Technical Review of Subpart RR MRV Plan for the O’Neal Gas Unit Well No. 4 October 2024


Technical Review of Subpart RR MRV Plan for
the O'Neal Gas Unit Well No. 4

October 2024

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For assistance in accessing this document, please contact ghgreporting@epa.gov.

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OFFICE OF ATMOSPHERIC PROTECTION

WASHINGTON, D.C. 20460

October 28, 2024

Mr. Richard Adams
Ozona CCS, LLC
19026 Ridgewood Pkwy
Suite 200

San Antonio, TX 78259

Re: Monitoring, Reporting and Verification (MRV) Plan for O'Neal Gas Unit Well No. 4
Dear Mr. Adams:

The United States Environmental Protection Agency (EPA) has reviewed the Monitoring, Reporting and
Verification (MRV) Plan submitted for O'Neal Gas Unit Well No. 4, as required by 40 CFR Part 98,
Subpart RR of the Greenhouse Gas Reporting Program. The EPA is approving the MRV Plan submitted
by O'Neal Gas Unit Well No. 4 on August 26, 2024, as the final MRV plan. The MRV Plan Approval
Number is 1014786-1. This decision is effective October 29, 2024 and is appealable to the EPA's
Environmental Appeals Board under 40 CFR Part 78. In conjunction with this MRV plan approval, we
recommend reviewing the Subpart PP regulations to determine whether your facility is required to
report data as a supplier of carbon dioxide. Furthermore, this decision is applicable only to the MRV
plan and does not constitute an EPA endorsement of the project, technologies, or parties involved.

If you have any questions regarding this determination, please contact me or Melinda Miller of the
Greenhouse Gas Reporting Branch at miller.melinda(5)epa.gov.

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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)	2

3	Identification of Potential Surface Leakage Pathways	3

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	13

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 Ozona CCS, LLC (O'Neal) for its O'Neal Gas Unit Well No. 4 (O'Neal No. 4 well)
treated acid gas (TAG) injection project, which injects into the Sligo Formation. Note that this evaluation
pertains only to the subpart RR MRV plan for O'Neal No. 4, and does not in any way replace, remove, or
affect Underground Injection Control (UIC) permitting obligations. Furthermore, this decision is
applicable only to the MRV plan and does not constitute an EPA endorsement of the project,
technologies, or parties involved.

1 Overview of Project

Section 1 of the MRV plan states that O'Neal No. 4 well currently has a pending Class II disposal permit
that will be issued by the Texas Railroad Commission (TRRC) for the O'Neal No. 4 well (API No. 42-025-
32658, UIC No. 56819). The permit application was submitted in September of 2023. This permit would
authorize O'Neal to inject up to 1.5 million standard cubic feet per day (MMscf/D) into the Sligo
formation at a depth of 15,874 ft to 16,056 ft with a maximum allowable surface pressure of 7,920
pounds per square inch gauge (psig). This injection of treated acid gas will occur for approximately 12
years. The source of the injected TAG is the Pawnee Treating Plant (Plant) in Bee County, Texas. The
O'Neal No. 4 well is located about 2 miles south of the Pawnee Gas Plant.

The MRV plan states that the facility and the well design of the O'Neal No. 4 well are planned to protect
against the migration of carbon dioxide (C02) out of the injection interval, protect against contamination
of subsurface formations, and most importantly, to prevent surface releases. The MRV plan states that
the injection interval for the O'Neal No. 4 well, the Sligo formation, is located approximately 14,924 ft
below the base of the Underground Source of Drinking Water (USDW). As stated in the MRV plan, the
O'Neal No. 4 well will inject a C02 stream containing 98.2% C02, 0.4% H2S, 1.03% hydrocarbons, and
0.37% Nitrogen.

Section 2 of the MRV plan describes the geologic setting and injection process for the O'Neal No. 4 well.
The MRV plan states that the target injection interval is the lower Cretaceous-age Sligo Formation. As
stated in the MRV plan, the Sligo Formation is predominately composed of shelf-edge limestones that
were deposited along the lower Cretaceous platform. According to the MRV plan primary porosity and
permeability of the upper Sligo Formation tends to develop in high-energy sequences with normal
marine conditions that are dominated by the deposition of oolitic and skeletal grainstones. As explained
in the MRV plan, the lithologic and petrophysical characteristics of the Sligo Formation at the O'Neal No.
4 well's location indicate that the reservoir contains the necessary thickness, porosity, and permeability
to receive the proposed injection stream.

The MRV plan states that the Pearsall Formation will serve as the upper confining interval. The MRV plan
states that following the deposition of the Sligo Formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
Formation throughout the region. The Pine Island Shale consists of alternating beds of pelagic
mudstone, hemipelagic mudstone, and iron-rich dolomitic mudstone interpreted to have been

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deposited along the outer ramp. According to the MRV plan, the 2012 U.S. Geological Survey (USGS) C02
Storage Resource Assessment suggests the Pine Island Shale Member contains the physical properties
required to act as a regional seal and noted it is a sufficient regional seal with as little as 50 feet of
contiguous shale development.

As stated in the MRV plan, the Lower Sligo and Hosston Formations serve as the lower confining
interval. The Hosston to lower Sligo "contact" represents a gradational package with a decrease in
terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the lower Sligo. The MRV plan also states that the porosity of the
Lower Sligo formation ranges from 0 to 2% and permeability is consistently near 0 millidarcies (mD).

The description of the project provides the necessary information for 40 CFR 98.448(a)(6).

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.

As stated in the MRV plan, the reservoir modeling calculated that, after 12 years of injection followed by
10 additional years of density drift, the areal extent of the projected plume will be 303 acres. The
reservoir is stated to be at hydrostatic equilibrium. Given the geological formation in which this well is
located and its previous history as a gas producer, the model is assumed to be primarily saturated with
gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine saturated, as
deduced from the well log data. O'Neal No. 4 well found that the maximum distance from the wellbore
to the edge of the forecasted plume to be approximately 0.45 miles (mi) after the 30-year post-injection
period. The MMA boundary represents the stabilized plume boundary after 10 years of density drift plus
an all-around buffer zone of one-half mile.

The MRV plan states that O'Neal No. 4 well initially established the AMA boundary by setting it equal to
the expected total injection period of 12 years. The AMA was analyzed by super imposing the area based
on a one-half mile buffer around the anticipated plume location after 12 years of injection (2037), with
the area of the projected free-phase C02 plume after 5 additional years (2042). Due to the AMA
boundary being only slightly smaller than the MMA boundary, O'Neal No. 4 well defined the AMA as

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equal to the MMA. The MRV plan also states that the facility will submit a revised MRV plan by 2037 to
provide an updated AMA and MMA.

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 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). O'Neal No. 4 well identified the following as potential leakage
pathways in Section 4 of their MRV plan that required consideration:

• Leakage from surface equipment

• Leakage through existing and future wells within the MMA

• Leakage through faults and fractures

• Leakage through the upper confining layer

• Leakage from natural or induced seismicity

A summary table of O'Neal No. 4 well's evaluation of the likelihood, magnitude, and timing of any
potential C02 leakage can be found in Table 7 of the MRV plan and is reproduced below.

Potential Leakage
Pathway

Likelihood

Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low. Automated systems will
detect leaks and execute
shut-down procedures.

During active injection
period. Thereafter the
well will be plugged.

Existing wells within
the MMA

Unlikely. One artificial
penetration was drilled into
the injection interval. This
well has been plugged and
abandoned.

Low. Vertical migration of C02
would likely enter a
shallower hydrocarbon
production zone.

During active injection.

Faults and fractures

Unlikely. There is over
14,000 ft of impermeable
rock between the injection
zone and the base of the
USDW.

Low. Vertical migration of C02
would likely enter a
shallower hydrocarbon
production zone.

During active injection.

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Upper confining layer

Unlikely. The lateral
continuity of the UCZ
consisting primarily of the
Pearsall Formation which is 500
ft thick is recognized as a very
competent seal.

Low. Vertical migration of C02
would likely enter a
shallower hydrocarbon
production zone.

During active injection.

Natural or induced
seismicity

Unlikely. There is over
14,000 ft of impermeable
rock between the injection
zone and the base of the
USDW.

Low. Vertical migration of C02
would likely enter a
shallower hydrocarbon
production zone.

During active injection.

Magnitude Assessment Description

Low - categorized as little to no impact to safety, health and the environment and the costs to mitigate are

minimal.

Medium - potential risks to the USDW and for surface releases does exist, but circumstances can be easily

remediated.

High - danger to the USDW and significant surface release may exist, and if occurs this would require

significant costs to remediate.

3.1 Leakage from Surface Equipment

Section 4.1 of the MRV plan states the Plant and the O'Neal No. 4 well are designed for separating
transporting, and injecting TAG, primarily consisting of C02, in a manner to ensure safety to the public,
the employees, and the environment. The facilities have been designed to minimize leakage and failure
points, following applicable National Association of Corrosion Engineers (NACE) and American
Petroleum Institute (API) standards and practices. As the TAG stream contains H2S, monitors installed for
H2S detection will also indicate the presence of C02. These monitors will be installed at key locations
around the Plant and the O'Neal No. 4 well. These devices will be continuously monitored by the
Supervisory Control and Data Acquisition (SCADA) system and will alert at set points at set points
determined by the Plant's Health, Safety, and Environment (HS&E) Director, consistent with
Occupational Safety and Health Administration (OSHA) requirements. The Plant will set the detection
and alarm states for personnel at 10 ppm and at 40 ppm for initiating Emergency Shutdown. Key
monitoring points and parameters are also provided in Table 8 of the MRV plan.

The MRV plan states facilities will incorporate important safety equipment to ensure reliable and safe
operations. In addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-
pressure shutoff settings to isolate the Plant, the O'Neal No. 4 well, and other components, StarTex has
a flare stack to safely handle the TAG when a depressuring event occurs. These facilities will be
constructed in the coming months. The exact location of this equipment is not yet known, but it will be
installed in accordance with applicable engineering and safety standards.

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With continuous air monitoring at the Plant and the O'Neal No. 4 well site, a release of C02 would be
quickly identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The C02 injected into the O'Neal No. 4 well is from the amine
unit at the Plant. O'Neal No. 4 well concludes that the leakage of C02 through the surface equipment is
unlikely.

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

3.2 Leakage through Existing and Future Wells Within the MMA
Oil and Gas Operations within the Monitoring Area

Section 4.2 of the MRV plan states that the O'Neal No. 4 well is engineered to prevent migration from
the injection interval to the surface through a special casing and cementing design as depicted in the
schematic provided in Figure 32 of the MRV plan. Mechanical integrity tests (MITs), required under
Statewide Rule (SWR) §3.46 [40 CFR §146.23 (b)(3)], will take place every 5 years to verify that the well
and wellhead can contain the appropriate operating pressures. If an MIT were to indicate a leak, the
well would be isolated, and the leak mitigated to prevent leakage of the injectate to the atmosphere.

According to the MRV plan, a map of all oil and gas wells within the MMA is shown in Figure 33. Figure
34 is a map of all the oil and gas wells that penetrate the MMA's gross injection zone. Only one well
penetrates the MMA's gross injection zone. This well is non-productive and has been plugged and
abandoned in accordance with TRRC requirements. A summary table of all oil and gas wells within the
MMA is provided in Appendix B-l. This table in Appendix B-l provides the total depth (TD) of all wells
within the MMA. The wells that are shallower and do not penetrate the injection zone are separated by
the Pearsall Formation with a gross thickness of 535 ft. The Pine Island Shale comprises approximately
130 ft of this interval and provides a competent regional seal—making vertical migration of fluids above
the injection zone unlikely.

The MRV plan states the shallower offset hydrocarbon wells within the MMA will also serve as above
zone monitoring wells. Should any of the sequestered volumes migrate vertically, they would potentially
enter the shallower hydrocarbon reservoir. Regular sampling and analysis are performed on the
produced hydrocarbons. O'Neal No. 4 well states if a material difference in the quantity of C02 in the
sample occurs indicating a potential migration of injectate from the Sligo Formation, then it would
investigate and develop a mitigation plan.

Future Drilling

The MRV plan states potential leakage pathways caused by future drilling in the area are not expected to
occur. The deeper formations have proven to date to be nonproductive in this area, and therefore the
facility does not see this as a risk. This is supported by a review of the TRRC Rule 13 (Casing, Cementing,
Drilling, Well Control, and Completion Requirements), 16 TAC §3.13. The Sligo is not among the
formations listed for which operators in Bee County and District 2 (where the O'Neal No. 4 well is located)

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are required to comply with TRCC Rule 13; therefore, the TRRC does not believe there are productive
horizons below the Sligo. The O'Neal No. 4 well drilling permit is provided in Appendix A-2.

