberg et al. (1990) and Puckette et al. (2008).

Primary Seals

The Morrow B sandstones are encased above and below by shales. Contacts with shale
both below and above the sandstone are sharp and irregular. The Morrow shale generally

8

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fines upwards in a series of thin beds that alternate between upper fine sands and fine to
medium muds. Sand content decreases upwards through the section.

The Thirteen Finger limestone formation has two different lithofacies: diagenetic limestone
(cementstone) and pyrite and fossil bearing fine to medium mudstone and coal. The two
facies are intercalated with each other but tend to cluster in layers dominated more by one
or the other.

2.2.2.2 Hydrogeology
Information about Morrowan and Atokan formation water flow during oil operations has
not been discovered in any oil or gas company published reports or academic research
studies in the Anadarko Basin. Groundwater flow rates in confined deep Anadarko layers at
present are considered to be low to no flow (Nelson and Gianoutsos, 2014). Their
arguments are based on (1) restricted recharge in the western basin, (2) density barriers to
flow in the east, and (3) an overpressure pocket inhibiting flow in the deep basin. Jorgenson
(1989) suggested flow could be west to east, driven by potential recharge to elevated units
in the west and discharge at lower elevation outcrops in the east. The CFA C02 injection and
production operations will not cause water to flow to outcrops of the Late Carboniferous
(Pennsylvanian) time period that extend from Brownwood, Texas, to the Jacksboro/Bowie,
Texas, area, which are hundreds of miles away (The Paleontology Portal).

2.3 Description of the Injection Process

Figure 2.3-1 depicts a simplified flow diagram of the facilities and equipment within the
boundaries of the CFA. C02 captured from the ethanol plant fermentation process is
delivered via pipeline to the field for injection. The Arkalon plant in Liberal, Kansas is the
only source of C02 to the field. The amount delivered is dependent on the production of
C02 produced from the fermentation process. This amount will vary but should average 12
MMCFD. Once C02 enters the CFA there are three main processes involved in EOR
operations. These processes are shown in Figure 2.3-1 and include:

1. C02 distribution and Injection. Purchased C02 is combined with recycled C02 from
the CFA central tank battery (CTB) and sent through the main C02 distribution
system to various water alternating gas (WAG) injectors.

2. Produced Fluids Handling. Full well stream fluids are produced to the "all well test"
(AWT) site. The AWT site has two major purposes; 1) to individually test a well's

-------
performance by separating and metering oil, gas and water, and 2) to separate all
gas from liquid then send these two phases to the CTB for final separation; while
only the gas from NPU is sent to the CTB the NPU oil and water remains in Texas.

3. Produced Gas Processing. All gases from the AWT sites are transferred to the CTB to
separate the oil, gas and water using a series of vessels and storage tanks.

C02 Miscible Reservoir

Production wells

Injection Wells

Produced Fluids -
Well Test Site / Injection C02/Water/0II

Arkalon Ethanol Plant
fermentation C02

CTB - Central Tank Battery

High Pressure C02 Injection System

C02

Figure 2.3-1 - Simplified flow diagram of the facilities arid equipment within the boundaries of the Camrick Field Area.

2.3.1 CO2 Distribution and injection
CapturePoint purchases CO2 from Conestoga Energy Partners, the parent company of the
Arkalon Ethanol plant located in Liberal, Kansas. A custody transfer meter is located in the
compression facility owned and operated by CapturePoint. The purchased CO?, from the
fermentation process is transported via a United States Department of Transportation (DOT)
regulated pipeline to the CFA. A totalizer meter, for the purchased CO2, is located in the field
where instantaneous data is summed into a 24-hour flow rate which is recorded. A totalizer
meter is a meter approved by the American Gas Association (AGA) Report #3 to measure the
flowrate of gases. The actual measurements taken are temperature, line pressure and
differential pressure across the meter. Gas produced, which contains recycled CO2, from the
wells is compressed and metered by a similar totalizer meter as the purchase CO2 meter and
is recorded daily.

CapturePoint currently has seven active injection manifolds and approximately 29 active
injection wells that the CO2 is distributed through, When the MRV plan becomes active, the
daily injection volume of the combined purchased CO2 and recycled C02 will be
approximately 24 MMCFD. Of this volume 12 MMCFD is purchased CO2 and 12 MMCFD is
recycled CO2. This ratio of purchased CO2 to recycled CO2 is expected to change over time,
with the percentage of recycled CO2 increasing and purchased CO2 decreasing. The current
reservoir management plan projects that CO2 purchases will remain constant at 12 MMCFD
for 12 years and decline after 2034. A reservoir management plan is an integrated process

-------
using various surveillance techniques, economic evaluations, and accepted petroleum
technical practices to efficiently operate enhanced oil recovery projects.

The seven injection manifolds currently in the field distribute the C02 to the field. These
manifolds have valves to switch to water when the time is called for. Depending on the
reservoir management plan the WAG cycle will be adjusted to maximize oil recovery and
minimize C02 utilization in each injection pattern. At each injection well pad there is a
totalizer to measure the volumes injected every 24 hours. This data is collected daily by the
field personnel and input into the data warehouse to be allocated for the pattern injection.

2.3.2 Produced Fluids Handling
As injected C02 and water migrate through the reservoir, a mixture of oil, gas and water
(referred to as "produced fluids") flows to the production wells. Gathering lines bring the
produced fluids from each production well to the AWT sites. CapturePoint has
approximately 32 active production wells producing at any time. Each AWT has two
separators. The first separator is used for testing individual wells to separate the gas, oil
and water produced from an individual well. This gas, oil and water is subsequently
measured and recorded for the well. Each producing well is production tested every 30 to
60 days after the last production test, or after the well is returned to production.

Depending on the reservoir management plan well testing can be more frequent to obtain
data. The second separator is used to separate the gas from the oil/water mixture from the
other wells producing into the AWT and the gas and liquids are displaced from the vessel in
separate lines. Leaving the AWT sites are two lines transporting produced fluids. One for
the liquid phase, a mixture of oil and water, and one for the gas phase. However, the AWT
in NPU does not transfer oil or gas to the CTB, it only transfers gas while reinjecting water
with pumps at the NPU AWT and sells oil at the NPU AWT.

When gas and liquid lines enter the CTB a series of vessels separate the oil, gas and water to
be accounted for and distributed for sales or reinjected. The liquid phase line has vessels to
separate the oil from the water using density and residence time. The gas phase vessels
collect any free liquids entrained with the gas. These free liquids are then combined back
into the liquid phase line. All gas and water are reinjected, and the oil, which contains an
estimated 2,360 ppm C02 (0.236%) for CU and 4,540 ppm C02 (0.454%) for NPU, is sold out
of tanks. Annually, the oil from the stock tank is analyzed by a laboratory using ASTM crude
oil analysis methods to determine the C02 content in the oil being sold.

-------
dissolved C02 in the water, analyses have shown the water typically contains <690 ppm
(0.069%) C02.

CFA production has trace amounts of hydrogen sulfide (H2S), which is toxic. There are
approximately 8-10 workers on the ground in the CFA at any given time, and all field and
contractor personnel are always required to wear H2S detectors. The primary purpose of
the H2S detectors is protecting people from the risk of being harmed. The detection limit of
the H2S detectors is quantified for readings in the range of 0-100 ppm and will sound an
alarm above 10 ppm. The secondary purpose of the H2S detectors would be to provide an
indication of emissions of gas from a pipeline or surface equipment, that might go unnoticed
by other observations or measurements. No gas volumes can be calculated based on the
detector reading or alarm; only a H2S leakage is detected and located. Once identified, a
further response will be initiated and C02 volumes will be quantified as discussed in sections
4.5, 4.6, 5.4 and 8.1.5 of this MRV plan.

2.3.3 Produced Gas Handling

Produced gas separated at the CTB is stripped by a series of vessels of entrained and free
water. The water content has been recorded to be < 20 pounds mass per MMCF, thus
dehydration is not necessary. The gas is then sent to a centralized compression system to
be compressed and placed in the high-pressure distribution system. This compression turns
the C02 into a variable density liquid, which is then transported out via high pressure lines to
the AWT sites where a manifold splits this dense C02 to the wells that are on C02 injection at
that time.

2.3.4 Facilities Locations

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2.3.5	Water Conditioning and Injection

Produced water collected at the CTB is collected in a series of vessels and tanks in a cascade
system. This allows any entrained oil to further separate to the top of the tanks because of
the density difference and is skimmed off and put back in the oil separation system. The
clean water is then transferred to the water injection system where it is boosted in pressure
and sent out to the AWT sites for distribution to all wells that are currently on water
injection.

2.3.6	Well Operation and Permitting

The Oklahoma Conservation Commission and Texas Railroad Commission rules (Appendix 2)
govern well location, construction, operation, maintenance, and closure for all wells in
permitted units and wells. CapturePoint follows these rules and regulations to maintain
safe and efficient operations. This includes complying with all current and updated
information for mechanical integrity testing, well repairs for injection wells, drilling and
completion permitting and reporting.

Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered.

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water.

•	That wells adhere to specified casing, cementing, drilling well control, and completion
requirements designed to prevent fluids from moving from the strata they are
encountered into strata with oil and gas, or into subsurface and surface waters.

13

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• That wells file a completion report including basic electric log (e.g., a density, sonic, or
resistivity (except dip meter) log run over the entire wellbore).

• That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and address
any instances where pressure on the Bradenhead is detected.

And that all wells follow plugging procedures that require advance approval from the
Director and allow consideration of the suitability of the cement based on the use of the
well, the location and setting of plugs.

2.3.7 Number, Location and Depth of Wells
CapturePoint's CFA injection wells are listed in Appendix 1. Injection is into the Upper
Morrowan, a lenticular bedded sandstone trending northwest to southeast with the average
top of sand at 7250 feet, true vertical depth. The Upper Morrowan is described in section
2.2.2.1 above.

2.4 Reservoir Characterization

2.4.1 Reservoir Description
The target reservoir CFA Morrow B is a sandstone formation overlain by the Morrow shale
and Thirteen Finger limestone, which serve as excellent seals for injected C02 as determined
by Farnsworth data (Ampomah et al., 2016a). The Morrow B sandstone reservoir is at a
depth between 6800 feet and 7600 feet subsurface with an average dip of less than one
degree (Figure 2.4-1). The productive limit of the CFA is about 80 to 90 percent of the total
operated surface acreage, which is 14,652.315 acres. The maximum pay thickness is 56 feet
with an average of 15 feet and does diminish to zero in spots.