Groundwater Wells

The MRV plan states that a groundwater well search resulted in five groundwater wells found within the
MMA, as identified by the Texas Water Development Board. The surface and intermediate casings of the
O'Neal No. 4 well, as shown in Figure 35 of the MRV plan, are designed to protect the shallow
freshwater aquifers consistent with applicable TRRC regulations and the Groundwater Advisory Unit
(GAU) letter issued for this location. The MRV plan also states that the wellbore casings and cements
also prevent C02 leakage to the surface along the borehole. For these reasons, the O'Neal No. 4 well
concludes that leakage of the sequestered C02 to groundwater is unlikely.

Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through existing wells within the MMA.

3.3 Leakage through Faults and Fractures

Section 4.3 of the MRV plan states detailed mapping of openhole logs surrounding the O'Neal No. 4 well
did not identify any faulting within either the Pearsall or Sligo sections. However, there is a general lack
of deep penetrators within the area that limits the amount of openhole coverage available.

According to the MRV plan, the majority of the published literature suggests that faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as shown in Figure 9 of the MRV
plan, with shallow faults dying out before reaching the Pearsall Formation. One source interpreted the
potential for faulting to the south. The potential fault is depicted in Figure 8 of the MRV plan relative to
the location of the O'Neal No. 4 well. According to the map, the interpreted fault lies approximately 4.25
miles south-southeast of the well and approximately 3.9 mi south-southeast of the stabilized plume
extent in the year 2047. O'Neal No. 4 well states in the unlikely scenario in which the injection plume or
pressure front reaches the potential fault, and the potential fault was to act as a transmissive pathway,
the upper confining Pearsall shale contains sufficient thickness and petrophysical properties required to
confine and protect injectates from leaking outside of the permitted injection zone.

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

3.4 Leakage through the Confining Layer

Section 4.4 of the MRV plan states the Sligo injection zone has competent sealing intervals present
above and below the targeted carbonate sequence of the Sligo section. The overlying Pine Island Shale
Member of the Pearsall Formation is approximately 130 ft thick at the O'Neal No. 4 well. Above this
confining unit, the Cow Creek Limestone, Cow Creek Shale, and Bexar Shale Members of the Pearsall
Formation will act as additional confinement between the injection interval and the USDW. The MRV
plan states that the USDW lies well above the sealing properties of the formations outlined above,

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making stratigraphic migration of fluids into the USDW highly unlikely. The MRV plan also states that the
petrophysical properties of the lower Sligo and Hosston Formations make these ideal for lower
confinement. The low porosity and permeability of these underlying formations minimizes the likelihood
of downward migration of injected fluids. The relative buoyancy of injectate to the in-situ reservoir fluid
makes migration below the lower confining layer unlikely

Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through the confining layer.

3.5 Leakage from Natural or Induced Seismicity

Section 4.5 of the MRV plan states that O'Neal No. 4 well is located in an area of the Gulf of Mexico
considered to be active from a seismic perspective. Therefore, the Bureau of Economic Geology's
TexNet (from 2017 to present) and USGS's Advanced National Seismic System (from 1971 to present)
databases were reviewed to identify any recorded seismic events within 25 kilometers (km) of the
O'Neal No. 4 well. The MRV plan states the investigation identified a multitude of seismic events within
the 25-km search radius; however, the magnitude of most of the events was below 2.5. The nearest
seismic event with a recorded magnitude of 3.0 or greater was measured approximately 5.6 km
northwest of the O'Neal No. 4 well at a depth of 5 km. The results of the investigation are plotted on the
map provided in Figure 36 of the MRV plan relative to the O'Neal No. 4 well and the 25-km search
radius.

The MRV plan states the Plant will have operating procedures and set points programmed into the
control and SCADA systems to ensure operating pressures are maintained within the injection and
confining intervals' approved fracture gradients. Given the seismic activity in the area, O'Neal No. 4 well
states it will closely monitor nearby TexNet station EF71 for activity and any corresponding irregularities
in the operating pressures of the O'Neal No. 4 well.

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

Overall, the MRV plan provides an acceptable characterization of potential C02 leakage pathways as
required by 40 CFR 98.448(a)(2).

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 potential C02 leakage. Section 5 of the MRV plan
discusses the strategy that O'Neal No. 4 well will employ for detecting and quantifying surface leakage
of C02 through the pathways identified in Section 4, to meet the requirements of 40 CFR §98.448(a)(3).

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As the injectate stream contains both H2S and C02, the H2S will be a proxy for C02 leakage and therefore
the monitoring systems in place to detect H2S will also indicate a release of C02. Monitoring will occur
during the planned 12-year injection period or cessation of injection operations, plus a proposed 10-year
post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults and fractures

•	Leakage through confining seals

•	Leakage from natural or induced seismicity

A summary table of O'Neal No. 4 well's strategy for monitoring any potential C02 leakage can be found
in Table 9 of the MRV plan and is reproduced below.

Leakage Pathway

Monitoring Method

Surface equipment

Fixed H2S monitors at the Plant and well site

Visual inspections

Monitor SCADA systems for the Plant and well site

Existing wells within the MMA

Monitor C02 levels in above zone producing wells

Mechanical Integrity Tests (MTT) of O'Neal No. 4 well every 5 years

Visual inspections

Annual soil gas sampling near well locations that penetrate the Upper
Confining Zone within the AMA

Leakage through groundwater wells

Annual groundwater samples from existing water well(s)

Leakage from future wells

Monitor drilling activity and compliance with TRRC Rule 13 Regulations

Faults and Fractures

SCADA continuous monitoring at the well site (volumes and pressures)

Monitor C02 levels in above zone producing wells

Natural or induced seismicity

Monitor C02 levels in above zone producing wells

Monitor existing TexNet station

4.1 Detection of Leakage from Surface Equipment

Section 5.1 of the MRV plan states the Plant and the O'Neal No. 4 well were designed to operate in a
safe manner to minimize the risk of an escape of C02 and H2S. Leakage from surface equipment is
unlikely and would quickly be detected and addressed. The facility design minimizes leak points through
the equipment used, and key areas are constructed with materials that are NACE and API compliant. A
baseline atmospheric C02 concentration will be established prior to commencing operation once facility
construction has been completed. Ambient H2S monitors will be located at the plant and near the
O'Neal No. 4 well site for local alarm and are connected to the SCADA system for continuous monitoring.

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According to the MRV plan, the plant and the O'Neal No. 4 well are continuously monitored through
automated control systems. In addition, field personnel conduct routine visual field inspections of
gauges and gas monitoring equipment. The effectiveness of the internal and external corrosion control
program is monitored through the periodic inspection of the corrosion coupons and inspection of the
cathodic protection system. These inspections and the automated systems allow O'Neal No. 4 well to
detect and respond to any leakage situation quickly. The surface equipment will be monitored for the
injection and post-injection period. The MRV plan states should leakage be detected during active
injection operations, the volume of C02 released will be calculated based on operating conditions at the
time of the event, per 40 CFR 98.448(a)(5) and 40 CFR 98.444(d).

The MRV plan states pressures, temperatures, and flow rates through the surface equipment are
continuously monitored during operations. If a release occurred from surface equipment, the amount of
C02 released would be quantified based on the operating conditions, including pressure, flow rate,
percentage of C02 in the injectate, size of the leak-point opening, and duration of the leak.

Table 9 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from surface equipment.

Thus, the MRV plan provides adequate characterization of the O'Neal No. 4 well's approach to detect
potential leakage through surface equipment as required by 40 CFR 98.448(a)(3).

4.2 Detection of Leakage through Existing and Future Wells Within the MMA

Section 4.2 of the MRV plan states that O'Neal No. 4 well continuously monitors and collects injection
volumes, pressures, and temperatures through their SCADA systems, for the O'Neal No. 4 well. This data
is reviewed by qualified personnel and will follow response and reporting procedures when data
exceeds acceptable performance limits. A change of injection or annular pressure would indicate the
presence of a possible leak and be thoroughly investigated. In addition, O'Neal No. 4 well states MITs
are performed every 5 years, as expected by the TRRC and UIC, and would also indicate the presence of
a leak. Upon a negative MIT, the well would be isolated and investigated to develop a leak mitigation
plan.

As discussed previously in the MRV plan, TRRC Rule 13 would ensure that new wells in the field would
be constructed to prevent migration from the injection interval.

In addition to the fixed monitors described previously, the MRV plan states that the facility will also
establish and operate an in- field monitoring program to detect C02 leakage within the AMA. This would
include H2S monitoring as a proxy for C02 at the well site and annual soil gas samples taken near any
identified wells that penetrate the injection interval within the AMA. These samples will be analyzed by
a qualified third party. Prior to commencing operation, and through the post-injection monitoring
period, O'Neal No. 4 well states it will have these monitoring systems in place.

The MRV plan states that currently, there is only one well in the MMA identified that penetrates the
injection interval. This well was plugged and abandoned in 2007. The TRRC records are provided in

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Appendix A-4. O'Neal No. 4 well will take an annual soil gas sample from this area, which will be
analyzed by a third-party lab. Additional monitoring will be added as the AMA is updated over time.

The MRV plan states O'Neal No. 4 well will also utilize shallower producing gas wells as proxies for
above-zone monitoring wells. Production data from these wells is analyzed for monthly production
statements, and therefore would be an early indicator of any possible subsurface issues. Should any
material change from historical trends in the C02 concentration occur, O'Neal No. 4 well would
investigate and develop a corrective action plan. Should any C02 migrate vertically from the Sligo, the
magnitude risk of this event is very low, as the producing reservoir provides an ideal containment given
the upper confining zone of this reservoir has proven competent.

Groundwater Quality Monitoring

According to the MRV plan, O'Neal No. 4 well will monitor the groundwater quality above the confining
interval by sampling from groundwater wells near the O'Neal No. 4 well and analyzing the samples with
a third-party laboratory on an annual basis. In the case of O'Neal No. 4 well, five existing groundwater
wells have been identified within the AMA, as shown in Figure 38 of the MRV plan. Initial groundwater
quality tests will be performed to establish a baseline prior to commencing operations.

Table 9 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected through existing and future wells within the MMA.

Thus, the MRV plan provides adequate characterization of O'Neal No. 4 well's approach to detect
potential leakage through existing and future wells within the MMA as required by 40 CFR 98.448(a)(3).

4.3 Detection of Leakage through Faults, Fractures, or Confining Seals

Section 5.3 of the MRV plan states that the facility will continuously monitor the operations of the
O'Neal No. 4 well through the automated controls and SCADA systems. Any deviation from normal
operating volume and corresponding injection pressure could indicate movement into a potential leak
pathway, such as a fault or breakthrough of the confining seal, and it would trigger an alert due to a
change in the injection pressure. Any such alert would be reviewed by field personnel and appropriate
action would be taken, including shutting in the well, if necessary.

According to the MRV plan, the facility will also utilize shallower producing wells as proxies for above-
zone monitoring wells. Production data is analyzed regularly for monthly production statements and
therefore would be an early indicator of any possible subsurface issues. Should any material change
from historical trends in the C02 concentration occur, O'Neal No. 4 well would investigate and develop a
corrective action plan. The MRV plan also states should any C02 migrate vertically from the Sligo
Formation, the magnitude risk of this event is very low, as the producing reservoir provides an ideal
containment given the upper confining zone has proven competent.

Table 9 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected through faults and fractures.

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Thus, the MRV plan provides adequate characterization of O'Neal No. 4 well's approach to detect
potential leakage through faults, fractures, or confining seals as required by 40 CFR 98.448(a)(3).

4.4 Detection of Leakage from Natural or Induced Seismicity

The MRV plan states that while the likelihood of a natural or induced seismicity event is low, O'Neal No.
4 well plans to use the nearest TexNet seismic monitoring station, EF71, to monitor the area around the
facility. The TexNet station is approximately 3 mi to the northwest, as shown in Figure 38 of the MRV
plan. The MRV plan states that this is a sufficient distance to allow for accurate and detailed monitoring
of the seismic activity in the area. O'Neal No. 4 well will monitor this station for any seismic activity, and
if a seismic event of 3.0 magnitude or greater is detected, it will review the injection volumes and
pressures of the O'Neal No. 4 well to determine if any significant changes have occurred that would
indicate potential leakage.

The MRV plan also states O'Neal No. 4 well will continuously monitor operations through the SCADA
system. Any deviation from normal operating pressure and volume set points would trigger an alarm for
investigation by operations staff. Such a variance could indicate movement into a potential leak
pathway, such as a fault or breakthrough of the confining seal. Any such alert would be reviewed by field
personnel and appropriate action would be taken, including shutting in the well, if necessary.

Table 9 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from natural or induced seismicity.

Thus, the MRV plan provides adequate characterization of O'Neal No. 4 well's approach to detect
potential leakage from natural or induced seismicity as required by 40 CFR 98.448(a)(3).

4.5 Quantification

Section 7.4 of the MRV plan states the potential for pathways for all previously mentioned forms of
leakage is unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, O'Neal No. 4 well believes the most appropriate method to quantify the mass of C02
released will be determined on a case-by-case basis. Any mass of C02 detected leaking to the surface
will be quantified by using industry proven engineering methods including, but not limited to,
engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling, and
history-matching of the sequestering reservoir performance, among others. If any leakage were to be
detected, the volume of C02 released would be quantified based on the operating conditions at the time
of release, in accordance with 40 CFR 98.448(a)(5).