The CFA is approximately 8 mi by 7 mi that have areas that exhibit different reservoir
behavior. The southwest portion of CU was most prolific oil producer under primary and
secondary production whereas the western portion of NPU is now responding to C02 better
than historical operations would have indicated.

-------
Figure 2.4-1- (Left) Type log ofCFA caprock and reservoir. (Upper Right) Surface contour of Morrow top.
(Lower right) Thickness map of Morrow sands.

2.4.2 Reservoir Fluid Modeling
The compositional fluid model was constructed for the CapturePoint operated Farnsworth
Unit. From laboratory compositional analysis an equation of state was tuned (Gunda et al.,
2015). The minimum miscibility pressure (MMP) experiment was then simulated using a
one-dimensional model (Figure 2.4.3). The simulated Farnworth Unit MMP of 4009 psia
compared to an MMP value of 4200 psia derived from laboratory experiments provided by
the operator represents a less than 5% error (Gunda et al., 2015).

The reservoir temperature in the CFA is 152 degrees Fahrenheit or 16 degrees lower than
the temperature at Farnsworth Unit of 168 degrees. Using parameters of the Alston
empirical correlation (1985), the MMP would be 170 psia lower at the CFA or 3510 psia
compared to 3680 psia at the Farnsworth Unit (Figure 2.4.4).

-------
Oil recovery vs Pressure

Pressure (psia)

Recovery at 1W.00 *f

Figure 2.4-4. Oil recovery plot for ID slim tube test for Farnswoth Unit.

2.4.3 CO2 Analogy Field Study

Based on similar geologic, petrophysical, engineering and operational parameters between
the Farnsworth Unit and the CFA, the oil recovery performance of both fields is expected to
be similar. Due to the stratigraphic nature of the Morrow channel sands, the potential
movement of CO2 is severely limited. The CFA area has contained the free phase CO2 plume
in a very confined area since March 2001 as exhibited by oil, water and CO2 recovery
performance. Also, no production performance exists which indicates any plume will move
outside of the M MA at the end of year t + 5, per §98.449 definitions.

2.4.4 CO2- EOR Performance Projections

For years the oil industry has used dimensionless equations to predict the amount of oil that
can be recovered using CO2 for flooding oil reservoirs (Lee et al, 2018, Stell 2010). The
amount of oil recovered from projects is plotted as a decimal fraction of the original-oil-in-
place versus the decimal fraction of the hydrocarbon pore volume (HPV) of CO2 injected into
the oil reservoir as measured in reservoir barrels (RB).

The CFA has been injecting CO2 since March 2001. The dimensionless curves were matched
to historical performance through early 2020. (Figure 2.4.5) The supply of CO2 was curtailed
from March 2020 until present, due to oil price uncertainty, and will resume after the
Arkalon Plant upgrade that will be finished in the 4th quarter of 2022.

-------
Camrick/N Perryton Forecast Type Curve

Camrick/N Perryton Forecast Type Curve

100000

Figure 2.4-5- Dimensionless curves for C02 injection (left) with rate time curves (right).

The dimensionless water oil ratio and the gas oil ration trends (Figure 2.4.6) for the CFA
flooded acreage are very similar to what was forecasted by simulation in the Farnsworth
Field as expected because of the porosity, permeability, and sand similarities.

Camrick/N Perryton Forecast Type Curve

100
90

so

" — ^ "	-i

1/V2001 1/3/200S 1/1/2009 1/1/2013 1/1/2017 1/1/2021 1/1/2CBS 1/1/2029 1/1/2033 1/3/203/

Figure 2.4-6- Dimensionaiess water cut and GOR vs. observed EOR data.

The CO2 storage volumes for Arkalon fermentation CO2 were also forecasted (Figure 2.4.7)
using the same dimensionless technique and indicates that the flooded acreage still has
significant additional storage potential. The maximum CO2 storage is limited to the amount
of space available by the removal of the produced oil and should have room to store
approximately 0.4 to 0.5 decimal fraction of HPV amounting to 30 to 40 MMB.

17

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Figure 2.4-7- Dimensionless C02 Fermentation Curves (Left) vs C02 Fermentation Volume (Right)

3 Delineation of Monitoring Area

3.1 MMA

As defined in Subpart RR, the maximum monitoring area (MMA) is 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. The purchase volumes that are
displayed in figure 2.4.7 were mapped and are displayed in Section 3.1.1 indicates that CO2
storage pore space is available, barring unforeseen future operational issues. Therefore,
CapturePoint is defining the MMA as the boundary of the CFA plus an additional one-half
mile buffer zone. This will allow for operational expansion throughout the CFA for the next
12 years, the anticipated life of the project.

3.1.1 Determination of Storage Volumes

Figure 3.1-1 displays the existing 4800 acres in the CFA that has been injecting CO2 since
March 2001. The volume of the oil recovered since August 1955, resulted in a voidage space
of 36 MMscf of C02 per acre of surface area that was later filled with water during
waterflood. The average decimal fraction of CO2 injection to hydrocarbon pore volume left
in the ground after accounting for CO2 production through 2021 is 0.29. The lateral extent
of CO2 in the injection zone or the CO2 storage radius for each well was estimated based on
cumulative CO2 injected times the decimal fraction of CO2 remaining divided by the voidage
space. The largest C02 storage areas are around wells that injected C02 for the most years.

Figure 3.1.2 displays the potential area of the reservoir that can be filled with CO2 with the
existing injection wells. This assumed that only 78 percent of the average injection pattern
area or 80 acres could be filled. There are 49 injectors identified for further injection that
have room for an additional 90 Bscf or CO2 storage or 140 Bscf total space.

-------
| NW (^AMRICK UNIT |

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Figure 3.1.1 Estimated C02 storage as of 2021 in CFA

Figure 3.1.2 Potential Total C02 Storage in the CFA

3.1.2 Determination of Buffer Zone
CapturePoint intends to implement a buffer zone of one-half mile around the CFA, the
minimum required by Subpart RR, because the site characterization of the Morrow did not
reveal any leakage pathways that would allow free-phase C02 to migrate laterally thereby
warranting a buffer zone greater than one-half mile.

19

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3.2 AMA

Currently, CapturePoint's operations are focused in the western portion of the CFA.
However, it is anticipated as the project develops, additional activity will occur in the NWCU
of the CFA; therefore, requiring active monitoring in that area. However, project
development is driven by the market price of oil so CapturePoint is unable to provide a
specific time in the future when the eastern portion of the CFA will be actively monitored.
Therefore, for the purposes of this MRV plan, CapturePoint has chosen to include the entire
CFA in the AMA.

4 Identification and Evaluation of Leakage Pathway

Since its discovery in 1955, the unitization of the different units from 1969 to 1972, and the
commencement of C02 EOR in 2001; the CFA is an analogous field to the Farnsworth Unit, which has
undergone extensive investigation and documentation as indicated in Section 2. From this body of
work, CapturePoint has identified the following potential pathways of C02 leakage to the surface. This
section will also address detection, verification, and quantification of leakage from each pathway.

4.1 Leakage from Surface Equipment

The surface equipment and pipelines utilize materials of construction and control processes that
are standard in the oil and gas industry for C02 EOR projects. Ongoing field surveillance of
pipelines, wellheads and other surface equipment via personnel instructed on how to detect
surface leaks and other equipment failure minimizes releases. In addition, requirements of the
Oklahoma Conservation Commission (OCC) rules and the Texas Administrative Code (TAC) rules for
the Texas Railroad Commission (TRRC) Oil and Gas Division to report and quantify leaks, both serve
to minimize leakage of GHG from surface equipment. Operating and maintenance practices
currently follow and will continue to follow demonstrated industry standards. As described in
Section 6.4 below, should leakage from surface equipment occur it will be quantified according to
the procedures in Subpart W of the GHGRP.

4.2 Leakage from Wells

4.2.1 Abandoned Wells

Figure 4.2-1 shows all wells plugged and abandoned in the CFA. Because the CFA was
unitized in 1969 to 1972, all plugging and abandonment activities of wells within the CFA
have been conducted under the regulations of the OCC and the TRRC for plugging wells.
CapturePoint concludes that leakage of C02 to the surface through abandoned wells is
unlikely. However, strategies for leak detection are in place that are discussed in Section 4.5
and the strategy to quantify the leak is discussed in Section 4.6.

-------
Figure 4.2-1 Plugged and Abandoned Wells in the CFA

4.2.2 Injection Wells

Mechanical integrity testing (MIT) is an essential requirement of the Underground Injection
Control (UIC) program in demonstrating that injection wells themselves do not act as
conduits for leakage into underground sources of drinking water (USDWs) and to the surface
environment. Rule 46 and any special conditions pertaining to mechanical integrity testing
required by the OCC and the TRRC are included in the Class II permits issued to
CapturePoint, ensure that active injection wells operate to be protective of subsurface and
surface resources and the environment. Figure 4.2-2 shows the active injection wells in the
CFA. CapturePoint concludes that leakage of C02 to the surface through active injection
wells is unlikely.

21

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4.2.3 Production Wells

Figure 4.2-3 shows the active oil production wells in the CFA. However, as the project
develops in the CFA additional production wells may be added and will be constructed
according to the relevant rules of the OCC and the TRRC. Additionally, inactive wells may
become active according to the rules of the OCC and the TRRC. CapturePoint concludes that
leakage of C02 to the surface through production wells is unlikely.











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Figure 4.2-3 Active Oil Production Wells in the CFA

22

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4.2.4 Inactive Wells

Figure 4.2-4 shows all of the inactive wells in the CFA. The OCC has regulations for
temporally abandoned/not plugged (TA) and terminated order wells/UIC not plugged (TM)
and likewise the TRRC has regulations for inactive wells.

CapturePoint LLC

CAMRICK

Figure 4.2-4 Inactive wells in the CFA

4.2.5 New Wells

As the project develops, new production wells and injection wells may be added to the CFA.
All new wells will be constructed according to the relevant rules for the OCC and the TRRC
which ensure protection of subsurface and surface resources and the environment.

All wells in Oklahoma oilfields and all wells in Texas oilfields, including both injection and
production wells, are regulated by the OCC and the TRRC, respectively, which has primacy to
implement the UIC Class II programs.

Rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Briefly current rules require, among other provisions:

•	That fluids be constrained in the strata in which they are encountered;

•	That activities governed by the rule cannot result in the pollution of subsurface or
surface water;

•	That wells adhere to specified casing, cementing, drilling well control, and
completion requirements designed to prevent fluids from moving from the strata
they are encountered into strata with oil and gas, or into subsurface and surface
water;

23

-------
•	That wells file a completion report including basic electric logs;

•	That all wells be equipped with a Bradenhead gauge, measure the pressure between
casing strings using the Bradenhead gauge, and follow procedures to report and
address any instances where pressure on the Bradenhead is detected;

•	And that all wells follow plugging procedures that require advance approval from
the Regulators and allow consideration of the suitability of the cement based on the
use of the well, the location and setting of plugs.

New well construction is based on existing best practices, established during the drilling of
existing wells in CFA and follows the OCC and the TRRC rules, which significantly limits any
potential leakage from well pathways. Additionally, the existing wells followed the OCC and
the TRRC rules.

In public databases, the area of CFA plus one mile past the unit boundary contains over 100
wells that were drilled deeper than the Morrow formation and none of these wells were
productive in reservoirs deeper than the Morrow. Therefore, it is very unlikely that anyone
will ever drill through the AMA reservoir in the future. In the event a well is drilled within
the AMA, the operator would be required to follow all the OCC and the TRRC rules and
procedures in the drilling the well and the potential for leakage would be similar to any well
that CapturePoint drills within the AMA. In addition, CapturePoint's visual inspection
process during routine field operation will identify any unapproved drilling activity in the
CFA.

4.3 Leakage from Faults and Bedding Plane Parting

Primary seals at CFA have been demonstrated to be mechanically very competent (see
Section 2.2.2), thus the main concern of C02 migration at CFA is via seal bypass systems
along fracture networks. The following lines of analysis have been used to assess this risk in
the area.

4.3.1	Prescence of Hydrocarbon

The first and foremost argument against present day up-fault transmissibility is the 75 MMB
of oil that was found trapped in the reservoir. If significant escape pathways existed, oil
would have drained from the reservoir prior to the current day.

4.3.2	Fracture analysis

At the CFA the work done at the Farnsworth Unit is analagous, where small aperture
fractures were noted but not common in most of the reservoir cores examined but most of
these fractures appear to be drilling induced. Fractures in the Thirteen Finger limestone
caprock were described using an industry-standard format for fracture class type,
orientation, fracture dip, type of mineral fill, fracture porosity, fracture spacing, and
intensity. Again, drilling induced fractures are most common. Natural mineral-filled
fractures are quite rare, were formed during diagenesis at shallow depths, and are of Late

24

-------
Carboniferous age. Unless significantly damaged by large changes in reservoir pressure they
are highly unlikely to provide migration pathways.

In the unlikely event C02 leakage occurs as a result of leakage through the faults and
fractures it is unlikely that the leak would result in surface leakage. As with any C02 leakage,
CapturePoint has strategies for leak detection in place that are discussed in Section 4.5 and
the strategy to quantify the leak is discussed in Section 4.6.

4.4 Lateral Fluid Movement

The Morrow strata in the Oklahoma and Texas Panhandle was primarily a deltaic sequence
that prograded toward the southeast, resulting in deposition of mainly shales with
lenticular, discontinuous coarse sandstones separated with very fine sandstone, minor
conglomerates and shale. The likelihood of any extensive migration of fluid outside of the
AMA is very low.

Since C02 is lighter than the water remaining in the reservoir it will migrate to the top of
each lenticular structure as it is filled. The producing wells, which create low pressure points
in the field, will drain the water and keep the C02 within each discontinuous sandstone.

4.5 Leakage through Confining/Seal system

At the CFA the work done at the Farnsworth Unit will apply, where a variety of analytical
methods were used for caprock (confining system) analysis, and the results should be the
same for the CFA. Petrologic examination included standard thin section petrography and
backscattered electron microscopy. Petrophysical analytical methods include retort
analysis, pulse-decay permeability measurement, pressure decay permeability analysis for
tight rocks, and mercury injection porosimetry, which is also known as mercury injection
capillary pressure (MICP). Geomechanical analysis involved a standard series of mechanical
tests: Brazil tension, unconfined compression, triaxial compression, and multi-stress
compression.

Results of the MICP analysis show that the mudstone lithologies in the Morrow Shale and
Thirteen Finger Limestone can support C02 column heights of ~1,000 to 10,000 feet. At an
order of magnitude over the thickness of the Morrow reservoir, this should prove an
effective seal for C02 storage in the Morrow B injection horizon.

Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so
that any fracture initiation around the injection well would not be expected to propagate
into the overlying sealing units. Mechanical properties of the overlying shale and limestones
provide an interesting and effective combination of strength and elasticity. Limestone
layers are strong but brittle, while the shale layers are weaker but sufficiently ductile to
prevent extensive fracture propagation.

It is unlikely for hydrocarbon migration pathways that charged the Morrow reservoir to be
potential C02 migration pathways via primary pore networks today. Any potential C02
migration would be most likely due to leakage from wellbores or bypass through fault and
fracture networks, discussed in Sections 4.2 and 4.3.

-------
In the unlikely event CO2 leakage occurs as a result of leakage through the confining seal it is
unlikely that the leak would result in surface leakage. As with any CO2 leakage,

CapturePoint has strategies for leak detection in place that are discussed in Section 4.5 and
the strategy to quantify the leak is discussed in Section 4.6.

4.6 Natural and Induced Seismic Activity

Figure 4.6 shows the map of earthquakes with magnitudes measured at greater than 2.5 as
defined by the United States Geological Survey (LJSGS). While past earthquake data cannot
predict future earthquakes, the small number of events near CFA after the waterflood
operations were initiated in 1969 implies the area is not seismically sensitive to injection.
Also, no documentation exists that any of the distant earthquake events caused a disruption
in injectivity or damage to any of the wellbores in CFA.

Kansa:

ueblo

Garden Qty

Dodge City

Liberal

Wichita Falls

Lubbock

Figure 4.6: USGS earthquakes (+2.5 magnitude) for last 40 years with CFA highlighted red

There is no direct evidence that natural seismic activity poses a significant risk for loss of CO2
to the surface in the CFA.

26

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In the unlikely event that induced seismicity resulted in a pathway for material amounts of
C02 to migrate from the injection zone, other reservoir fluid monitoring provisions (e.g.,
reservoir pressure, well pressure, and pattern monitoring) would lead to further
investigation.

4.7 Strategy for Detection and Response to CO2 loss

As discussed above, the potential sources of leakage include fairly routine issues, such as
problems with surface equipment (pumps, valves, etc.) or subsurface equipment (well
bores), and unique events such as induced fractures. Table 1 summarizes some of these
potential leakage scenarios, the monitoring activities designed to detect those leaks,
CapturePoint's standard response, and other applicable regulatory programs requiring
similar reporting.

The potential C02 losses discussed in the table are identified by type. Once the type is
reported to a response manager the correct resources and personnel can be mobilized to
develop the optimal response procedure. The procedure will address and mitigate further
C02 leakage.

Table 1 Response Plan for C02Loss

Known Potential Leakage Risks

Monitoring Methods and Frequency

Anticipated Response Plan

Tubing Leak

Monitor changes in annulus pressure; MIT for
injectors

Workover crews respond within days

Casing Leak

Weekly field inspection; MIT for injectors;
extra attention to high-risk wells

Workover crews respond within days

Wellhead Leak

Weekly field inspection

Workover crews respond within days

Loss of Bottom-hole pressure
control

Blowout during well operations (weekly
inspection but field personnel present daily)

Maintain well kill procedures

Unplanned wells drilled through
Morrow

Weekly field inspection to prevent
unapproved drilling; compliance with TRRC
permitting for planned wells.

Assure compliance with TRRC regulations

Loss of seal in abandoned wells

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Re-enter and reseal abandoned wells

Pumps, values, etc.

Weekly field inspection

Workover crews respond within days

Leakage along faults

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near faults

Leakage laterally

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Fluid management along lease lines

Leakage through induced fractures

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Comply with rules for keeping pressures
below parting pressure

Leakage due to seismic event

Continuous monitoring of pressure in WAG
skids; high pressure found in new wells as
drilled

Shut in injectors near seismic event

4.8 Strategy for Quantifying CO2 loss

Major C02 losses are typically event-driven and require a process to assess, address, track,
and if applicable, quantify potential C02 leakage to the surface. CapturePoint will reconcile

27

-------
the Subpart W report and results from any event-driven quantification to assure that
surface leaks are not double counted.

Given the uncertainty concerning the nature and characteristics of leaks that will be
encountered, it is not clear the method for quantifying the volume of leaked C02 that would
be most appropriate. In the event leakage occurs, CapturePoint will determine the most
appropriate method for quantifying the volume leaked and will report the methodology
used as required as part of the annual Subpart RR submission.

Any volume of C02 detected leaking to the surface will be quantified using acceptable
emission factors such as those found in 40 CFR Part 98 Subpart W or engineering estimates
of leak amounts based on measurements in the subsurface, CapturePoint's field experience,
and other factors such as the frequency of inspection. As indicated in Sections 6.4, leaks will
be documented, and the records of leakage events will be retained in the electronic
environmental documentation and reporting system. Repairs requiring a work order will be
documented in the electronic equipment maintenance system.

Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02
geysers) suggest that the amount released from routine leaks would be small as compared
to the amount of C02 that would remain stored in the formation.

5 Strategy for Determining CO2 Baselines for CO2 Monitoring

Atmospheric C02 concentrations from the Moody, Texas station can be used for background C02
values for soil measurement in the CFA area, per the characterization, monitoring and well data
collected by the Southwest Regional Partnership on Carbon Sequestration (SWP) in the analogous
Farnsworth Unit.

5.1 Site Characterization and Monitoring

As described in Sections 2.2.2 and 2.4, the Morrow B sandstone is isolated both above and
below by shale units of the Morrow. The primary seal consists of 180 - 200 ft of Morrow
shale and Thirteen Finger Limestone which in turn is overlain by over a thousand feet of
younger shale and limestone. These units provide a suitable seal to prevent the migration
of C02 out of the injection reservoir. Additionally, no significant faults or fracture zones that
cut across the seal units have been identified in the CFA, indicating that the most likely
leakage pathway is from legacy wellbores that have been poorly completed/cemented.

5.2 Groundwater monitoring

CapturePoint does not routinely pull water samples from the Ogallala water wells.

However, samples are pulled when OCC injection permits are submitted in Oklahoma. No
indication of fluid leakage has been identified from any of these in the CFA area.
CapturePoint is unlikely to continue monitoring USDW wells for C02 or brine contamination,
as characterization of the Morrow (see section 5.1) have suggested minimal risk of
groundwater contamination from C02 leakage from this depth.