4.6 Determination of Baselines

Section 6 of the MRV plan identifies the strategies that the facility will undertake to establish the
expected baselines for monitoring C02 surface leakage per 40 CFR 98.448(a)(4). O'Neal No. 4 well will

-------
also use existing SCADA monitoring systems to identify changes from the expected performance that
may indicate leakage of C02. The MRV plan identifies the following strategies for determining baselines:

Visual Inspections

The MRV plan states regular inspections will be conducted by field personnel at the Plant and the O'Neal
No. 4 well site. These inspections will aid in identifying and addressing possible issues to minimize the
risk of leakage. If any issues are identified, such as vapor clouds or ice formations, corrective actions will
be taken to address such issues.

CO2/H2S Detection

The MRV plan states that in addition to the fixed monitors in the Plant and at the wellsite, the facility
will perform an annual in-field sampling program to monitor and detect any C02 leakage within the
AMA. This will consist of soil gas sampling near any artificial penetrations of the injection zone and
sampling of water wells. These probes have special membrane inserts that collect the gas samples over
a 21-day period. These will be analyzed by a third-party lab to be analyzed for C02, H2S, and trace
contaminants typically found in a hydrocarbon gas stream. The lab results will be provided in the annual
report should they indicate a material variance from the baseline. Initial samples will be taken and
analyzed before the commencement of operations and will establish the baseline reference levels.

Operational Data

The MRV plan states upon starting injection operations, baseline measurements of injection volumes
and pressures will be recorded. Any significant deviations over time will be analyzed for indication of
leakage of injectate and the corresponding component of C02.

Continuous Monitoring

The MRV plan states the total mass of C02 emitted by surface leakage and equipment leaks will not be
measured directly, as the injection stream for this project is near the OSHA Permissible Exposure Limit
(PEL) 8-hour Time Weighted Average (TWA) of 5,000 ppm. Direct leak surveys present a hazard to
personnel due to the presence of H2S in the gas stream. Continuous monitoring systems will trigger
alarms if there is a release. The mass of the C02 released would be calculated based on the operating
conditions, including pressure, flow rate, percentage of C02, size of the leak-point opening, and
duration. This method is consistent with 40 CFR 98.448(a)(5) and 40 CFR 98.444(d), allowing the
operator to calculate site-specific variables used in the mass balance equation.

The MRV plan also states in the case of a depressuring event, the acid gas stream will be sent to a flare
stack to be safely processed and will be reported under reporting requirements for the plant. Any such
events will be accounted for in the sequestered reporting volumes consistent with Section 7.4 of the
MRV plan.

Groundwater Monitoring

-------
The MRV plan states initial samples will be taken from groundwater wells in the area of the O'Neal No. 4
well upon approval of the MRV plan, and before commencement of C02 injection. These samples will be
analyzed, and reports prepared by a third-party laboratory testing for pH, total dissolved solids (TDS),
C02, and volatile organic compounds (VOC). Initial samples will be taken and analyzed before the
commencement of operations and will establish the baseline reference levels. Sampling select wells will
be performed annually. The MRV plan also states that in the event a material deviation in the sample
analysis occurs, the results will be provided in the annual report.

Thus, the MRV plan provides an acceptable approach for detecting and quantifying leakage and for
establishing expected baselines in accordance with 40 CFR 98.448(a)(3) and 40 CFR 98.448(a)(4).

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, the C02 received for the O'Neal No. 4 well is wholly injected and not mixed
with any other supply. Therefore, the facility concludes that the annual mass of C02 injected will equal
the amount received. The MRV plan states that any future streams would be metered separately before
being combined into the calculated stream.

O'Neal No. 4 well provides an acceptable approach to calculating the mass of C02 received in
accordance with subpart RR requirements.

5.2 Determining Mass of CO2 Injected

Section 7.2 of the MRV plan states that the mass of C02 injected will be measured with a volumetric flow
meter. The total annual mass of C02, in metric tons, will be calculated by multiplying the mass flow by
the C02 concentration in the flow according to Equation RR-5:

p= 1

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.

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.

u = Flow meter.

O'Neal No. 4 well provides an acceptable approach to calculating the mass of C02 injected in accordance
with subpart RR requirements.

5.3 Mass of CO2 Produced

The MRV plan states that O'Neal No. 4 well is not part of an enhanced oil recovery project; therefore, no
C02 will be produced.

5.4 Calculation of Mass of CO2 Emitted by Surface Leakage

The MRV plan states that the mass of C02 emitted by surface leakage and equipment leaks will not be
measured directly due to the H2S concentration in the injection stream. Direct leak surveys are
dangerous and present a hazard to personnel. Because no venting is expected to occur, the calculations
would be based on the unusual event that a blowdown is required, and those emissions would be sent
to a flare stack and reported as a part of the required GHG reporting for the plant. Any leakage would be
detected and managed as an upset event. Continuous monitoring systems should trigger an alarm upon
a release of H2S and C02. The mass of the C02 released would be calculated for the operating conditions,
including pressure, flow rate, size of the leak point opening, and duration of the leak. This method is
consistent with 40 CFR 98.448(a)(5).

Should C02 surface leakage occur, the MRV plan states that the mass emitted would be calculated for
each surface pathway according to methods outlined in the plan and totaled using Equation RR-10 as

E = ^
x-1

follows:

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.

Calculation methods using equations from subpart W will be used to calculate C02 emissions due to any
surface leakage between the flow meter used to measure injection quantity and the injection wellhead.

O'Neal No. 4 well 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 on Equation RR-12. Data collection for calculating the amount of C02 sequestered will
begin once the subsurface recompletion and surface facilities construction has been completed, as well
as the approval of this MRV plan. As this well will not actively produce oil or natural gas, or any other
fluids, as follows:

C02 = C02i ~ C02e ~ C02fi

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

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

The MRV plan states that C02Fi will be calculated in accordance with subpart W reporting of GHGs.
Because no venting is expected to occur, the calculations would be based on the unusual event that a
blowdown is required, and those emissions sent to flares and reported as part of the required GHG
reporting for the gas plant.

-------
O'Neal No. 4 well 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 the O'Neal Gas Unit Well No. 4 meets the requirements of 40 CFR 98.448.
The regulatory provisions of 40 CFR 98.448(a), which specifies the requirements for MRV plans, are
summarized below along with a summary of relevant provisions in the MRV plan.

Subpart RR MRV Plan Requirement

O'Neal Gas Unit Well No. 4 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 AMA boundary was established by
superimposing the area based on a half-mile buffer
around the anticipated plume location at the end of
injection (2037) with the area of the projected free-
phase C02 plume at five additional years (2047). Since
the AMA boundary was determined to fall within the
MMA boundary, the defined MMA was also used to
define the effective AMA.

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 and
future wells within the MMA; leakage through faults
and fractures; leakage through the upper confining
layer; and leakage from natural or induced seismicity.
The MRV plan analyzes the likelihood, magnitude, and
timing of surface leakage through these pathways.

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

Section 5 and Section 7 of the MRV plan describe 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 SCADA systems, MITs,
groundwater sampling, and in-field monitors.

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

Section 6 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

Section 7 of the MRV plan describes O'Neal No. 4 well's
approach to determining the amount of C02

-------
calculate site-specific variables for the mass
balance equation.

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.

Section 1 of the MRV plan provides the well
identification numbers for the O'Neal No. 4 well (API
No. 42-025-32658, UIC No. 56819). The MRV plan
specifies that the wells are pending a UIC Class II permit
under TRRC Rule 9 and Rule 36.

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 8 of the MRV plan states that the mass of C02
sequestered in subsurface geologic formations will be
calculated based on Equation RR-12, assuming an
expected injection start date of October 1, 2024.

17

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Appendix A: Final MRV Plan

-------
©)zona

Carbon Capture & Sequestration

Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
O'Neal Gas Unit Well No. 4

Bee County, TX

Prepared for Ozona CCS, LLC
San Antonio, TX

By

Lonquist Sequestration, LLC
Austin, TX

Version 4.0
August 2024

LONQUIST

SEQUESTRATION LLC

Hi

-------
INTRODUCTION

Ozona CCS, LLC (Ozona) has a pending Class II acid gas injection (AGI) permit application with the
Texas Railroad Commission (TRRC), which was submitted in September of 2023 for its O'Neal Gas
Unit Well No. 4 (O'Neal No. 4), API No. 42-025-32658. Granting of this application would
authorize Ozona to inject up to 1.5 million standard cubic feet per day (MMscf/D) of treated acid
gas (TAG) into the Sligo Formation at a depth of 15,874 feet (ft) to 16,056 ft, with a maximum
allowable surface pressure of 7,920 pounds per square inch gauge (psig). The TAG for this AGI
well is associated with StarTex's Pawnee Treating Facility, located in a rural area of Bee County,
Texas, approximately 2.0 miles (mi) south of Pawnee, Texas, as shown in Figure 1.

Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4

Subpart RR MRV Plan - O'Neal No. 4

Page 2 of 80

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Ozona is submitting this Monitoring, Reporting, and Verification (MRV) plan to the EPA for
approval underTitle 40, U.S. Code of Federal Regulations (40 CFR) §98.440(a), Subpart RR, of the
Greenhouse Gas Reporting Program (GHGRP). In addition to submitting this MRV plan to the
EPA, Ozona has applied to the TRRC for the O'Neal GU No. 4's Class II permit. Ozona plans to
inject TAG for approximately 12 years. Table 1 shows the expected composition of the gas stream
to be sequestered from the nearby treating facility.

Table 1 - Expected TAG Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

Subpart RR MRV Plan - O'Neal No. 4

Page 3 of 80

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ACRONYMS AND ABBREVIATIONS

AMA
BCF
CH4
CMG

C02
E

EOS

EPA

ESD

FG

ft

GAPI

GAU

GEM

GHG

GHGRP

GL

H2S

JPHIE

mD

mi

MIT

MM

MMA

MCF

MMcf

MMscf

Subpart RR MRV Plan - O'Neal No. 4

Active Monitoring Area
Billion Cubic Feet
Methane

Computer Modelling Group, Ltd.

Carbon Dioxide (may also refer to other carbon

oxides)

East

Equation of State
Environmental Protection Agency
Emergency Shutdown
Fracture Gradient
Foot (Feet)

Gamma Units of the American Petroleum Institute
Groundwater Advisory Unit
Computer Modelling Group's GEM 2023.2
Greenhouse Gas

Greenhouse Gas Reporting Program
Ground Level Elevation
Hydrogen Sulfide

Effective Porosity (corrected for clay content)

Millidarcy

Mile(s)

Mechanical Integrity Test
Million

Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet

Page 4 of 80

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Mscf/D	Thousand Standard Cubic Feet per Day

MMscf/D	Million Standard Cubic Feet per Day

MRV	Monitoring, Reporting, and Verification

v	Poisson's Ratio

N	North

NW	Northwest

OBG	Overburden Gradient

PG	Pore Gradient

pH	Scale of Acidity

ppm	Parts per Million

psi	Pounds per Square Inch

psig	Pounds per Square Inch Gauge

S	South

SE	Southeast

SF	Safety Factor

SWD	Saltwater Disposal

TAC	Texas Administrative Code

TAG	Treated Acid Gas

TOC	Total Organic Carbon

TRRC	Texas Railroad Commission

UIC	Underground Injection Control

USDW	Underground Source of Drinking Water

W	West

Subpart RR MRV Plan - O'Neal No. 4

Page 5 of 80

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TABLE OF CONTENTS

INTRODUCTION	2

ACRONYMS AND ABBREVIATIONS	4

SECTION 1 - UIC INFORMATION	10

1.1	Underground Injection Control Permit Class: Class II	10

1.2	UIC Well Identification Number	10

1.3	Facility Address	10

SECTION 2 - PROJECT DESCRIPTION	11

2.1	Regional Geology	11

2.1.1	Geologic Setting and Depositional Environment	13

2.1.2	Regional Structure and Faulting	15

2.2	Site Characterization	17

2.2.1	Stratigraphy and Lithologic Characteristics	17

2.2.2	Upper Confining Interval - Pearsall Formation	19

2.2.3	Injection Interval - Upper Sligo Formation	21

2.2.4	Formation Fluid	23

2.2.5	Fracture Pressure Gradient	24

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations	25

2.3	Local Structure	25

2.4	Injection and Confinement Summary	30

2.5	Groundwater Hydrology	30

2.6	References	34

2.7	Description of the Injection Process	35

2.7.1 Current Operations	35

2.8	Reservoir Characterization Modeling	35

2.8.1 Simulation Modeling	39

SECTION 3 - DELINEATION OF MONITORING AREA	48

3.1	Maximum Monitoring Area	48

3.2	Active Monitoring Area	50

SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE	52

4.1	Leakage from Surface Equipment	53

4.2	Leakage Through Existing Wells Within the MMA	55

4.2.1	Future Drilling	59

4.2.2	Groundwater Wells	59

4.3	Leakage Through Faults and Fractures	61

4.4	Leakage Through the Upper Confining Zone	61

4.5	Leakage from Natural or Induced Seismicity	61

SECTION 5 - MONITORING FOR LEAKAGE	64

5.1	Leakage from Surface Equipment	65

5.2	Leakage Through Existing and Future Wells Within the MMA	67

5.2.1 Groundwater Quality Monitoring	68

5.3	Leakage Through Faults, Fractures, or Confining Seals	70

Subpart RR MRV Plan - O'Neal No. 4

Page 6 of 80

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5.4 Leakage Through Natural or Induced Seismicity 70