-------
5.3 Soil CO2 monitoring

Atmospheric C02 values at the Farnsworth Unit have been determined by a SWP eddy tower
installation. In winter 2019, the eddy system malfunctioned and has not been repaired due
to COVID travel restrictions. However, the atmospheric C02 concentration data from the
eddy tower were in very good agreement with values obtained from the NOAA Global
Monitoring Laboratory station in Moody, Texas (Station: WKT). Since the CFA area is in close
proximity to the Farnsworth Unit, atmospheric C02 concentrations from the Moody, Texas
station can be used for background C02 values.

5.4 Visual Inspection

CapturePoint operational field personnel visually inspect surface equipment daily and report
and act upon any event indicating leakage.

5.5 Well Surveillance

CapturePoint adheres to the requirements of Rule 165:10-5 for the OCC and of Rule 46 for
the TRRC governing fluid injection into productive reservoirs. Rule 46 includes requirements
for monitoring, reporting, and testing of Class II injection wells. Furthermore, the OCC and
the TRRC includes special conditions regarding monitoring, reporting, and testing in the
individual permits for each injection well if they are deemed necessary.

CapturePoint also adheres to the requirements of Rule 165:10-7 for the OCC and of Rule 20 for the TRRC
governing the notification of fires, breaks, leaks, or escapes. Rule 20 requires that all operators report leaks to
the OCC or the TRRC including measured or estimated quantities of product leaked.

6 Site specific considerations for determining the Mass of CO2
Sequestered

Of the twelve RR equations in 98.443 of Subpart RR, the following are relevant to CapturePoint's
operations

6.1 Determining Mass of CO2 received

CapturePoint currently receives C02 to its CFA facility through their own pipeline from theArkalon Ethanol
plant in Liberal, Kansas. CapturePoint also recycles C02from their production wells in the CFA.
C02Tr = Y*p=i(Qr,P ~ Sr,P) * D * cco2iPr (Equation RR-2)
where:

C02T,r = Net annual mass ofC02 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).

STjp = 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 ofC02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

CCq2 pr = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent C02,

expressed as a decimal fraction),
p = Quarter of the year.
r= Receiving flow meter.

-------
6.2	Determining Mass of CO2 Injected
CapturePoint injects C02 into the injection wells listed in Appendix 1.

C02m = Zp=i QP,u * D * cco2V:U (Equation RR-5)

where:

C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.

Qpu= Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).

D = Density ofC02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

CCo2 pu = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent C02, expressed

as a decimal fraction),
p = Quarter of the year,
u = Flow meter.

6.3	Determining Mass of CO2 produced from Oil Wells

CapturePoint also recycles C02from its production wells which are part of its operations in the CFA.

Therefore, the following equation is relevant to its operations.

C02,w = Ep=1 QPjW * D * CCo2 p w (Equation RR-8)

Where:

C02,w = Annual C02 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 ofC02 at standard conditions (metric tons per standard cubic meter): 0.0018682.

CCq2 pw = C02 concentration measurement in flow for separator w in quarter p (vol. percent C02, expressed

as a decimal fraction),
p = Quarter of the year.
w= Separator.

To aggregate production data, CapturePoint will sum the mass of all of the C02 separated at each gas-liquid
separator in accordance with the procedure specified in Equation RR-9 below:

C02P = (1 + X) * Zw=i c°2,w (Equation RR-9)

Where:

C02P = Total annual C02 mass produced (metric tons) through all separators in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.

X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators in the
reporting year (weight percent C02, expressed as a decimal fraction).
w= Separator.

6.4	Determining Mass of CO2 emitted by Surface Leakage

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant surface
equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233 (r) (2) of Subpart W, the
emissions factor listed in Table W-1A of Subpart W shall be used to estimate all streams of gases, including
recycle C02 stream, for facilities that conduct EOR operations.

CapturePoint will calculate the total annual mass ofC02 emitted from all leakage pathways in accordance
with the procedure specified in Equation RR-10 below:

C02E= Y%=1C02 x (Equation RR-10)
where:

C02e = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.

30

-------
C02x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.

6.5 Determining Mass of CO2 sequestered

The following Equation RR-11 pertains to facilities that are actively producing oil or natural gas.

C02 = C02I — C02P — C02E — C02FI — C02FP (Equation RR-11)

Where:

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility in the
reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the reporting year.

C02P = Total annual C02 mass produced (metric tons) in the reporting year.

C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.

C02fi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions ofC02

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 the GHGRP.

C02Fp = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions ofC02

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 the GHGRP.

The following Equation RR-12 pertains to facilities that are not actively producing oil or natural gas. This

equation may become relevant to CapturePoint's operation as it evolves in the future. However, this does not

apply to CapturePoint's current operations.

C02 = C02I — C02E — C02FI (Equation RR-12)

C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility in the
reporting year.

C02I = Total annual C02 mass injected (metric tons) in the well or group of wells in the reporting year.
C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.

C02pi = Total annual C02 mass emitted (metric tons) from equipment leaks and vented

emissions of C02 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 the GHGRP.

7	Estimated Schedule for Implementation of MRV plan

CapturePoint expects to begin implementing the approved MRV plan when the new C02 capture facility
is operational, November 1, 2022.

8	GHG monitoring and Quality Assurance Program

CapturePoint will meet the monitoring and QA/QC requirements of 98.444 of Subpart RR including those
of Subpart W for emissions from surface equipment as required by 98.444 (d).

8.1 GHG monitoring

As required by 40 CFR 98.3(g)(5)(i), CapturePoint's internal documentation regarding the collection of
emissions data includes the following:

• Identification of positions of responsibility (i.e., job titles) for collection of the emissions
data.

31

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• Explanation of the processes and methods used to collect the necessary data for the
GHG calculations.

8.1.1 General

Measurement of CO? Concentration - All measurements of C02 concentrations of any C02 quantity will
be conducted according to an appropriate standard method published by a consensus-based standards
organization or an industry standard practice such as the Gas Producers Association (GSA) standards.
Measurement of CO? Volume - All measurements of C02 volumes will be converted to the following
standard industry temperature and pressure conditions for use in Equations RR-2, RR-5 and RR-8 of
Subpart RR of the GHGRP: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an
absolute pressure of 1 atmosphere. CapturePoint will adhere to the American Gas Association (AGA)
Report #3 - (ORIFICE METERING OF NATURAL GAS AND OTHER RELATED HYDROCARBON FLUIDS)

8.1.2 CO2 Received

Daily totalized volumetric flow meters are used to record C02 received via pipeline from the Arkalon
ethanol plant in Liberal, Kansas, using a volumetric totalizer using accepted flow calculations for C02
according to the AGA Report #3.

8.1.3 CO2 Injected

Daily C02 injection is recorded by combining the totals for the recycle compressor meter and the
received C02 meter from Arkalon based on what's delivered on a 24-hour basis. This data is taken from
the meter daily and stored in CapturePoint's data warehouse for records and reservoir management.

8.1.4 CO2 Produced

The point of produced gas measurement is from a meter downstream of the compressors prior to being
combined with purchase C02. The produced gas is sampled at least quarterly for the C02 content.

8.1.5 CO2 emissions from equipment leaks and vented emissions of CO2

As required by 98.444 (d), CapturePoint will follow the monitoring and QA/QC requirements specified in
Subpart W of the GHGRP for equipment located on the surface between the flow meter used to
measure injection quantity and the injection wellhead and between the flow meter used to measure
production quantity and the production wellhead.

As required by 98.448 (d) of Subpart RR, CapturePoint will assess leakage from the relevant surface
equipment listed in Sections 98.233 and 98.234 of Subpart W. According to 98.233 (r) (2) of Subpart W,
the emissions factor listed in Table W-1A of Subpart W shall be used to estimate all streams of gases,
including recycle C02 stream, for facilities that conduct EOR operations. The default emission factors for
production equipment are applied to the carbon capture utilization and storage (CCUS) injection
operations reporting under Subpart RR.

8.1.6 Measurement Devices

As required by 40 CFR 98.444(e), CapturePoint will ensure that:

• All flow meters are operated continuously except as necessary for maintenance and
calibration.

• All flow meters used to measure quantities reported are calibrated according to the
calibration and accuracy requirements in 40 CFR 98.3(i) of Subpart A of the GHGRP.

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• All measurement devices are operated according to an appropriate standard method
published by a consensus-based standards organization 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 Gas Producers Association (GPA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and
the North American Energy Standards Board (NAESB).

• All flow meters are National Institute of Standards and Technology (NIST) traceable.

8.2 QA/QC procedures

CapturePoint will adhere to all QA/QC requirements in Subparts A, RR, and W of the GHGRP, as required in the
development of this MRV plan under Subpart RR. Any measurement devices used to acquire data will be
operated and maintained according to the relevant industry standards.

8.3 Estimating missing data

CapturePoint will estimate any missing data according to the following procedures in 40 CFR 98.445 of
Subpart RR of the GHGRP, as required.

A quarterly flow rate ofC02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.

A quarterly C02 concentration of a C02 stream received that is missing would be estimated using invoices or
using a representative concentration value from the nearest previous time period.

A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity of C02
injected from the nearest previous period of time at a similar injection pressure.

For any values associated with C02 emissions from equipment leaks and vented emissions ofC02from surface
equipment at the facility that are reported in this subpart, missing data estimation procedures specified in
subpart W of 40 CFR Part 98 would be followed.

The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.

8.4 Revisions of the MRV plan

CapturePoint will revise the MRV Plan as needed to reflect changes in production processes, monitoring
instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and
repair of monitoring systems to reduce the frequency of monitoring equipment downtime.

9 Records Retention

CapturePoint will meet the recordkeeping requirements of paragraph 40 CFR 98.3 (g) of Subpart A of the
GHGRP. As required by 40 CFR 98.3 (g) and 40 CFR 98.447, CapturePoint will retain the following
documents:

(1) A list of all units, operations, processes, and activities for which GHG emissions were calculated.

(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity. These
data include:

(i) The GHG emissions calculations and methods used.

(ii) Analytical results for the development of site-specific emissions factors, if applicable.

(iii) The results of all required analyses.

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(iv) Any facility operating data or process information used for the GHG emission calculations.

(3) The annual GHG reports.

(4) Missing data computations. For each missing data event, CapturePoint will retain a record of the
cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment.

(5) A copy of the most recent revision of this MRV Plan.

(6) The results of all required certification and quality assurance tests of continuous monitoring systems,
fuel flow meters, and other instrumentation used to provide data for the GHGs reported.

(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation
used to provide data for the GHGs reported.

(8) Quarterly records of C02 received, including mass flow rate of contents of container (mass or
volumetric) at standard conditions and operating conditions, operating temperature and pressure, and
concentration of these streams.

(9) Quarterly records of produced C02, including mass flow or volumetric flow at standard conditions
and operating conditions, operating temperature and pressure, and concentration of these streams.

(10) Quarterly records of injected C02 including mass flow or volumetric flow at standard conditions and
operating conditions, operating temperature and pressure, and concentration of these streams.

(11) Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.

(12) Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.

(13) Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02from equipment located on the surface between the production wellhead and the flow
meter used to measure production quantity.

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

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10 Appendices

Appendix 1 - CFA Wells

Table Al.l - Production Wells

Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 2112

35007353570000

Oi

Prod

Active

6

u

1

0

CU 2171

35007354120000

Oi

Prod

Active

n
O

1

0

CU 2173

35007354140000

Oi

Prod

Active

C02

1

0

CU 2177

35007222340000

Oi

Prod

Active

n
O

1

0

CU 2272

35007224530000

Oi

Prod

Active

C02

1

0

CU 2651

35007362650000

Oi

Prod

Active

n
O

1

0

CU 2731

35007359750000

Oi

Prod

Active

n
O

1

0

CU 2761

35007350590000

Oi

Prod

Active

n
O

1

0

CU 2853

35007250840000

Oi

Prod

Active

C02

1

0

CU 2854

35007250850000

Oi

Prod

Active

n
O

1

0

CU 2971A

35007256700000

Oi

Prod

Active

C02

1

0

CU 2973

35007213750000

Oi

Prod

Active

n
O

1

0

CU 2975

35007223730000

Oi

Prod

Active

C02

1

0

CU 3111

35007350600000

Oi

Prod

Active

n
O

1

0

CU 3113

35007359460000

Oi

Prod

Active

C02

1

0

CU 3115

35007251710000

Oi

Prod

Active

n
O

1

0

CU 3116

35007252570000

Oi

Prod

Active

O
O

1

0

CU 3143

35007250860000

Oi

Prod

Active

n
O

1

0

CU 3171

35007359600000

Oi

Prod

Active

o
u

1

0

CU 3182

35007249250000

Oi

Prod

Active

n
O

1

0

CU 3211

35007352150000

Oi

Prod

Active

C02

1

0

CU 3212

35007352690000

Oi

Prod

Active

n
O

1

0

CU 3231

35007001820000

Oi

Prod

Active

C02

1

0

CU 3232

35007352720000

Oi

Prod

Active

n
O

1

0

CU 3234

35007212010000

Oi

Prod

Active

o
u

1

0

CU 3261

35007352170000

Oi

Prod

Active

n
O

1

0

CU 3263

35007251640000

Oi

Prod

Active

C02

1

0

CU 3271

35007352160000

Oi

Prod

Active

n
O

1

0

CU 3273

35007252580000

Oi

Prod

Active

C02

1

0

CU 3274

35007253140000

Oi

Prod

Active

n
O

1

0

CU 3275

35007254040000

Oi

Prod

Active

o
o

1

0

CU 3312

35007360800000

Oi

Prod

Active

n
O

1

0

CU 3313

35007254370000

Oi

Prod

Active

co2

1

0

CU 3314

35007254030000

Oi

Prod

Active

n
O

1

0

CU 3332

35007254020000

Oi

Prod

Active

o
o

1

0

CU 3381

35007360780000

Oi

Prod

Active

n
O

1

0

CU 3411

35007351700000

Oi

Prod

Active

O
O

1

0

-------
Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 3412

35007351720000

Oil

Prod

Active

C02

1

0

CU 3413

35007351730000

Oil

Prod

Active

C02

1

0

CU 3414

35007005220000

Oil

Prod

Active

C02

1

0

CU 3415

35007211170000

Oil

Prod

Active

C02

1

0

CU 3416A

35007252590000

Oil

Prod

Active

C02

1

0

CU 3451A

35007256710000

Oil

Prod

Active

C02

1

0

CU 3471

35007351750000

Oil

Prod

Active

C02

1

0

CU 3481

35007351710001

Oil

Prod

Active

C02

1

0

CU 3491

35007254330000

Oil

Prod

Active

C02

1

0

CU 3533

35007206880000

Oil

Prod

Active

C02

1

0

CU 3562

35007255050000

Oil

Prod

Active

C02

1

0

NPU 101

42357010440000

Oil

Prod

Active

C02

1

0

NPU 103

42357010060000

Oil

Prod

Active

C02

1

0

NPU 104

42357000050000

Oil

Prod

Active

C02

1

0

NPU 207

42357302000000

Oil

Prod

Active

co2

1

0

NPU 209

42357333830000

Oil

Prod

Active

co2

1

0

NPU 501

42357009140000

Oil

Prod

Active

co2

1

0

NPU 502

42357024100000

Oil

Prod

Active

co2

1

0

NPU 601

42357008420000

Oil

Prod

Active

co2

1

0

NPU 605

42357333840000

Oil

Prod

Active

co2

1

0

NWCU 3-1

35007360850000

Gas Prod

Active

co2

1

0

NWCU 9-3

35007249430000

Oil

Prod

Active

co2

1

0

CU 2172

35007354130000

Oil

Prod

Inactive

co2

0

0

CU 2175

35007354160000

Oil

Prod

Inactive

co2

0

0

CU 2473

35007211990000

Oil

Prod

Inactive

co2

0

0

CU 2511

35007350790000

Oil

Prod

Inactive

co2

0

0

CU 2711

35007359260000

Oil

Prod

Inactive

co2

0

0

CU 2771

35007359850000

Oil

Prod

Inactive

co2

0

0

CU 3142

35007222350000

Oil

Prod

Inactive

co2

0

0

CU 3361

35007352670000

Oil

Prod

Inactive

co2

0

0

NPU 205

42357008070000

Oil

Prod

Inactive

co2

0

0

NPU 301

42357022080000

Oil

Prod

Inactive

co2

0

0

NPU 801

42357004630000

Oil

Prod

Inactive

co2

0

0

NPU 802

42357004620000

Oil

Prod

Inactive

co2

0

0

NPU 804

42357201730000

Oil

Prod

Inactive

co2

0

0

NPU 901

42357000660000

Oil

Prod

Inactive

co2

0

0

NWCU 15-2

35007350870000

Oil

Prod

Inactive

co2

0

0

NWCU 15-3

35007210790000

Oil

Prod

Inactive

co2

0

0

NWCU 16-1

35007350720000

Oil

Prod

Inactive

co2

0

0

NWCU 19-1

35007360900000

Oil

Prod

Inactive

co2

0

0

NWCU 19-3

35007360920000

Oil

Prod

Inactive

co2

0

0

-------
Well Name

API

Well Type

Status

Gas

Active

Activ<











Makeup

Production

Inject

NWCU 19-4

35007360930000

Oi

Prod

Inactive

O
u

0

0

NWCU 19-5

35007360940000

Oi

Prod

Inactive

o
u

0

0

NWCU 19-6

35007211250000

Oi

Prod

Inactive

co2

0

0

NWCU 24-5

35007222710000

Oi

Prod

Inactive

o
u

0

0

NWCU 25-7

35007228000000

Oi

Prod

Inactive

co2

0

0

NWCU 3-3

35007360870000

Oi

Prod

Inactive

0
u

0

0

NWCU 3-4

35007360880000

Oi

Prod

Inactive

co2

0

0

NWCU 4-2

35007360740000

Oi

Prod

Inactive

0
u

0

0

NWCU 5-1

35007361050000

Oi

Prod

Inactive

C02

0

0

NWCU 7-1

35007360980000

Oi

Prod

Inactive

O
u

0

0

NWCU 7-2

35007360990000

Oi

Prod

Inactive

n
O

0

0

NWCU 8-1

35007360810000

Oi

Prod

Inactive

0
u

0

0

NWCU 8-2

35007360820000

Oi

Prod

Inactive

co2

0

0

NWCU 8-3

35007208260000

Oi

Prod

Inactive

0
u

0

0

NWCU 9-1

35007360950000

Oi

Prod

Inactive

co2

0

0

NWCU 9-2

35007360960000

Oi

Prod

Inactive

0
u

0

0

CU 1551

35007350740000

Oi

Prod

P&A

co2

0

0

CU 1671

35007352180000

Oi

Prod

P&A

0
u

0

0

CU 2111

35007353560000

Oi

Prod

P&A

co2

0

0

CU 2176

35007358870000

Oi

Prod

P&A

0
u

0

0

CU 2221

35007000490000

Oi

Prod

P&A

co2

0

0

CU 2281

35007359220000

Oi

Prod

P&A

0
u

0

0

CU 2421

35007359350000

Oi

Prod

P&A

0
u

0

0

CU 2431

35007350330000

Oi

Prod

P&A

0
u

0

0

CU 2432

35007350340000

Oi

Prod

P&A

co2

0

0

CU 2433

35007350350000

Oi

Prod

P&A

0
u

0

0

CU 2434

35007350360000

Oi

Prod

P&A

co2

0

0

CU 2435

35007218800000

Oi

Prod

P&A

0
u

0

0

CU 2471

35007359080000

Oi

Prod

P&A

n
O

0

0

CU 2531

35007361090000

Oi

Prod

P&A

O
u

0

0

CU 2532

35007361100000

Oi

Prod

P&A

0
u

0

0

CU 2552

35007359760000

Oi

Prod

P&A

0
u

0

0

CU 2571

35007350730000

Oi

Prod

P&A

0
u

0

0

CU 2572

35007359320000

Oi

Prod

P&A

0
u

0

0

CU 2661

35007361990000

Oi

Prod

P&A

0
u

0

0

CU 2681

35007350320000

Oi

Prod

P&A

0
u

0

0

CU 2852

35007301360000

Oi

Prod

P&A

co2

0

0

CU 2961

35007358760000

Oi

Prod

P&A

0
u

0

0

CU 2971

35007358750000

Oi

Prod

P&A

co2

0

0

CU 2972

35007358780000

Oi

Prod

P&A

0
u

0

0

CU 3031

35007359560000

Oi

Prod

P&A

0
u

0

0

-------
Well Name

API

Well Type

Status

Gas

Makeup

Active
Production

Active
Injection

CU 3051

35007300380000

Oi

Prod

P&A

o
u

0

0

CU 3064