SECTION 6 - BASELINE DETERMINATIONS 72

6.1 Visual Inspections 72

6.2 H2S/ CO2 Monitoring 72

6.3 Operational Data 72

6.4 Continuous Monitoring 72

6.5 Groundwater Monitoring 73

SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION 74

7.1 Mass of CO2 Received 74

7.2 Mass of CO2 Injected 74

7.3 Mass of CO2 Produced 75

7.4 Mass of CO2 Emitted by Surface Leakage 75

7.5 Mass of CO2 Sequestered 76

SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN 77

SECTION 9 - QUALITY ASSURANCE 78

9.1 Monitoring QA/QC 78

9.2 Missing Data 78

9.3 MRV Plan Revisions 79

SECTION 10 - RECORDS RETENTION 80

Figures

Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4 2

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-

Ashby etal., 2012) 11

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby

etal., 2012) 12

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The
proposed injection interval is shaded light blue and proposed confining intervals are shaded light

yellow (modified from Bebout et al., 1981) 13

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981) 14

Figure 6-Generalized northwest to southeast schematic cross section of the Trinity Group, south
Texas (the line of section depicted in Figure 5). The red star and line represent the approximate
location of the O'Neal No. 4 (modified from Kirkland et al., 1987) 15

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated
porosity and permeability values of typical facies (modified from Talbert and Atchley, 2000).. 15
Figure 8 - Structural features and fault zones near the proposed injection site. The red star
represents the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through
Word field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).. 17

Subpart RR MRV Plan - O'Neal No. 4

Page 7 of 80

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Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted 18

Figure 11 - Porosity-Permeability Crossplot of Pearsall Formation Crushed Rock Core Data

(Swanson et al., 2016) 20

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map. The
red star represents the approximate location of the O'Neal No. 4 (modified from Bebout et al.,

1981) 20

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981) 21

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded

green >0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms 22

Figure 15 - Offset Wells Used for Formation Fluid Characterization 24

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the

location of the O'Neal No. 4 27

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the

locator map 28

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on

the locator map 29

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of

the O'Neal No. 4 (modified from Bruun, B., et al., 2016) 31

Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006) 32

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016) 32

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016) 33

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model 37

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection) 41

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation) 42

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End

of Simulation) 45

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time 46

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum

Monitoring Area 49

Figure 31 - Active Monitoring Area 51

Figure 32 - O'Neal No. 4 Wellbore Schematic 56

Figure 33 - All Oil and Gas Wells Within the MMA 57

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA 58

Figure 35 - Groundwater Wells Within the MMA 60

Figure 36 - 25-km Seismicity Review 63

Figure 37 - O'Neal No. 4 Process Flow Diagram 66

Subpart RR MRV Plan - O'Neal No. 4

Page 8 of 80

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Figure 38 - Groundwater Wells	69

Figure 39 - Seismic Events and Monitoring Station	71

Tables

Table 1 - Expected TAG Composition	3

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo

oil-field brine samples	24

Table 3 - Gas Composition	35

Table 4 - Modeled Injectate Composition	36

Table 5 - GEM Model Layer Package Properties	38

Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection	47

Table 7 - Potential Leakage Pathway Risk Assessment	52

Table 8 - Summary of TAG Monitors and Equipment	54

Table 9 - Summary of Leakage Monitoring Methods	64

Table 10 - Baseline Sampling Schedule	77

Appendices

Appendix A - TRRC O'Neal Gas Unit Well No. 4 Forms

Appendix A-l - GAU Groundwater Protection Determination
Appendix A-2 - Drilling Permit
Appendix A-3 - Completion Report
Appendix A-4 - Plugging Records

Appendix B - Area of Review

Appendix B-l - Oil and Gas Wells Within the MMA List
Appendix B-2 - Water Wells Within the MMA List

Subpart RR MRV Plan - O'Neal No. 4

Page 9 of 80

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SECTION 1 - UIC INFORMATION

This section contains key information regarding the Underground Injection Control (UIC) Permit.

1.1	Underground Injection Control Permit Class: Class II

The TRRC regulates oil and gas activities in Texas and has primacy to implement the Underground
Injection Control (UIC) Class II program. The TRRC classifies the O'Neal No. 4 as a UIC Class II well.
Ozona has applied for a Class II permit for the O'Neal No. 4 under TRRC Rules 36 (Oil, Gas, or
Geothermal Resource Operation in Hydrogen Sulfide Areas) and 46 (Fluid Injection into Productive
Reservoirs).

1.2	UIC Well Identification Number

•	O'Neal No. 4, API No. 42-025-32658, UIC No. 56819

1.3	Facility Address

•	Facility Name: StarTex Pawnee Treating Facility

•	Operator: StarTex Field Services, LLC

•	Facility ID No. 568661

•	Coordinates in North American Datum for 1983 (NAD 83) for this facility:

o Latitude: 28.622211
o Longitude: -97.992772

•	Greenhouse Gas Reporting Program ID Information:

o Ozona will report under GHGRP ID No. 587021 for this Monitoring, Reporting
and Verification plan

Subpart RR MRV Plan - O'Neal No. 4

Page 10 of 80

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SECTION 2 - PROJECT DESCRIPTION

This section discusses the geologic setting, planned injection process and volumes, and reservoir
and plume modeling performed for the O'Neal No. 4 well.

The O'Neal No. 4 will inject the TAG stream into the Sligo Formation at a depth of 15,874 ft to
16,056 ft, and approximately 14,924 ft below the base of the Underground Source of Drinking
Water (USDW). Therefore, the well and the facility are designed to protect against the leakage
out of the injection interval, to protect against contaminating other subsurface formations, and —
most critically—to prevent surface releases.

2.1 Regional Geology

The O'Neal No. 4 (API No. 42-025-32658) is located in south Texas within the Gulf of Mexico
Basin. The onshore portion of the Gulf of Mexico basin spans approximately 148,049,000 acres
and encompasses portions of Texas, Louisiana, Mississippi, Alabama, Arkansas, Missouri,
Kentucky, Tennessee, Florida, and Georgia to the state-waters boundary of the United States
(Roberts-Ashby et al., 2012). The location of the O'Neal No. 4 is designated by the red star in
Figure 2, relative to the present coastal extent and major structural features of the basin.

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-Ashby et

al., 2012)

Subpart RR MRV Plan - O'Neal No. 4

Page 11 of 80

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Figure 3 depicts a generalized stratigraphic column of the U.S. Gulf Coast, with light blue shading
signifying the proposed injection interval and green stars indicating productive formations
identified within 5 miles of the O'Neal No. 4. The injection interval is found within the Sligo
Formation, with confinement provided by the overlying Pearsall Formation and tight underlying
fades of the Lower Sligo and Hosston Formations.

System /
Series

Global
Chronostratigraphic
Units

Calabrian

Piacenzian
Zanclean

Messinian
Tortonian
Serravallian

Langhian
Burdigalian
Aquitanian

Chattian

Rupelian

Priabonian

Bartonian
Lutetian

Ypresian

Thanetian
Selandian
Danian

Maastrichtian

Campanian

Santonian
Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian
Hauterivian

Valanginian
Berriasian

North American
Chronostratigraphic
Units

Middle Mioc. Fleming Fm

Chickasawhayan

Vicksburgian

Jacksonian

Claibornian

Sabinian

Midwayan

Navarroan

Tayloran

Austinian

Eaglefordian

Woodbinian

Washitan-
Fredericksburgian

Trinitian

Nuevoleonian

Durangoan

Stratigraphic Unit

Undifferentiated

Upper Mioc.

Lower Mioc.

^X-Catahoula
W Fm /

Fm / Ss

Frio Formation

Vicksburg Formation

Jackson Group

Sparta Sand

Claiborne Group Cane River Fm

Carrizo Sand

Wilcox Group

Midway Group

Navarro Group

Taylor Group

Austin Group /
Tokio Formation /
Eutaw Formation

Eagle Ford Shale

Woodbine / Tuscaloosa Fms

Washita Group
(Buda Ls)

Fredericksburg Group ,
(Edwards Ls / Paluxy Fm)'

Glen Rose Ls
(Rusk / Rodessa Fms)

Pearsall Formation |

Sligo"^f

Hosston
Formation

UPPER CONFINING INTERVAL
INJECTION INTERVAL

LOWER CONFINING
INTERVAL

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby et al.,

2012).

Subpart RR MRV Plan - O'Neal No. 4

Page 12 of 80

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The targeted formations of this study are located entirely within the Trinity Group, as clarified by
the detailed stratigraphic column provided in Figure 4. During this time the area of interest was
located along a broad, shallow marine carbonate platform that extended along the northern rim
of the ancestral Gulf of Mexico. The Lower Cretaceous platform spanned approximately 870 mi
from western Florida to northeastern Mexico, with a shoreline-to-basin margin that ranged
between 45 to 125 mi wide (Yurewicz et al., 1993).

00
D
O

O
<
>—
UJ

ce
o

Pearsal

Sliao

H osston

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The proposed
injection interval is shaded light blue and proposed confining intervals are shaded light yellow (modified

from Bebout et ai., 1981).

2.1.1 Geologic Setting and Depositional Environment

The depositional environment during the Lower Cretaceous generally consisted of a well-defined
platform margin with a shallow marine platform interior or lagoon to the north, a shallow marine
outer platform to the south, and a foreslope that gradually dipped southward towards the basin
center. The platform margin remained stable for tens of millions of years during the Cretaceous
but experienced episodic changes in sea level that resulted in cyclic deposition of several key
facies that vary both spatially and within the geologic section. Facies distributions were heavily
impacted by positioning relative to the margin, the height of the water column at any given time,
and the degree of energy or wave action within the system (Galloway, 2008; Yurewicz et al.,
1993).

In general, long stands of reef development and ooid shoaling developed primary porosity and
permeability along the shallow, high-energy carbonate platform and represent reservoir quality

Subpart RR MRV Plan - O'Neal No. 4

Page 13 of 80

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rock found within Cretaceous reef deposits. Deeper, basinward deposits tend to result in tighter
petrophysical properties due to a relative increase in the amount of entrained clay associated
with the heightening of the water column while moving downslope. Backreef deposits have the
potential for porosity development but tend to have low permeability due to a general lack of
wave action caused by restricted access to open water by the platform margin. Facies and
petrophysical properties of the Lower Cretaceous section are anticipated to be relatively
homogenous moving southwest-northwest along reef trend, with increased heterogeneity
moving northwest-southeast due to the orientation of the carbonate rim and its effect on
deposition and facies distributions (Yurewicz et a I1993).

Figure 5 displays the paleogeography during deposition of the Lower Cretaceous section to
visually demonstrate the position of the O'Neal No. 4 relative to the Sligo shelf margin and updip
extents of Sligo deposition. A generalized schematic cross section of the Trinity Group is provided
in Figure 6, which nearly intersects the project area from the northwest. The schematic illustrates
the gross section thickening basinward, with primary reservoir development improving with
proximity to the reef margin. Figure 7 displays a depositional model of the Lower Cretaceous
carbonate platform to visually conceptualize depositional environments and anticipated
petrophysical properties of facies introduced above.

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the
approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981).

Subpart RR MRV Plan - O'Neal No. 4 Page 14 of 80

-------
outcrop

subsurface

NW

SE

D
a

o
<

I

QC

o

o
w

5

D

Figure 6 - Generalized northwest to southeast schematic cross section of the Trinity Group, south Texas
(the line of section depicted in Figure 5). The red star and line represent the approximate location of the

O'Neal No, 4 (modified from Kirkland et al., 1987)

0=15-25
K>200

0=10-15
K=20-100

SHOAL

0=2-12
K<1

BACKREEF

Windward Fairweather Wave Base

FOREREEF
W CLAY

FOREREEF
W/NO CLAY

CLAY-RICH

LEGEND

Sedimentary Structures Grains

* Current Rippte
—— Flaser/Wavy Bedding
— mm Laminations
—v— Mud Cracks

- Ptanar and Festoon Bedding
1J Burrow Clay Seam

e Ootd Q) Oyster uncfrff
. PetokJ Bivalve uidiff.
C> Rudtst undrff. § Gastropod
Solitary Coral ® Echinoderm
O Dic&conus @ Ammonite

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated porosity and
permeability values of typical facies (modified from Talbert and Atchley, 2000).

2.1.2 Regional Structure arid Faulting

The Gulf of Mexico basin was formed by crustal extension and sea-floor spreading associated
with the Mesozoic breakup of Pangea. Rifting of northwest to southeast trending transfer faults
during the Middle Jurassic lasted approximately 25 million years and resulted in variable
thickness of the transcontinental crust underlying the region. By the Lower Cretaceous time, the
general outline and morphology of the Gulf were similar to that of present-day (Galloway, 2008;

GLEN ROSE

PEARSALL (undifferentiated!

SYCAMORE I

I HOSSTON

SLIGO

HAYNESVILLE

PALEOZOIC
|undif(erentiatedl

Subpart RR MRV Plan - O'Neal No. 4

Page 15 of 80

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Yurewicz et al,, 1993). Lower Cretaceous tectonic activity was limited to regional subsidence
associated with areas of variable crustal thickness and local structuring caused by movement of
Louann Salt (Yurewicz et al., 1993). The combination of these processes resulted in the structural
development of regional arches, grabens, uplifts, embayments, salt domes, and salt basins
around the northern edge of the basin (Dennen and Hackley, 2012; Galloway, 2008). The location
of these structural features can be referenced in Figures 2 and 8 relative to the location of the
O'Neal No. 4.

The schematic dip-oriented cross section displayed in Figure 9 presents a common interpretation
of the current structural setting. Most of the published literature suggests that faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as displayed in Figure 9,
with shallow faulting dying out before reaching the Pearsall Formation. However, one source did
interpret the potential for faulting to the south (Swanson et al., 2016). The closest potential fault
is depicted in Figure 8 relative to the location of the O'Neal No. 4. According to the map, the
interpreted fault lies approximately 4.25 miles south-southeast of the well and approximately 3.9
miles south-southeast of the stabilized plume extent in the year 2047.

50
_L_

~T—r

100 Kilometers

100 Miles
J I

EXPLANATION

O
*

Uplift

Plateau

Basin

TPS boundary
Fault zone

Lower Cretaceous shelf margin
County line

Field in Edwards Limestone
associated with fault zones

Salt structure

Anticlinal axis; large arrow indicates
direction of plunge

GOM Gulf of Mexico

Figure 8 - Structural features and fault zones near the proposed injection site. The red star represents
the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

Rio Grande
embayment

Edwards plateau

Subpart RR MRV Plan - O'Neal No. 4

Page 16 of 80

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! MMe	EXPLANATION

-|	1	| | Edwards Limestone, potential reservoir

1 Kilometer	facies (shallow-water facies)

1 Pearsall Fm.

~ Sligo Formation, wedges of downslope
debris

Fault

Sligo Fm.

Hosston Fm.

Sligo Fm.
shelf margin

Edwards Ls.

Pearsall Fm.

Word field

Published
Edwards Ls.
shelf margin

Taylor Gp.

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through Word
field, northeast of the O'Neal No. 4 project area (modified from Swanson et a!., 2016).

2.2 Site Characterization

The following section discusses site-specific geological characteristics of the O'Neal No. 4 well
2.2.1 Stratigraphy and Lithologic Characteristics

Figure 10 depicts openhole logs from two offset wells (API No. 42-025-00473 and API No. 42-025-
31892) to the O'Neal No. 4, indicating the injection and primary upper confining zones. The
Tomasek No. 1 (API No. 42-025-00473) is located approximately 1 mi northeast of the O'Neal No.
4 and displays the shallow section from 0-8,200 ft. The Gordon No. 3 (API No. 42-025-31892) is
located approximately 1.6 mi northeast of the O'Neal No. 4 and displays a shallow section from
8,200-16,400 ft.

Subpart RR MRV Plan - O'Neal No. 4

Page 17 of 80

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BB-SOUTHTEX, LLC

TOMASEKGAS UNIT 1

42025004730000

-:r::

BASE USDW

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Figure 10-Type Log with Tops, Confining, and Injection Intervals Depicted

Subpart RR MRV Plan - O'Neal No. 4

Page 18 of 80

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2.2.2 Upper Confining Interval - Pearsall Formation

Following the deposition of the Sligo Formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
Formation throughout the region (Roberts-Ashby et al., 2012). The Pine Island Shale consists of
alternating beds of pelagic mudstone, hemipelagic mudstone, and Fe-rich dolomitic mudstone
interpreted to have been deposited along the outer ramp. This is in agreement with core data
published by Bebout and others (1981), and later by Swanson and others (2016), who identified
the presence of C. Margerelli, a nannofossil indicative of anoxic conditions. The core-derived
porosity-permeability relationship displayed in Figure 11 suggests that the permeability of the
Pine Island Shale is incredibly low and stays below 0.0001 mD, regardless of porosity (Figure 11;
Hull, 2011). This is further supported by the 2012 U.S. Geological Survey (USGS) CO2 Storage
Resource Assessment, which suggests that the Pine Island Shale contains the physical properties
required to act as a regional seal and was chosen as the upward confining interval for their
C50490108 Storage Assessment Unit (SAU) assessment of the Gulf Coast. The 2012 USGS report
also noted that the Pine Island Shale is a sufficient regional seal with as little as 50 ft of contiguous
shale development. The top of the Pearsall is encountered at a depth of 15,339 ft in the O'Neal
No. 4, with a gross thickness of 535 ft (Figure 14). The Pine Island Shale member is approximately
130 ft thick at the O'Neal No. 4 location, with deposition of additional members of the overlying
Pearsall Formation, which include the Cow Creek Limestone, Cow Creek shale, and Bexar Shale
Members (Roberts-Ashby et al., 2012; Swanson et al., 2016).

The seismic line displayed in Figure 12 runs northwest to southeast across the Stuart City reef
trend southwest of the project area. The top of the Buda, Pearsall, and Sligo Formation markers
are depicted in color to demonstrate the lateral continuity of the section near the O'Neal No. 4.
Seismic reflectors within the Pearsall Formation appear to lack deformation, suggesting
consistent deposition over the reef margin. This is in agreement with reviewed published
literature, which suggests deposition of the Pine Island Shale occurred during widespread marine
transgression (Bebout et al., 1981; Hull, 2011.; Roberts-Ashby et al., 2012, Swanson et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 19 of 80

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0.0001
(100 nd;

Permeability and Porosity-
Crushed Rock Data

"O

E

-O

ro

d)

E

-------
2.2.3 Injection Interval - Upper Sligo Formation

The Sligo Formation underlies the Pearsall Formation and is predominately composed of shelf-
edge limestones that were deposited along the Lower Cretaceous platform (Roberts-Ashby et al.,
2012). However, the Cretaceous also experienced episodic changes in sea level that resulted in
the deposition of cyclic Sligo facies that vary both spatially and within the geologic section. The
overall Sligo interval is interpreted to be a transgressive sequence occasionally interrupted by
progradational cycles that consists of porous shoaling-upward sequences that represent primary
reservoir potential within the system (Bebout et al., 1981). Facies distributions of these reef
complexes are heavily impacted by positioning relative to the margin, the height of the water
column at any given time, and the degree of energy or wave action within the system (Galloway,
2008). Figure 13 depicts an idealized environmental setting of the Lower Cretaceous platform
during deposition. Primary porosity and permeability of the upper Sligo Formation tends to
develop in high-energy sequences with normal marine conditions that are dominated by the
deposition of oolitic and skeletal grainstones.

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)

According to the 2012 USGS CO2 Storage Resource Assessment, "the average porosity in the
porous intervals of the storage reservoir decreases with depth from 9 to 16 percent" for their
C50490108 DEEP SAU assessment of the Gulf Coast (>13,000 ft). The study also reported that
"the average permeability in the storage reservoirs decreases with depth from 0.05 to 200 mD,
with a most-likely value of 8 mD" for their C50490108 DEEP SAU assessment of the Gulf Coast
(Roberts-Ashby et al., 2012).

The top of the upper Sligo is encountered at a depth of 15,874 ft in the O'Neal No. 4 with a gross
thickness of 183 ft (Figure 14). The type log displayed in Figure 14 plots effective porosity for the
confining interval and the total porosity of the injection interval, to account for the increased

Subpart RR MRV Plan - O'Neal No. 4

Page 21 of 80

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volume of shale (Vshale) seen in the Pearsall Formation. The porosity data was compared to the
analysis performed by Nutech to generate a permeability curve with a reasonable porosity-
permeability relationship. The permeability curve was generated utilizing the Coates
permeability equation, incorporated with a 20% irreducible brine saturation to match analysis
provided by Nutech. Petrophysical analysis of the O'Neal No. 4 indicates an average porosity of
4.6%, a maximum porosity of 15%, an average permeability of 0.16 mD, and a maximum
permeability of 3.3 mD. These curves have been extrapolated to the injection site and used to
establish reservoir characteristics in the plume model.

BB-SOUTHTEX, LLC

ONEAL GAS UNIT 4

o

42025326580000

GR

0

150

0.2

ILD

> 5 ohm 2000

K_COATES20
10	0

0.3

PHIE

>0 %

0

DPHI

0.3

> 0 %

0

Pearsall

Very Low Perm:
Pine Island Shale

Very Low Perm:
Lower Sligo
Formation

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded green
>0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms.

Subpart RR MRV Plan - O'Neal No. 4

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2.2.4 Formation Fluid

The USGS National Produced Waters Geochemical Database version 3.0 was reviewed for
chemical analyses of Sligo oil-field brines within the state of Texas (Blondes et al., 2023). Only
two samples were identified from the Sligo Formation: one located approximately 29 mi north-
northeast in Karnes County and one located approximately 72 mi northeast in Gonzales County.
The locations of these wells are shown in Figure 15 relative to the O'Neal No. 4. A summary of
water chemistry analyses conducted on the two Texas Sligo oil-field brine samples is provided in
Table 2 (page 25).

Averages from the samples were utilized for model assumptions due to the minimal Sligo sample
availability and wide geographic spread of Sligo analysis. Total Dissolved Solids (TDS) of the
samples contain a wide range of reported values but averaged 176,470 parts per million (ppm).
Model sensitivities were established by running iterations with varying TDS values to understand
the effect of brine concentrations on plume extents. The results suggested higher density brine
values lead to smaller plumes; therefore, a value of 150,000 ppm was established in the model
for a conservative approach. If the actual formation fluid sample that will be tested during the
recompletion work produces a material difference in the plume, Ozona will submit an updated
MRV plan.

Based on the results of the investigation, in situ Sligo reservoir fluid is anticipated to contain
greater than 20,000 ppm TDS near the O'Neal No. 4, qualifying the aquifer as saline. These
analyses indicate the in situ reservoir fluid of the Sligo Formation is compatible with the proposed
injection fluids.

Subpart RR MRV Plan - O'Neal No. 4

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Figure 15 - Offset Wells Used for Formation Fluid Characterization

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo oil-field

brine samples.

Measurement

Karnes County
Sample

Gonzales
County Sample

Average

Total Dissolved Solids (mg/L)

234,646

117,470

176,058

Sodium (mg/L)

51,168

27,909

39,539

Calcium (mg/L)

34,335

8,684

21,510

Chloride (mg/L)

146,500

57,811

102,156

Sample Depth (ft)

13,580 to 13,660

8,290-8,305

-

pH

5.9

8.2

7.05

2.2.5 Fracture Pressure Gradient

The fracture pressure gradient was obtained from a fracture report taken during the April 1993
completion of the Sligo interval in the O'Neal No. 4. The Sligo was perforated between the depths
of 15,874 ft and 16,056 ft, with continuous monitoring during the minifrac job. The report noted
a calculated fracture gradient of 0.954 psi/ft based on an initial shut-in pressure (ISIP) of 8,312

Subpart RR MRV Plan - O'Neal No. 4

Page 24 of 80

-------
psi. A 10% safety factor was then applied to the calculated gradient, resulting in a maximum
allowed bottomhole pressure of 0.86 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.

2.2.6 Lower Confining Interval - Lower Sligo and Hosston Formations

The O'Neal No. 4 reaches its total depth in the lower Sligo Formation, directly below the upper
Sligo proposed injection interval. The lower Sligo is interpreted by Bebout and others (1981) to
represent the seaward extension of the low-energy lagoon and tidal-flat system of the underlying
Hosston Formation, a sequence of siliciclastics, evaporites, and dolomitic mudstone (Figure 16).
The Hosston to lower Sligo "contact" represents a gradational package with a decrease in
terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the lower Sligo. The lower Sligo consists of numerous cycles
of subtidal to supratidal carbonates deposited in a low-energy lagoon and tidal-flat system
(Bebout et al., 1981). These low permeability facies of the lower Sligo and underlying Hosston
Formation will provide lower confinement to the upper Sligo injection interval. Figure 16
illustrates the typical environmental setting for the deposition of tidal flat facies along the Lower
Cretaceous margin. The type log displayed in Figure 14 (Section 2.2.3) illustrates that the
porosity of the lower Sligo ranges between 0-2% with permeability staying close to 0 mD.
Therefore, the petrophysicai characteristics of the lower Sligo and Hosston are ideal for
prohibiting the migration of the injection stream outside of the injection interval.