35007254270000

Oi

Prod

P&A

o
u

0

0

CU 3141

35007359610000

Oi

Prod

P&A

o

U

0

0

CU 3181

35007359470000

Oi

Prod

P&A

co2

0

0

CU 3251

35007352710000

Oi

Prod

P&A

o
u

0

0

CU 3331

35007200750000

Oi

Prod

P&A

co2

0

0

CU 3451

35007351690000

Oi

Prod

P&A

o
u

0

0

CU 3511

35007359730000

Oi

Prod

P&A

co2

0

0

CU 3531

35007350850000

Oi

Prod

P&A

o
u

0

0

CU 3532

35007359950000

Oi

Prod

P&A

co2

0

0

CU 3534

35007211180000

Oi

Prod

P&A

o
u

0

0

CU 3561

35007359830000

Oi

Prod

P&A

co2

0

0

CU 3571

35007359980000

Oi

Prod

P&A

o
u

0

0

CU 3581

35007359970000

Oi

Prod

P&A

co2

0

0

CU 3631

35007301000000

Oi

Prod

P&A

o
u

0

0

CU 1672

35007352190000

Oi

Prod

P&A

co2

0

0

CU 2351

35007350370000

Oi

Prod

P&A

o
u

0

0

CU 2474

35007228200000

Oi

Prod

P&A

co2

0

0

CU 2812

35007352340000

Oi

Prod

P&A

o
u

0

0

CU 2871

35007359060000

Oi

Prod

P&A

co2

0

0

NPU 102

42357021420000

Oi

Prod

P&A

o
u

0

0

NPU 201

42357001280000

Oi

Prod

P&A

n
o

0

0

NPU 302

42357022290000

Oi

Prod

P&A

o

U

0

0

NPU 402

42357022300000

Oi

Prod

P&A

co2

0

0

NWCU 17-2

35007359620000

Oi

Prod

P&A

o
u

0

0

NWCU 10-1

35007361010000

Oi

Prod

P&A

co2

0

0

NWCU 17-1

35007350710000

Oi

Prod

P&A

o
u

0

0

NWCU 19-7

35007224520000

Oi

Prod

P&A

co2

0

0

NWCU 24-4

35007358770000

Oi

Prod

P&A

o
u

0

0

NWCU 25-6

35007358790000

Oi

Prod

P&A

co2

0

0

-------
Table A1.2 - Water Alternating Gas (WAG) Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active











Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG

Inj

Active

C02

0

1

CU 2662 (INJ)

35007362010000

WAG

Inj

Active

o
u

0

1

CU 2751 (INJ)

35007359440002

WAG

Inj

Active

n
O

0

1

CU 2762 (INJ)

35007213660000

WAG

Inj

Active

C02

0

1

CU 2772 (INJ)

35007359860001

WAG

Inj

Active

n
O

0

1

CU 2811 (INJ)

35007352200000

WAG

Inj

Active

C02

0

1

CU 2872 (INJ)

35007359070000

WAG

Inj

Active

n
O

0

1

CU 2962 (INJ)

35007212000000

WAG

Inj

Active

C02

0

1

CU 2974 (INJ)

35007220770000

WAG

Inj

Active

n
O

0

1

CU 3114 (INJ)

35007206540000

WAG

Inj

Active

C02

0

1

CU 3117 (INJ)

35007254000000

WAG

Inj

Active

n
O

0

1

CU 3161 (INJ)

35007359590002

WAG

Inj

Active

C02

0

1

CU 3213 (INJ)

35007224570000

WAG

Inj

Active

n
O

0

1

CU 3233 (INJ)

35007206890000

WAG

Inj

Active

o
u

0

1

CU 3252 (INJ)

35007211020000

WAG

Inj

Active

n
O

0

1

CU 3262 (INJ)

35007206870000

WAG

Inj

Active

C02

0

1

CU 3351 (INJ)

35007352680000

WAG

Inj

Active

n
O

0

1

CU 3371 (INJ)

35007360770000

WAG

Inj

Active

C02

0

1

CU 3417 (INJ)

35007255060000

WAG

Inj

Active

n
O

0

1

CU 3461 (INJ)

35007351680000

WAG

Inj

Active

C02

0

1

CU 3472 (INJ)

35007206940000

WAG

Inj

Active

n
O

0

1

CU 3551 (INJ)

35007359840000

WAG

Inj

Active

C02

0

1

NPU 105 (INJ)

42357000030000

WAG

Inj

Active

n
O

0

1

NPU 107W (INJ)

42357333770000

WAG

Inj

Active

C02

0

1

NPU 202WI (INJ)

42357021500000

WAG

Inj

Active

n
O

0

1

NPU 208 (INJ)

42357327410000

WAG

Inj

Active

C02

0

1

NPU 701 (INJ)

42357008410000

WAG

Inj

Active

n
O

0

1

NPU 504 (INJ)

42357329480000

WAG

Inj

Active

C02

0

1

NPU 604W (INJ)

42357330870000

WAG

Inj

Active

n
O

0

1

CU 1531 (INJ)

35007359990000

WAG

Inj

Inactive

C02

0

0

CU 2131 (INJ)

35007362700000

WAG

Inj

Inactive

n
O

0

0

CU 2512 (INJ)

35007350780000

WAG

Inj

Inactive

o
u

0

0

CU 2641 (INJ)

35007359250001

WAG

Inj

Inactive

n
O

0

0

CU 2721 (INJ)

35007359870001

WAG

Inj

Inactive

C02

0

0

CU 2741 (INJ)

35007359430000

WAG

Inj

Inactive

n
O

0

0

CU 2851 (INJ)

35007355420001

WAG

Inj

Inactive

C02

0

0

CU 3032 (INJ)

35007359580000

WAG

Inj

Inactive

n
O

0

0

CU 3062 (INJ)

35007253090000

WAG

Inj

Inactive

C02

0

0

CU 3112 (INJ)

35007359450001

WAG

Inj

Inactive

n
O

0

0

39

-------
Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU 2174 (INJ)

35007354150000

WAG Inj

Active

C02

0

1

CU 3172 (INJ)

35007251690000

WAG Inj

Inactive

o
u

0

0

CU 3281 (INJ)

35007352700003

WAG Inj

Inactive

o
u

0

0

CU 3311 (INJ)

35007360790000

WAG Inj

Inactive

co2

0

0

CU 3341 (INJ)

35007353530000

WAG Inj

Inactive

o
u

0

0

NPU 203W (INJ)

42357008270000

WAG Inj

Inactive

co2

0

0

NPU 503 (INJ)

42357009150001

WAG Inj

Inactive

o
u

0

0

NWCU 15-1 (INJ)

35007350860000

WAG Inj

Inactive

co2

0

0

NWCU 15-4 (INJ)

35007224510000

WAG Inj

Inactive

0
u

0

0

NWCU 20-1 (INJ)

35007360760000

WAG Inj

Inactive

co2

0

0

NWCU 21-1 (INJ)

35007361020000

WAG Inj

Inactive

0
u

0

0

CU 2271 (INJ)

35007359230000

WAG Inj

P&A

O
u

0

0

CU 2311 (INJ)

35007362000000

WAG Inj

P&A

0
u

0

0

CU 2472 (INJ)

35007359090000

WAG Inj

P&A

co2

0

0

CU 3061 (INJ)

35007359820000

WAG Inj

P&A

0
u

0

0

CU 3512 (INJ)

35007359740000

WAG Inj

P&A

n
O

0

0

NPU 204W (INJ)

42357022520000

WAG Inj

P&A

O
u

0

0

NPU 206W (INJ)

42357022510000

WAG Inj

P&A

co2

0

0

NPU 401W (INJ)

42357004520000

WAG Inj

P&A

0
u

0

0

NPU 602W (INJ)

42357020230000

WAG Inj

P&A

co2

0

0

NPU 603W (INJ)

42357201720001

WAG Inj

P&A

0
u

0

0

NPU 803W (INJ)

42357201710000

WAG Inj

P&A

co2

0

0

NWCU 14-1 (INJ)

35007350530000

WAG Inj

P&A

0
u

0

0

NWCU 3-2 (INJ)

35007360860000

WAG Inj

P&A

co2

0

0

Table A1.3 - Water Injection Wells

Well Name

API

Well Type

Status

Gas

Active

Active









Makeup

Production

Injection

CU wsw 1

35007355430001

Wtr Inj

Active

n
O

0

1

NPU W 1W

42357300050002

Wtr Inj

Inactive

n
O

0

0

CU 2551

35007350750000

Wtr Inj

P&A

O
O

0

0

40

-------
Appendix 2 - Referenced Regulations
U.S. Code > Title 26. INTERNAL REVENUE CODE > Subtitle A. Income Taxes > Chapter 1. NORMAL TAXES
AND SURTAXES > Subchapter A. Determination of Tax Liability > Part IV. CREDITS AGAINST TAX > Subpart
D. Business Related Credits > Section 45Q - Credit for carbon oxide sequestration

OKLAHOMA CONSERVATION COMMISSION > Title 165: CORPORATION COMMISSION > CHAPTER 10: OIL
AND GAS CONSERVATION

SUBCHAPTER 5. UNDERGROUND INJECTION CONTROL
Section

165:10-5-1. Classification of underground injection wells
165:10-5-2. Approval of injection wells or disposal wells

165:10-5-3. Authorization for existing enhanced recovery injection wells and existing
disposal wells

165:10-5-4. Application for approval of enhanced recovery projects
165:10-5-5. Application for approval of injection and disposal operations
165:10-5-6. Testing and monitoring requirements for injection wells and disposal wells
165:10-5-7. Monitoring and reporting requirements for wells covered by 165:10-5-1
165:10-5-8. Liquid hydrocarbon storage wells

165:10-5-9. Duration of underground injection well orders or permits
165:10-5-10. Transfer of authority to inject
165:10-5-11. Notarized reports

165:10-5-12. Application for administrative approval for the subsurface injection of onsite
reserve pit fluids

165:10-5-13. Application for permit for one time injection of reserve pit fluids
165:10-5-14. Exempt aquifers

165:10-5-15. Application for permit for simultaneous injection well

165:5-7-27. Application for approval of injection and disposal wells
165:5-7-29. Request for exception to certain underground injection well requirements
165:5-7-30. Amending existing orders or permits authorizing injection for injection, disposal,
or LPG storage wells

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Texas Administrative Code (TAC) > Title 16 - Economic Regulation> Part 1 - Railroad Commission of
Texas > Chapter 3 - Oil and Gas Division

Rules

§3.1 Organization Report; Retention of Records; Notice Requirements

§3.2 Commission Access to Properties

§3.3 Identification of Properties, Wells, and Tanks

§3.4 Oil and Geothermal Lease Numbers and Gas Well ID Numbers Required on All Forms