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

2.3 Local Structure

Structures surrounding the proposed sequestration site were influenced by regional arches,
grabens, uplifts, embayments, movement of Louann Salt, and the development of carbonate reef
complexes around the northern edge of the basin. However, one potential fault was identified
in the literature within proximity and lies approximately 4.25 mi south-southeast of the well and

Subpart RR MRV Plan - O'Neal No. 4

Page 25 of 80

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approximately 3.9 mi south-southeast of the stabilized plume extent in the year 2062 (Swanson
et al., 2016). The location of these structural features can be referenced in Figures 2 and 8
relative to the location of the O'Neal No. 4.

A subsea true vertical depth (SSTVD) structure map on the top of the Sligo Formation is provided
in Figure 17. The map illustrates the gentle basinward dip of the Sligo from the northwest to the
southeast. The structural cross sections provided in Figures 18 and 19 (pages 28 and 29,
respectively) illustrate the structural changes encountered in moving away from the O'Neal No.
4 site. The figures also demonstrate the laterally continuous nature of the Pearsall Formation
that overlies the injection interval, with sufficient thickness and modeled petrophysical
properties to alleviate the risk of upward migration of injected fluids. Section 2.1.2, discussing
regional structure and faulting, presents a regional discussion pertinent to this topic.

Subpart RR MRV Plan - O'Neal No. 4

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Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the location of the O'Neal No. 4.

Subpart RR MRV Plan - O'Neal No. 4

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13400

15400
15500
15600
15700
15800

| ) Injection Reservoir
Color Fill

ASTN

LEGFD

EDRD

PRSL

SLGO

SLGOJNJ
BASE

11700
11800
11900
12000
12100
12200
12300
12400
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12600
12700
12800
12900
13000
13100
13200
13300
13400
13500
13600
13700
13800
13900
14000
14100
14200
14300
14400

PRSL

Jpper Confining Zone
(Pearsall Formation)

SLGO

Injection Reservoir
(Sligo Formation)

SLGOJNJ
BASE

11700
11800
11900
12000
12100
12200
12300
12400
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12600
12700
12800
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TtOfilT
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TTOT

15000
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12700
12800
12900
13000
13100
13200

1M

Logged
cased
hole in
EDRD,
DPHI
Over-
estimated

CLRS

Figure 18- Northwest to southeast structural cross section: A-A' Oriented along regional dip.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 28 of 80

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422973335100
MCMORAN EXPLCO
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SPARTAN PETRO CORP
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14300
14350
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14450
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T4650
14700
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15600
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15600
15650
15700
15750
15800
15850

15700
15750
15800
15850
15900
15950
16000
1605(1

15900
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SLGO

16650
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16850

16700
16750
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16850
16900
16950
17000
17050
17100

16900
16950
17000
17050
i7inn

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15000
15050
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15350"
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KARNES

ATASCOSA

16850
16900
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17000
17050
17100
17150
17200
17250

~ Injection Reservoir
Color Fill

16000
16050
16100
16150

Logged

cased

hole in

EDRD,

DPHI

Over-

estimated

GLRS

PRSL

Upper Confining Zone
(Pearsall Formation)

SLGO

Injection Reservoir
(Sligo Formation)

SLGOJNJ
BASE

ASTN
LEGFD

BUDA

DLRO
EDRD

SLGOjr
BASE

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 29 of 80

-------
2.4 Injection and Confinement Summary

The lithologic and petrophysical characteristics of the Sligo Formation at the O'Neal No. 4 well
location indicate that the reservoir contains the necessary thickness, porosity, and permeability to
receive the proposed injection stream. The overlying Pearsall Formation is regionally extensive at
the O'Neal No. 4 with low permeability and sufficient thickness to serve as the upper confining
interval. Beneath the injection interval, the low permeability, low porosity facies tidal flat, and
lagoonal facies of the lower Sligo and underlying Hosston Formation are unsuitable for fluid
migration and serve as the lower confining interval.

2.5 Groundwater Hydrology

Bee County falls within the boundary of the Bee Groundwater Conservation District. Only one
aquifer is identified by the Texas Water Development Board's Texas Aquifers Study near the O'Neal
No. 4 well location, the unconfined to semi-confined Gulf Coast aquifer. The Gulf Coast aquifer
parallels the Gulf of Mexico and extends across the state of Texas from the Mexican border to the
border of Louisiana (Bruun et al., 2016). The extents of the Gulf Coast aquifer are provided in Figure
20 for reference.

The Gulf Coast aquifer is a major aquifer system comprised of several individual aquifers: the Jasper,
Evangeline, and Chicot. These aquifers are composed of discontinuous clay, silt, sand, and gravel
beds that range from Miocene to Holocene in age (Figure 21, page 32). Numerous interbedded
lenses and layers of silt and clay are present within the aquifers, which can confine individual aquifers
locally. The underlying Oligocene Catahoula tuff represents the lower confining interval, but it
should be noted that the formation is prone to leaking along the base of the aquifer. However, the
Burkeville confining interval provides isolation between Jasper and Evangeline aquifers which helps
protect the shallower Evangeline and Chicot Aquifers (Bruun et al., 2016).

The schematic cross section provided in Figure 22 (page 32) runs south of the O'Neal No. 4,
illustrating the structure and stratigraphy of the aquifer system. The thickness of individual
sedimentary units within the Cenozoic section tends to thicken towards the Gulf of Mexico due to
the presence of growth faults that allow additional loading of unconsolidated sediment. The total
net sand thickness of the aquifer system ranges between 700 ft of sand in the south, to over 1,300
ft in the north, with the saturated freshwater thickness averaging 1,000 ft.

The water quality of the aquifer system varies with depth and locality but water quality generally
improves towards the central to northeastern portions of the aquifer where TDS values are less than
500 milligrams per liter (mg/L). The salinity of the Gulf Coast aquifer increases to the south, where
TDS ranges between 1,000 mg/L to more than 10,000 mg/L. The Texas Water Development Board's
Texas Aquifers Study (2016) suggests that areas associated with higher salinities are possibly
associated with saltwater intrusion likely "resulting from groundwater pumping or to brine migration
in response to oil field operations and natural flows from salt domes intruding into the aquifer"
(Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 30 of 80

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According to the TDS map of the Gulf Coast aquifer (Figure 23), the TDS in northern Bee County
range between 500-3,000 mg/L near the O'Neal No, 4, categorizing the aquifer as fresh to slightly
saline.

The TRRC's Groundwater Advisory Unit (GAU) identified the Base of Useable Quality water (BUQW)
at a depth of 250 ft and the base of the USDW at a depth of 950 ft at the location of the O'Neal No.
4. Approximately 14,924 ft is therefore separating the base of the USDW and the injection interval.
(A copy of the GAU's Groundwater Protection Determination letter issued by the TRRC as part of the
Class II permitting process for the O'Neal No. 4 is provided in Exhibit A-l.) The base of the deepest
aquifer is separated from the injection interval by more than 14,924 ft of rock, including 4,200 feet
of Midway shale. Though unlikely for reasons outlined in the sections here on confinement and
potential leaks, if the migration of injected fluid did occur above the Pearsall Formation, thousands
of feet of tight sandstone, limestone, shale, and anhydrite beds occur between the injection interval
and the lowest water-bearing aquifer.

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of the
O'Neal No. 4 (modified from Bruun, B., et al., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 31 of 80

-------
System

Series

Stratigraphic Units

Hydrostratigraphy

Baker(1979)

Quaternary

Holocene

Alluvium

Chicot aquifer

Pleistocene

Beaumont Clay

Lissie
Formation

Montgomery
Formation

Bentley
Formation

Willis Sand

Tertiary

Pliocene

Goliad Sand

Evangeline aquifer

Burkeville Confining System
Jasper aquifer

Miocene
Oligocene

Fleming Formation/
Lagarto Clay

' /

Oakville Sandstone

"—- 2

-2-—_ Upper part of

tatShoulBtuffCata-hQulaM
or sandstone/ 2Anahuac
\ Formation

<"*' 2 Frio

Fomiation

Catahoula Confining System

1

Frio Clay,--"" Vicksburg Group
equivalent



Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury arid Turco, 2006)

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun et a!., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 32 of 80

-------
,nderson

Brown

Hamilton

[acogdoche

McLennan jLimestoro

Coryell

Houston

Angelina

Hardin

Travis

Montgomery

Blanco

'ashingtoi

Bastrop

Jefferson

Austin

Harris

Kendall

¦Caldwell

lambeb.

Comal

Colorado

Guadalupi

Gonzales

Wharton

Wilson

Dewitt

Jackson

Matagorda

Victoria

Goliad

McMullgfl

Duval Ji,n WelfNueceS,;:^
Kleberg jf/

Brooks

Kenedy

Willacy

Hidalgo

Cameron

120

¦ Miles

Total dissolved solids (milligrams per liter)

| 1-1,000 Fresh	1,000-3,000 Slighty saline	3,000-10,000 Moderately saline jj^^H 10,000-35,000 Very saline

^ State boundary | | County boundary I j Aquifer boundary

San Saba >amPasas

v-j

S	\ Bell	^obertsonv/viadisofvL-/ I

	 I	i	. \ / \	

/ Burnet f	Milam \ y' i Ltf&lker ^

Mason Llano / /Williamson	\ iJ^razosS	SiinJa'

- / ~\	\ . ¦. Grftnes ^—- T

^	I			J / \	Y/\Burleson V Jt 1	v

Gillespie

Bandera

Bexar

Medina

Atascosa V^arnes

LaSalle

Webb^-

Mexico

Gulf of Mexico

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 33 of 80

-------
2.6 References

Bebout, D.G., Budd, D.A., and Schatzinger, R.A. (1981). Depositional and Diagenetic History of the
Sligo and Hosston Formations (Lower Cretaceous) in South Texas: The University of Texas at
Austin, Bureau of Economic Geology, Report of Investigations No. 109.

Blondes, M.S., Gans, K.D., Engle, M.A. et al. (2018). U.S. Geological Survey National Produced Waters
Geochemical Database (Ver. 2.3, January 2018): U.S. Geological Survey data release,
https://doi.org/10.5066/F7J964W8.

Bruun, B., Anaya, R., Boghici, R. et al. (2016). Texas Aquifers Study: Chapter 6, Gulf Coast Aquifers.

Chowdhury, A.H. and Turco, M.J. (2006). Geology of the Gulf Coast Aquifer, Texas. In: Mace, R.E., et
al., Eds., Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report.

Dennen, K.O. and Hackley, P.C. (2012). Definition of Greater Gulf Basin Lower Cretaceous and Upper
Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico
basin onshore and state waters: https://pubs.usgs.gov/publication/70176229.

Galloway, W.E. (2008). Sedimentary Basins of the World, Chapter 15: Depositional Evolution of the
Gulf of Mexico Sedimentary Basin, 505-549.

Hull, D.C. (2011). Stratigraphic Architecture, Depositional Systems, and Reservoir Characteristics of
the Pearsall Shale-Gas System, Lower Cretaceous, South Texas: Thesis for M.S. of Science in
Geology, University of Texas, Austin.

Kirkland, B.L., Lighty, R.G., Rezak, R., and Tieh, T.T. (1987). Lower Cretaceous barrier reef and outer
shelf facies, Sligo Formation, south Texas, United States.

Roberts-Ashby, T.L., Brennan, S.T., Buursink, M.L. et al. (2012). Geologic framework for the national
assessment of carbon dioxide storage resources: U.S. Gulf Coast. USGS.

Swanson, S.M., Enomoto, C.B., Dennen, K.O. et al. (2017). Geologic assessment of undiscovered oil
and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate
rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain
and State Waters: U.S. Geological Survey Open-File Report 2016-1199, 69 p.,
https://doi.org/10.3133/ofr20161199.

Talbert, S.J. and Atchley, S.J. (2000). Sequence Stratigraphy of the Lower Cretaceous (Albian)
Fredericksburg Group, Central and North Texas: Department of Geology, Baylor University,
Waco, Texas 76798.

Yurewicz, D.A., Marler, T.B., Meyerholtz, K.A., and Siroky, F.X. (1993). Early Cretaceous Carbonate
Platform, North Rim of the Gulf of Mexico, Mississippi, and Louisiana.

Subpart RR MRV Plan - O'Neal No. 4

Page 34 of 80

-------
2.7 Description of the Injection Process

2.7.1 Current Operations

The Pawnee Treating Facility and the O'Neal No. 4 are existing operating assets. The O'Neal No. 4
will be recompleted for acid gas injection service under the Class II permit process. Under the Class
II application, the maximum injection rate is 28 MT/yr (1.5 MMscf/d). The TAG is 98.2% CO2, which
equates to 27.5 MT/yr of CO2 each year. The current composition of the TAG stream is displayed in
Table 3.

Table 3 - Gas Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

The facility is designed to treat, dehydrate, and compress the natural gas produced from the
surrounding acreage in Bee County. The facility uses an amine unit to remove the CO2 and other
constituents from the gas stream. The TAG stream is then dehydrated, compressed, and routed
directly to the O'Neal No. 4 for injection. The remaining gas stream is processed to separate the
natural gas liquids from the natural gas. The facility is monitored 24 hours per day, 7 days per week.

2.8 Reservoir Characterization Modeling

The modeling software used to evaluate this project was Computer Modelling Group, Ltd.'s GEM
2023.2 (GEM) simulator, one of the most comprehensive reservoir simulation software packages for
conventional, unconventional, and secondary recovery. The GEM utilizes equation-of-state (EOS)
algorithms in conjunction with some of the most advanced computational methods to evaluate
compositional, chemical, and geochemical processes and characteristics. This results in the creation
of exceedingly precise and dependable simulation models for carbon injection and storage. The
GEM model holds recognition from the EPA for its application in the delineation modeling aspect of
the area of review, as outlined in the Class VI Well Area of Review Evaluation and Corrective Action
Guidance document.

The Sligo Formation serves as the target formation for the O'Neal No. 4 (API No. 42-025-32658).
The Petra software package was utilized to construct the geological model for this target formation.
Within Petra, formation top contours were generated and subsequently brought into GEM to
outline the geological structure.

Porosity and permeability estimates were determined using the porosity log from the O'Neal No. 4.
A petrophysical analysis was then conducted to establish a correlation between porosity values and
permeability, employing the Coates equation. Both the porosity and permeability estimates from

Subpart RR MRV Plan - O'Neal No. 4

Page 35 of 80

-------
the O'Neal No. 4 were incorporated into the model, with the assumption that they exhibit lateral
homogeneity throughout the reservoir.

The reservoir is assumed to be at hydrostatic equilibrium. Given the geological formation in which
this well is located and its previous history as a gas producer, the model is assumed to be primarily
saturated with gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine
saturated, as deduced from the well log data. The modeled injection interval exhibits an average
permeability of 0.23 mD and an average porosity of 5%. All layers within the model have been
perforated. An infinite-acting reservoir has been created to simulate the boundary conditions.

The gas injectate is composed predominantly of CO2 as shown in Table 4. The modeled composition
takes into consideration the carbon dioxide and other constituents of the total stream. As the
facility has been in operation for many years, the gas composition for the proposed injection period
is expected to remain constant.

Table 4 - Modeled Injectate Composition

Component

Expected Composition
(mol %)

Modeled
Composition (mol %)

Carbon Dioxide (C02)

98.2

98.2

Hydrocarbons

1.03

Hydrocarbons

Hydrogen Sulfide

0.4

Hydrogen Sulfide

Nitrogen

0.37

Nitrogen

Core data from the literature review was used to determine residual gas saturation (Keelan and
Pugh, 1975) and relative permeability curves between carbon dioxide and the connate brine within
the Sligo carbonates (Bennion and Bachu, 2010). A maximum residual gas saturation of 35% was
assigned to the model based on core from the literature review. The Corey-Brooks method was
used to create relative permeability curves. The key inputs used to create the relative permeability
curves in the model include a Corey exponent for brine of 1.8, a Corey exponent for gas of 2.5, brine
and gas relative permeability endpoints of 0.8 and 0.5, respectively, and an irreducible brine
saturation of 20%. The relative permeability curves used for the GEM model are shown in Figure
24.

Subpart RR MRV Plan - O'Neal No. 4

Page 36 of 80

-------
1

2-Phase (C02/Brine) Relative Permeability Curves
O'Neal No. 4 Sligo Formation

-L

0.8 '

>

s 0.6

CU
(D

E

i—



'¦S 0.4

dJ

cc

























0.2

























0

C

) 0.2 0.4 0.6 0.

Gas Saturation

.8 :

L







— Krw 	Krg



Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model

The grid contains 81 blocks in the x-direction (east-west) and 81 blocks in the y-direction (north-
south), resulting in a total of 6,561 grid blocks per layer. Each grid block spans dimensions of 250 ft
x 250 ft. This configuration yields a grid size measuring 20,250 ft x 20,250 ft, equating to just under
15 square miles in area. The grid cells in the vicinity of the O'Neal No. 4, within a radius of 0.5 mi,
have been refined to dimensions of 83.333 ft x 83.333 ft in all layers. This refinement is employed
to ensure a more accurate representation of the plume and pressure effects near the wellbore.

In the model, each layer is characterized by homogeneous permeability and porosity values. These
values are derived from the porosity log of the O'Neal No. 4. The model encompasses a total of 61
layers, each featuring a thickness of approximately 3 ft per layer. As previously mentioned, the
model is perforated in each layer, with the top layer being the top of the injection interval and the
bottom layer being the lowest portion of the injection interval. The summarized property values for
each of these packages are displayed in Table 5.

Subpart RR MRV Plan - O'Neal No. 4

Page 37 of 80

-------
Table 5 - GEM Model Layer Package Properties

Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

1

15,874

3

0.004

3.75%

2

15,877

3

0.002

2.98%

3

15,880

3

0.001

1.62%

4

15,883

3

0.001

1.78%

5

15,886

3

0.002

2.32%

6

15,889

3

0.001

1.96%

7

15,892

3

0.002

3.10%

8

15,895

3

0.002

2.99%

9

15,898

3

0.003

3.52%

10

15,901

3

0.006

4.00%

11

15,904

3

0.005

3.93%

12

15,907

3

0.001

2.15%

13

15,910

3

0.001

1.99%

14

15,913

3

0.002

2.97%

15

15,916

3

0.001

2.22%

16

15,919

3

0.002

2.88%

17

15,922

3

0.001

2.38%

18

15,925

3

0.093

6.68%

19

15,928

3

0.005

2.62%

20

15,931

3

0.002

2.58%

21

15,934

3

0.003

3.07%

22

15,937

3

0.006

3.62%

23

15,940

3

0.002

2.68%

24

15,943

3

0.001

1.08%

25

15,946

3

0.002

1.87%

26

15,949

3

0.025

4.70%

27

15,952

3

0.024

4.37%

28

15,955

3

0.001

1.97%

29

15,958

3

0.003

2.27%

30

15,961

3

0.007

3.09%

31

15,964

3

0.110

6.75%

32

15,967

3

0.037

5.62%

33

15,970

3

0.011

4.41%

34

15,973

3

0.022

4.59%

35

15,976

3

0.297

7.88%

36

15,979

3

0.440

9.21%

37

15,982

3

0.060

5.90%

38

15,985

3

0.001

2.22%

39

15,988

3

0.001

2.21%

Subpart RR MRV Plan - O'Neal No. 4

Page 38 of 80

-------
Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

40

15,991

3

0.001

1.12%

41

15,994

3

0.003

2.05%

42

15,997

3

0.014

4.56%

43

16,000

3

0.007

4.15%

44

16,003

3

0.033

5.95%

45

16,006

3

1.233

10.25%

46

16,009

3

1.476

12.04%

47

16,012

3

0.566

10.08%

48

16,015

3

1.679

12.18%

49

16,018

3

2.194

13.08%

50

16,021

3

1.235

12.02%

51

16,024

3

0.788

11.22%

52

16,027

3

0.944

10.48%

53

16,030

3

0.424

9.05%

54

16,033

3

0.378

8.85%

55

16,036

3

0.378

8.81%

56

16,039

3

0.378

8.84%

57

16,042

3

0.736

9.91%

58

16,045

3

0.232

7.94%

59

16,048

3

0.238

7.97%

60

16,051

3

0.012

3.01%

61

16,054

3

0.038

4.30%

2.8.1 Simulation Modeling

The primary objectives of the model simulation were as follows:

1.	Estimate the maximum areal extent and density drift of the injectate plume after injection.

2.	Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone.

3.	Assess the likelihood of the injectate plume migrating into potential leak pathways.

The reservoir is assumed to have an irreducible brine saturation of 20%. The salinity of the brine
within the formation is estimated to be 150,000 ppm (USGS National Produced Waters Geochemical
Database, Ver. 2.3), typical for the region and formation. The injectate stream is primarily composed
of CO2 and H2S as stated previously. Core data from the literature was used to help generate relative
permeability curves. From the literature review, also as previously discussed, cores that most
closely represent the carbonate rock formation of the Sligo seen in this region were identified, and
the Corey-Brooks equations were used to develop the curves (Bennion and Bachu, 2010). A low,
conservative residual gas saturation based on the cores from the literature review was then used to
estimate the size of the plume (Keelan and Pugh, 1975).

Subpart RR MRV Plan - O'Neal No. 4

Page 39 of 80

-------
The model is initialized with a reference pressure of 10,995 psig at a subsea depth of 15,740 ft. This,
when a Kelly Bushing "KB" elevation of 334 ft is considered, correlates to a gradient of 0.684 psi/ft.
This pressure gradient was determined from production data of the O'Neal No. 4. An initial reservoir
pressure of 0.76 psi/ft was calculated before initial production. However, in 1997, after producing
approximately 0.5 billion cubic feet (Bcf) of gas, the well was shut in. The last bottomhole pressure
reading was calculated to be 0.480 psi/ft. This assumes the reservoir repressurizes after production
ceases, but not fully back to in situ conditions. Therefore, a 10% safety factor was given to the initial
reservoir pressure gradient of 0.76 psi/ft, and a gradient of 0.684 psi/ft was implemented into the
model as a conservative estimate. A skin factor of -2 was applied to the well to simulate the
stimulation of the O'Neal No. 4 for gas production from the Sligo Formation, which is based on the
acid fracture report, provided in Appendix A-3.

The fracture gradient of the injection zone was estimated to be 0.954 psi/ft, which was determined
from the acid fracture report. A 10% safety factor was then applied to this number, putting the
maximum bottomhole pressure allowed in the model at 0.86 psi/ft, which is equivalent to 13,652
psig at the top of the Sligo injection interval.

The model, which begins in January 2025, runs for a total of 22 years, comprising 12 years of active
injection, and is then succeeded by 10 years of density drift. Throughout the entire 12-year injection
period, an injection rate of 1.5 MMscf/D is used to model the maximum available rate, yielding the
largest estimate of the plume size. After the 12-year injection period, when the O'Neal No. 4 ceases
injection, the density drift of the plume continues until the plume stabilizes 10 years later. The
maximum plume extent during the 12-year injection period is shown in Figure 25. The final extent
after 10 years of density drift after injection ceases is shown in Figure 26 (page 42).

Subpart RR MRV Plan - O'Neal No. 4

Page 40 of 80

-------
C02 Saturation at End of Injection

	i	i

283750 -

282500

281250

280000 -

N

0.80-—j

0.70

-0.60

-0.50

-0.40

-0.30

-0.20

I0'10

O.oJ

278750 —	Actual Scale: 1:0

Y/X: 1:1
Axis Units: ft
Total Blocks: 459,269
Active Blocks: 459,269

I	I	I	I	I	I

2316000	2318000	2320000	2322000	2324000	2326000

Figure 25 - Areal View of Saturation Piume at Shut-in (End of injection)

Subpart RR MRV Plan - O'Neal No. 4

Page 41 of 80

-------
283750 -

282500

281250

280000 -

278750

CO? Saturation at End of Simulation

.	i 	i

o I

0.70

-0.60

-0.50

-0.40

-0.30

-0.20

|

0.03J

Actual Scale: 1:0
Y/X: 1:1
Axis Units: ft
Total Blocks: 459.269
Active Blocks: 459.269

I

2324000

2316000

2318000

2320000

2322000

2326000

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal No. 4

Page 42 of 80

-------
The cross-sectional view of the O'Neal No. 4 shows the extent of the plume from a side-view angle,
cutting through the formation at the wellbore. Figure 27 shows the maximum plume extent during
the 12-year injection period. During this time, gas from the injection well is injected into the
permeable layers of the formation and predominantly travels laterally. Figure 28 (page 45) shows
the final extent of the plume after 10 years of migration. Then, the effects of residual gas saturation
and migration due to density drift are clearly shown. At least 35% of injected gas that travels into
each grid cell is trapped, as the gas travels mostly vertically—as it is less dense than the formation
brine—until an impermeable layer is reached. Both figures are shown in an east-to-west view.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 43 of 80

-------
C02 Saturation at End of Injection

15500 -

15563 -

15625 -

15688 -

15750 -

15813 -



0.70

0.60

0.50

0.40

0.30

-0.20

|

0.03-1

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Loc^cal See: 2 of 3
Total Blocks: 459.269
Active Bocks: 459.269

2319000

r

2321000

West

r

2323000

East

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 44 of 80

-------
C02 Saturation at End of Simulation

15500

15563

15625

15688

15750

15813

0.80-

1

0.70

0.60

0.50

0.40

-0.30

1-0.20

J 0.10

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical Sfcce: 2 of 3
Total Bocks: 459.269
Active Bocks: 459.269

2319000

2321000

West

2323000

East

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 45 of 80

-------
Figure 29 shows the surface injection rate, bottom hole pressures, and surface pressures over the
injection period—and the period of density drift after injection ceases. The bottomhole pressure
increases the most as the injection rate ends, reaching a maximum pressure of 13,337 psig, at the
end of injection. This buildup of 2,362 psig keeps the bottomhole pressure below the fracture
pressure of 13,652 psig. The maximum surface pressure associated with the maximum bottomhole
pressure reached is 6,095 psig, well below the maximum allowable 7,937 psig per the TRRC UIC
permit application for this well. Bottomhole and wellhead pressures are provided in Table 6.