§3.5 Application to Drill, Deepen, Reenter, or Plug Back

§3.6 Application for Multiple Completion

§3.7 Strata to Be Sealed Off

§3.8 Water Protection

§3.9 Disposal Wells

§3.10 Restriction of Production of Oil and Gas from Different Strata
§3.11 Inclination and Directional Surveys Required
§3.12 Directional Survey Company Report

§3.13 Casing, Cementing, Drilling, Well Control, and Completion Requirements
§3.14 Plugging

§3.15 Surface Equipment Removal Requirements and Inactive Wells

§3.16 Log and Completion or Plugging Report

§3.17 Pressure on Bradenhead

§3.18 Mud Circulation Required

§3.19 Density of Mud-Fluid

§3.20 Notification of Fire Breaks, Leaks, or Blow-outs

§3.21 Fire Prevention and Swabbing

§3.22 Protection of Birds

§3.23 Vacuum Pumps

§3.24 Check Valves Required

§3.25 Use of Common Storage

§3.26 Separating Devices, Tanks, and Surface Commingling of Oil

§3.27 Gas to be Measured and Surface Commingling of Gas

§3.28 Potential and Deliverability of Gas Wells to be Ascertained and Reported

§3.29 Hydraulic Fracturing Chemical Disclosure Requirements

§3.30 Memorandum of Understanding between the Railroad Commission of Texas (RRC)
and the Texas Commission on Environmental Quality (TCEQ)

§3.31 Gas Reservoirs and Gas Well Allowable

§3.32 Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes
§3.33 Geothermal Resource Production Test Forms Required
§3.34 Gas To Be Produced and Purchased Ratably

§3.35 Procedures for Identification and Control of Wellbores in Which Certain Logging
Tools Have Been Abandoned

§3.36 Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas

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§3.37	Statewide Spacing Rule

§3.38	Well Densities

§3.39	Proration and Drilling Units: Contiguity of Acreage and Exception Thereto

§3.40	Assignment of Acreage to Pooled Development and Proration Units

§3.41	Application for New Oil or Gas Field Designation and/or Allowable

§3.42	Oil Discovery Allowable

§3.43	Application for Temporary Field Rules

§3.45	Oil Allowables

§3.46	Fluid Injection into Productive Reservoirs

§3.47	Allowable Transfers for Saltwater Injection Wells

§3.48	Capacity Oil Allowables for Secondary or Tertiary Recovery Projects

§3.49	Gas-Oil Ratio

§3.50	Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive

§3.51	Oil Potential Test Forms Required

§3.52	Oil Well Allowable Production

§3.53	Annual Well Tests and Well Status Reports Required

§3.54	Gas Reports Required

§3.55	Reports on Gas Wells Commingling Liquid Hydrocarbons before Metering

§3.56	Scrubber Oil and Skim Hydrocarbons

§3.57	Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste Materials

§3.58	Certificate of Compliance and Transportation Authority; Operator Reports

§3.59	Oil and Gas Transporter's Reports

§3.60	Refinery Reports

§3.61	Refinery and Gasoline Plants

§3.62	Cycling Plant Control and Reports

§3.63	Carbon Black Plant Permits Required

§3.70	Pipeline Permits Required

§3.71	Pipeline Tariffs

§3.72	Obtaining Pipeline Connections

§3.73	Pipeline Connection; Cancellation of Certificate of Compliance; Severance

§3.76	Commission Approval of Plats for Mineral Development

§3.78	Fees and Financial Security Requirements

§3.79	Definitions

§3.80	Commission Oil and Gas Forms, Applications, and Filing Requirements

§3.81	Brine Mining Injection Wells

§3.83	Tax Exemption for Two-Year Inactive Wells and Three-Year Inactive Wells

§3.84	Gas Shortage Emergency Response

§3.85	Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle

§3.86	Horizontal Drainhole Wells

§3.91	Cleanup of Soil Contaminated by a Crude Oil Spill

§3.93	Water Quality Certification Definitions

§3.95	Underground Storage of Liquid or Liquefied Hydrocarbons in Salt Formations

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§3.96 Underground Storage of Gas in Productive or Depleted Reservoirs
§3.97 Underground Storage of Gas in Salt Formations
§3.98 Standards for Management of Hazardous Oil and Gas Waste
§3.99 Cathodic Protection Wells
§3.100 Seismic Holes and Core Holes

§3.101 Certification for Severance Tax Exemption or Reduction for Gas Produced From High-
Cost Gas Wells

§3.102 Tax Reduction for Incremental Production

§3.103 Certification for Severance Tax Exemption for Casinghead Gas Previously Vented or
Flared

§3.106 Sour Gas Pipeline Facility Construction Permit
§3.107 Penalty Guidelines for Oil and Gas Violations

44

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Appendix 3 - References

Al-Shaieb, Z., Puckette, & Abdalla A. (1995). Influence of sea-level fluctuation on reservoir quality of the
upper Morrowan sandstones, northwestern shelf of the Anadarko Basin, in Hyne, N.J., ed., Sequence
stratigraphy of the midcontinent: Tulsa Geological Society Special Publication, no. 4, 249-268.

Alston, R.B., Kokolis, G.P., James, C.F. CO2 minimum miscibility pressure: A correlation for impure CO2
streams and live oil systems. SPE J. 1985, 25(2): 268-274.

Ampomah W., R. Balch, M. Cather, D. Rose-Coss, Z. Dai, J. Heath, T. Dewers, and P. Mozley (2016a),
Evaluation of C02 Storage Mechanisms in C02 Enhanced Oil Recovery Sites: Application to Morrow
Sandstone Reservoir. Energy &Fuels Article ASAP.

Ampomah, W., Balch, R. S., Grigg, R. B., McPherson, B., Will, R. A., Lee, S.-Y., Dai, Z. and Pan, F. (2016b),
Co-optimization of CO2-EOR and storage processes in mature oil reservoirs. Greenhouse Gas Sci Technol.
doi:10.1002/ghg,1618

Blakeney, B.A., Krystinik, L.F., Downey, A.A. (1990) Reservoir heterogeneity in Morrow Valley Fills,
Stateline Trend: implications for reservoir management and field expansion in Sonnenberg, S.A., ed.,
Morrow Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 131-141Bowen et
al., 1990

Ball, Mahlon M., Henry, Mitchell E., Frezon, Sherwood E. (1991) Department of the Interior, U.S.
Geological Survey, Petroleum Geology of the Anadarko Region, Province (115), Kansas, Oklahoma and
Texas, Open File Report 88-450W

Bowen, D.W., Krystinik, L.F., and Grantz, R.E., (1990) Geology and reservoir characteristics of the
Sorrento-Mt. Pearl field complex, Cheyenne County, Colorado: in Sonnenberg, S.A., ed., Morrow
Sandstones of SE Colorado, and Adjacent Areas: Denver, Colorado, RMAG, p. 67-77.

Bowen, D. W., & Weimer, P. (2003). Regional sequence stratigraphic setting and reservoir geology of
Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas.
American Association of Petroleum Geologists Bulletin, 87(5), 781-815.

Bowen, D. W., & Weimer, P. (2004). Reservoir geology of Nicholas and Liverpool cemetery fields (lower
Pennsylvanian), Stanton county, Kansas, and their significance to the regional interpretation of the
Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas. American
Association of Petroleum Geologists Bulletin, 88(1), 47-70.

Devries, A.A., 2005, Sequence Stratigraphy and Micro-Image Analysis of the Upper Morrow Sandstone in
the Mustang East Field, Morton County, Kansas: M.S. Thesis, Oklahoma State University.

Evans, J.L. (1979). Major structural and stratigraphic features of the Anadarko Basin: in N. J. Hyne, ed.,
Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society Special Publication 1, 97-113.

Farnsworth Unit MRV plan, final decisions under 40 CFR Part 98, Subpart RR, dated June 30, 2021

45

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Gallagher, S. R. (2014). Depositional and diagenetic controls on reservoir heterogeneity: Upper Morrow
Sandstone, Farnsworth Unit, Ochiltree County, Texas. MS thesis, New Mexico Institute of Mining and
Technology, p. 214.

Gragg, Evan J. (2016) Petroleum System Modeling of the northwest Anadarko Basin: Implications for
Carbon Storage: M.S. Thesis, New Mexico Institute of Mining and Technology, ProQuest Dissertations
Publishing, 2016. 10116887.

Gragg E., Will R., Rose-Coss D., Trujillo N., Hutton A., Ampomah W., van Wijk J., and Balch R.S. (2018)
Geomodelling, Geomechanics, and Evaluating the Subsurface for Carbon Storage. AAPG Southwest
Section meeting, 4/9/2018. El Paso, TX

Gunda D., Ampomah, W., Grigg, R. B. and Balch, R. S. (2015) Reservoir Fluid Characterization for Miscible
Enhanced Oil Recovery. Carbon Management Technology Conference November 16-19 2015, Sugarland,
Houston-Texas USA.

Heath, J. E., Dewers, T. A., Mozley, P. S. (2015). Characteristics of the Farnsworth Unit, Ochiltree County,
Texas : Southwest Partnership C02 Storage - EOR Project.

Higley, D. K., Cook, T. A., & Pawlewicz, M. J. (2014). Petroleum Systems and assessment of undiscovered
oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas — Woodford Shale
Assessment Units. In Higley, D.K., Compiler, Petroleum Systems and Assessment of Undiscovered Oil and
Gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas - USGS Province 58: USGS
Digital Data Series DDS-69-EE, 24.

Hobbs, Noah; van Wijk, Jolante; Axen, Gary; 3D Interpretation of the Farnsworth Unit, unpublished
report, New Mexico Institute of Mining and Technology, pp 9.

Hobbs N., van Wijk J., Axen G. (2019) - Tectonic-landscape evolution model of the Anadarko basin.
American Geophysical Union Fall Meeting, San Francisco CA December 8-15, 2019

Jorgensen, D.G. (1989). Paleohydrology of the Anadarko Basin, central United States. In: Johnson, K.S.,
ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, 176-193.

Krystinik, L.F., & Blakeney, B.A. (1990). Sedimentology of the upper Morrow Formation in eastern
Colorado and western Kansas, in Sonnenberg, S. A., et al., eds., Morrow sandstones of southeast
Colorado and adjacent areas: Rocky Mountain Association of Geologists, Denver, Colorado, 37-50.

Lee, E., Hornafius, J.S., Dean, E., Kazemi, H (2018). Potential of Denver Basin Oil Fields 1 to Store C02 and
Produce Bio-C02-EOR Oil, Manuscript Submitted to the International Journal of Greenhouse Gas Control,
published by Elsevier.

Lohrenz, J., Bray, B.G., Clark, C.R. (1964). "Calculating Viscosities of Reservoir Fluids from their
compositions", SPE Paper 915, Journal of Petroleum Technology, p. 1171-1176.

McKay, R. H., & Noah, J. T. (1996). Integrated perspective of the depositional environment and reservoir
geometry, characterization, and performance of the Upper Morrow Buckhaults Sandstone in the
Farnsworth Unit, Ochiltree County, Texas: Oklahoma Geological Survey Circular, no. 98, p. 101-114.

46

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Munson, T., 1988, "Depositional, diagenetic, and production history of the Upper Morrowan Buckhaults
sandstone, Farnsworth Field, Ochiltree County, Texas," unpub. MS thesis, West Texas State University,
Canyon, TX. 354. pp.

Munson, T. W. (1989). Depositional, diagenetic, and production history of the Upper Morrowan
Buckhaults Sandstone, Farnsworth Field, Ochiltree County Texas, The Shale Shaker, July-August 1989, p
1-19.

Nelson, P.H. and Gianoutsos, N.J, 2014, Potentiometric Surfaces for Seven Stratigraphic Units and an
Explanation for Underpressure , Chapter 9 of 13 in the Greater Anadarko Basin, Oklahoma, Texas,
Kansas, and Colorado in Petroleum systems and assessment of undiscovered oil and gas in the Anadarko
Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58, compiled by Debra Higley.

The Paleontology Portal, The Carboniferous in Texas, US. (Site was funded by the National Science
Foundation under award no. 0234594.)

http://paleoportal.org/index. php?globalnav=time_space§ionnav=state&state_id=42&period_id=12

Pedersen, K.S., Thomassen, P., and Fredenslund, A.: "Characterization of Gas Condensate Mixtures,"C7+
Fraction Characterization, L.G.Chorn and G.A. Mansoori (eds.), Advances in Thermodynamics, Taylor &
Francis, New York City (1989)

Pedersen, K. S., Calsep, A. S., Milter, J., S0rensen, H., & Calsep, A. S. (n.d.). SPE 77385 Cubic Equations of
State Applied to HT/ HP and Highly Aromatic Fluids (2002).

Peneloux, A., Rauzy, E., and Freze, R.: "A Consistent Correction for Redlich-Kwong-Soave Volumes," Fluid
Phase Equilibria (1982)

Peng, D.Y. and Robinson, D.B. (1976). A New Two-Constant Equation of State. Ind.Eng.Chem.
Fundamentals, 15, 59-64

Perry, W. J., Jr. (1989). Tectonic evolution of the Anadarko basin region, Oklahoma: U.S. Geological
Survey Bulletin 1866-A, 19 pp.

Puckette, J., Abdalla, A., Rice, A., & Al-Shaieb, Z. (1996). The upper Morrow reservoirs: Complex fluvio-
deltaic depositional systems, in Johnson, K.S., ed., Deltaic reservoirs in the southern midcontinent, 1993
symposium: Oklahoma Geological Survey Circular, no. 98, 47-84.

Puckette, J., Al-Shaieb, Z., & Van Evera, E. (2008). Sequence stratigraphy, lithofacies, and reservoir
quality, upper Morrow sandstones, northwestern shelf, Anadarko Basin, in Andrews, R. D., ed., Morrow
and Springer in the southern midcontinent, 2005 symposium: Oklahoma Geological Survey Circular, no.
Ill, 81-97.

Rasmussen, L., Fan, T., Rinehart, A., Luhmann, A., Ampomah, W., Dewers, T., Heath, J, Cather, M., and
Grigg, R. (2019). Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic
Reservoirs: Controls on Oil/Brine and Oil/ C02 Relative Permeability from Diagenetic Heterogeneity and
Evolving Wettability. Energies, Special Issue "C02 EOR and C02 Storage in Oil Reservoirs" Energies 2019,
12(19), 3663.

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Rose-Coss, D. (2017). A Refined Depositional Sequence Stratigraphic and Structural Model for the
Reservoir and Caprock Intervals at the Farnsworth Unit, Ochiltree County TX. M.S. Thesis, New Mexico
Institute of Mining and Technology, ProQuest Dissertations Publishing, 2017. 10258790.

Rose-Coss, D., Ampomah, W., Cather M., Balch, R. S., Mozley P (2016): "An Improved Approach for
Sandstone Reservoir Characterization" paper SPE-180375-MS presented at SPE Western Regional
Meeting held in Anchorage, Alaska, May 23-26.

Schlumberger, https://www.software.slb.com/products/eclipse

Sonnenberg, S.A., 1985, Tectonic and Sedimentation Model for Morrow Sandstone Deposition, Sorrento
Field Area, Denver Basin, Colorado: The Mountain Geologist, v. 22. p 180-191.

Stell, Mike, (2010) An Auditor's View of Booking Reserves in C02 EOR Projects and the ROZ, 16th Annual
C02 Flooding Conference, Midland, Texas, December 9-10, 2010

Swanson, D., 1979, Deltaic Deposits in the Pennsylvanian upper Morrow Formation in the Anadarko
Basin, in Pennsylvanian sandstones of the mid-continent: Tulsa Geological Society special publication,
no. 1, p. 115-168.

Trujillo, N, A., (2018). Influence of Lithology and Diagenesis on Mechanical and Sealing Properties of the
Thirteen Finger Limestone and Upper Morrow Shale, Farnsworth Unit, Ochiltree County, Texas. M.S.
Thesis. New Mexico Institute of Mining and Technology, ProQuest Dissertations Publishing, 2018.
10689420.

Wheeler, D. M., Scott, A. J., Coringrato, V. J., and Devine, P. E., 1990, Stratigraphy and depositional
history of the Morrow Formation, southeast Colorado, and southwest Kansas; in, Morrow Sandstones of
Southeast Colorado and Adjacent Areas, S. A. Sonnenberg, L. T. Shannon, K. Rader, W. F. von Drehle, and
G. W. Martin, eds.: The Rocky Mountain Association of Geologists, Special Paper, p. 3-35.

Xiao, T., McPherson, B., Pan, F., Esser, R., Jia, W., Bordelon, A., & Bacon, D. (2016). Potential chemical
impacts of C02 leakage on underground source of drinking water assessed by quantitative risk analysis.
International Journal of Greenhouse Gas Control, 50, 305-316.

Xiao, T., McPherson, B., Bordelon, A., Viswanathan, H., Dai, Z., Tian, H., Esser, R., Jia, W., & Carey, W.
(2017). Quantification of C02-cement-rock interactions at the well-caprock-reservoir interface and
implications for geological C02 storage. International Journal of Greenhouse Gas Control, 63, 126-140.

48

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Appendix 4 - Abbreviations and Acronyms

2D - 2 dimensional

3D - 3 dimensional

AGA - American Gas Association

AMA - Active Monitoring Area

ANSI - American National Standards Institute

API - American Petroleum Institute

AWT-All Well Test

ASTM - American Society for Testing and Materials

Bscf - billion standard cubic feet

B/D - barrels per day

bopd - barrels of oil per day

C4 - butane

C5 - pentane

C7 - heptane

C7+ - standard heptane plus

CCE - constant composition expansion

CCUS - carbon capture utilization and storage

CFA - Camrick Field Area

cf- cubic feet

CH4 - methane

C02 - carbon dioxide

EOR - Enhanced Oil Recovery

EOS - Equation of State

EPA - US Environmental Protection Agency

ESD - Emergency Shutdown Device

GHG - Greenhouse Gas

GHGRP - Greenhouse Gas Reporting Program

GPA- Gas Producers Association

H2S - hydrogen sulfide

mD - millidarcy(ies)

MICP - mercury injection capillary pressure

MIT - mechanical integrity test

MMA- maximum monitoring area

MMB - million barrels

MMP - minimum miscible pressure

MMscf - million standard cubic feet

MMstb - million stock tank barrels

MRV- Monitoring, Reporting, and Verification

MMMT- Million metric tonnes

MT - Metric tonne

NIST - National Institute of Standards and Technology
NAESB - North American Energy Standards Board

49

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OCC-Oklahoma Conservation Commission

OOIP - Original Oil-ln-Place

OWC - oil water contact

PPM - Parts Per Million

psia - pounds per square inch absolute

PVT- pressure, volume, temperature

QA/QC- quality assurance/quality control

RMS - root mean square

SEM - scanning electron microscope

SWP - Southwest Regional Partnership on Carbon Sequestration
TAC - Texas Administrative Code
TA - Temporally Abandoned/not plugged
TD - total depth

TM - Terminated order wells/UIC not plugged

TRRC-Texas Railroad Commission

TSD -Technical Support Document

TVDSS-True Vertical Depth Subsea

UIC- Underground Injection Control

USDW - Underground Source of Drinking Water

WAG - Water Alternating Gas (Gas is recycled C02 and purchase C02)

XRD - x-ray diffraction

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Appendix 5 - Conversion Factors
CapturePoint reports C02 at standard conditions of temperature and pressure as defined
in the State of Texas in the Texas Administrative Code for the Oil and Gas Division, Rule
3.79 as follows:

Cubic foot of gas or standard cubic foot of gas-The volume of gas contained in
one cubic foot of space at a standard pressure base and at a standard
temperature base. The standard pressure base shall be 14.65 pounds per square
inch absolute, and the standard temperature base shall be 60 degrees
Fahrenheit.

To calculate C02 mass from C02 volume, EPA recommends using the database of
thermodynamic properties developed by the National Institute of Standards and
Technology (NIST). This online database is available at:

https://webbook.nist.gov/chemistry/fluid/

It provides density of C02 using the Span and Wagner equation of state (EOS) at a wide
range of temperature and pressures.

At State of Texas standard conditions, the Span and Wagner EOS gives a density of C02 of
0.002641684 lb-moles per cubic foot. Converting the C02 density in units of metric
tonnes per cubic foot:

/ MT\	fib — moles\	1 MT

Densityrn2 -7-7 = Densityrn2 	ti,	 x MWrn2 x 	—

yc02\ft3J	JC02\ ft3 J C02 2204.62 lbs

Where:

Density C02 = Density of CO 2 in metric tonnes (MT) per cubic foot
DensityC02 = 0.0 0 2 641 684
MWC02 = 44.0 0 9 5

c MT	_ MT

DensityC02 = 5.2734x 10 -r-r or 5.2734x 10 		

ft3	Mcf

The conversion factor 5.2734 x 10"2 MT/Mcf is used to convert C02 volumes in standard
cubic feet to C02 mass in metric tonnes.

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