2,000,000









16,000
14,000
12,000

10,000 J

v>
v>

8,000 §
5,000 (jq"
4,000
2,000









J., /







,





_ 1,500,000
-a
>

jn 1,250,000
0)

4-»

£ 1,000,000

£
o

y 750,000

'E

— 500,000
250,000
0

C

f











v	











	















































5 10 15 20

Time (years)



Gas Rate (scf/d) BHP (psig) WHP(psig) — — — BHP Constraint (psig) ——

— WHP Constraint (psig)



Figure 29-Well Injection Rate and Bottomhole and Surface Pressures Over Time

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 46 of 80

-------
Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection

Time from Start of Injection
(years)

BHP (psig)

WHP (psig)

0

10,975

-

10

13,311

6,073

12 (End of Inj.)

13,337

6,095

20

11,029

-

22 (End of Model)

11,013

-

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 47 of 80

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SECTION 3 - DELINEATION OF MONITORING AREA

This section discusses the delineation of both the maximum monitoring area (MMA) and active
monitoring area (AMA) as described in 40 CFR §98.448(a)(1).

3.1 Maximum Monitoring Area

The MMA is defined as equal to or greater than the area expected to contain the free-phase CO2
plume until the plume has stabilized, plus an all-around buffer zone of at least one half mile.
Numerical simulation was used to predict the size and drift of the plume. With CMG's GEM software
package, reservoir modeling was used to determine the areal extent and density drift of the plume.
The model considers the following:

•	Offset well logs to estimate geologic properties

•	Petrophysical analysis to calculate the heterogeneity of the rock

•	Geological interpretations to determine faulting and geologic structure

•	Offset injection history to predict the density drift of the plume adequately

Ozona's expected gas composition was used in the model. The injectate is estimated at a molar
composition of 98.2% CO2 and 1.8% of other constituents. The StarTex Pawnee Treating Facility has
been in stable operations for many years. Ozona believes the gas analysis provided in Table 1 is an
accurate representation of the injectate. In the future, if the actual gas analysis varies materially
from the injectate composition herein, an update to this MRV plan will be submitted to the GHGRP.
As discussed in Section 2, the gas will be injected into the Sligo Formation. The geomodel was
created based on the rock properties of the Sligo.

The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of
3% gas saturation was used to determine the boundary of the plume. When injection ceases in Year
12, the area expanse of the plume will be approximately 270 acres. The maximum distance between
the wellbore and the edge of the plume is approximately 0.42 mi to the west. After 10 additional
years of density drift, the areal extent of the plume is 303 acres with a maximum distance to the
edge of the plume of approximately 0.45 mi to the west. Since the plume shape is relatively circular,
the maximum distance from the injection well after density drift was used to define the circular
boundary of the MMA. The AMA and the MMA have similar areas of influence, with the AMA being
only marginally smaller than the MMA. Therefore, Ozona will set the AMA equal to the MMA as the
basis for the area extent of the monitoring program.

This is shown in Figure 30 with the plume boundary at the end of injection, the stabilized plume
boundary, and the MMA. The MMA boundary represents the stabilized plume boundary after 10
years of density drift plus an all-around buffer zone of one half mile.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 48 of 80

-------
l>'N»4l Unit *4
lUiimum Woiiiloiim) Aim

0/o«w CCS UC
•»* county, ix

t» Minify 'O. | Of.* I .V ¦''),'» | *p
-------
3.2 Active Monitoring Area

The AMA was initially set equal to the expected total injection period of 12-years. The AMA was
analyzed by superimposing the area based on a one-half mile buffer around the anticipated plume
location after 12 years of injection (2037), with the area of the projected free-phase CO2 plume at
five additional years (2042). In this case, as shown in Figure 31, the plume boundary in 2042 is within
the plume in 2037 plus the one-half mile buffer. Since the AMA boundary is only slightly smaller
than the MMA boundary, Ozona will define the AMA to be equal to the MMA. By 2037, Ozona will
submit a revised MRV plan to provide an updated AMA and MMA.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 50 of 80

-------
Figure 31 - Active Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 51 of 80

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SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE

This section identifies and discusses the potential pathways within the MMA for CO2 to reach the
surface and is summarized in Table 7. Also included are the likelihood, magnitude, and timing of
such potential leakage. The potential leakage pathways are:

•	Surface equipment

•	Existing wells within the MMA

•	Faults and fractures

•	Upper confining layer

•	Natural or induced seismicity

Table 7 - Potential Leakage Pathway Risk Assessment

Potential Leakage
Pathway

Likelihood



Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low

Low. Automated systems
will detect leaks and
execute shut-down
procedures.

During active
injection period.
Thereafter the well
will be plugged.

Existing wells within
the MMA

Unlikely. One artificial
penetration was drilled into
the injection interval. This
well has been properly
plugged and abandoned.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Faults and fractures

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Upper confining zone

Unlikely. The lateral
continuity of the UCZ
consisting primarily of the
Pearsall Formation which is
over 500 ft thick is
recognized as a very
competent seal.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Natural or induced
seismicity

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

1 - UCZ is defined as the upper confining zone.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 52 of 80

-------
Magnitude Assessment Description

Low - catergorized as little to no impact to safety, health and the environment and the costs to mitigate

are minimal.	

Medium - potential risks to the USDW and for surface releases does exist, but circumstances can be

	easily remediated.	

High - dangerto the USDW and significant surface release may exist, and if occurs this would require
	significant costs to remediate.	

4.1 Leakage from Surface Equipment

The Pawnee Treating Facility and O'Neal No. 4 are designed for separating, transporting, and
injecting TAG, primarily consisting of CO2, in a manner to ensure safety to the public, the employees,
and the environment. The mechanical aspects of this are noted in Table 8 and Figure 32. The
facilities have been designed to minimize leakage and failure points, following applicable National
Association of Corrosion Engineers (NACE) and American Petroleum Institute (API) applicable
standards and practices. As the TAG stream contains H2S, monitors installed for H2S detection will
also indicate the presence of CO2. These monitors will be installed at key locations around the
facility and the O'Neal No. 4 location. These devices will be continuously monitored by the
Supervisory Control and Data Acquisition (SCADA) system and will alarm at set points determined
by the facility's Health, Safety and Environment (HS&E) Director, consistent with Occupational
Safety and Health Administration (OSHA) requirements. The facility will set the detection and alarm
states for personnel at 10 ppm and at 40 ppm for initiating Emergency Shutdown. Key monitoring
points and parameters are also provided in Table 8.

The facilities will incorporate important safety equipment to ensure reliable and safe operations. In
addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-pressure
shutoff settings to isolate the facility, the O'Neal No. 4, and other components, StarTex has a flare
stackto safely handle the TAG when a depressuring event occurs. These facilities will be constructed
in the coming months. The exact location of this equipment is not yet known, but it will be installed
in accordance with applicable engineering and safety standards.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 53 of 80

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Table 8 - Summary of TAG Monitors and Equipment

Device

Location

Set Point

H2S Monitors (1-4)

O'Neal No. 4 wellsite

10 ppm High Alarm
40 ppm Emergency Shutdown

H2S Monitors (5-8)

In-Plant Monitors

10 ppm High Alarm
40 ppm Emergency Shutdown

Flare Stack

Plant Site Perimeter

N/A

AGI Flowmeter

In-Plant (downstream of
the Amine Unit)

Calibrated per API specifications

Emergency Shutdown

In-Plant Monitors

40 ppm Facility Shutdown

Emergency Shutdown

O'Neal No. 4 wellsite

40 ppm Facility Shutdown

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 54 of 80

-------
With the continuous air monitoring at the facility and the well site, a release of CO2 would be quickly
identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The CO2 injected into the O'Neal No. 4 is from the amine
unit at the Pawnee Treating Facility. If any leakage were to be detected, the volume of CO2 released
would be quantified based on the operating conditions at the time of release, as stated in Section 7,
in accordance with 40 CFR §98.448(a)(5). Ozona concludes that the leakage of CO2 through the
surface equipment is unlikely.

4.2 Leakage Through Existing Wells Within the MMA

The O'Neal No. 4 is engineered to prevent migration from the injection interval to the surface
through a special casing and cementing design as depicted in the schematic provided in Figure 32.
Mechanical integrity tests (MITs), required under Statewide Rule (SWR) §3.46 [40 CFR §146.23
(b)(3)], will take place every 5 years to verify that the well and wellhead can contain the appropriate
operating pressures. If the MIT were to indicate a leak, the well would be isolated and the leak
mitigated to prevent leakage of the injectate to the atmosphere.

A map of all oil and gas wells within the MMA is shown in Figure 33. Figure 34 is a map of all the oil
and gas wells that penetrate the MMA's gross injection zone. Only one well penetrated the MMA's
gross injection zone. This well was non-productive and has been plugged and abandoned in
accordance with TRRC requirements. A summary table of all oil and gas wells within the MMA is
provided in Appendix B-l.

This table in Appendix B-l provides the total depth (TD) of all wells within the MMA. The wells that
are shallower and do not penetrate the injection zone are separated by the Pearsall Formation with
a gross thickness of 535 ft. The Pine Island Shale comprises approximately 130 ft of this interval as
discussed in Section 2.2.2 and provides a competent regional seal—making vertical migration of
fluids above the injection zone unlikely.

The shallower offset hydrocarbon wells within the MMA will also serve as above zone monitoring
wells. Should any of the sequestered volumes migrate vertically, they would potentially enter the
shallower hydrocarbon reservoir. Regular sampling and analysis is performed on the produced
hydrocarbons. If a material difference in the quantity of CO2 in the sample occurs indicating a
potential migration of injectate from the Sligo Formation, Ozona would investigate and develop a
mitigation plan. This may include reducing the injection rate or shutting in the well. Based on the
investigation, the appropriate equation in Section 7 would be used to make any adjustments to the
reported volumes.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 55 of 80

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'P.

0

C2J—

(4>

(5>5

L I

SSSV

CasingiTubing Information

Label



2

a

4

E

Type

Coa&mIH



Hamml

PtadusBun LlMt

Tufcinfl

OD

-

1Q-3W

7-5.-S"

5" (new)

5" i.oidi

2-3'8"

D

-

9.760"

5.625"

•A-276"

4.276"

1.867"

Drift ID

-

9.504"

6.500*

¦4.151"

4-151"

1.773"

COD

-

11.750"

B.500"

5.553"

5-553"

3.063"

Weight

-

555 tv-t

39.0 lth"t

18.0 Itrft

18-0 bit

5 .8 bit

Grade

-

3-95

CY-95

F-110

Q-125

L-90

Hole
Size

MIA

14-3/4*

9-1."2*

HJA

6-1 or

M'A

Depth
S#1

Driven to
Refusa

3,510'

15.340"

Top: 0*
Bottom: 14,030

Top: 14,089'
Bottom 16,101"

15,720'

Cement

M'A

Lead: 1,125 sks

HLC
Tal: 350 s*5 H

Lead: 575 sfcs
50:50 Paz H
Tail: 400 5*5 H

Lead: 650 sits
50:50 PozsH
Tall; 110 sfcs CO2
Res. Sfrurry

200 «s Premium

WA

TOC

HM

Surface

7359'

Surface

3urface

MM

%
EXC-frtG







Lead: 10%
Tail: 0%

-

M'A

\

Top of Intermec ate I-errer: g 7.2-E9



P>ftjrd Cement arB^Jx-atert

Top of Corrosion Resistant Cemenfc 13,300"
Edwards Perforations g- 13-,525' - 13-8*11 squeezed!

W- -
W^7-

CO.;-Resatar; Permanent Packer 15,700'

Do«nho»-e Check. Vafve

Re-Perforate Initial Production Zone >gj 15.S7-A' - 16,Q£.5"
Injection Interval @ 15,874' - S 6,056'

(4>

TD@tS.1Dr

0]

LONQUIST

SEQUESTRATION L

Ozona CCS

Country: USA

API No: 42-025-32658

C02 Injection Well
Proposed Well Design - O'Neal Gas Unit No. 4

State/Province: Texas

Field: TBD

County/Parish: Bee County

Well Type/Status: Proposes

Texas License F-5652

Location: 28.0031807, -35.0017001

Project No: LSI 90

Date: 10/13/2023

12912 mi Courtrj Evd Ste -2110
Austto, Texas 73738
Tfel: 512.732.9812
=ar 512.732.9S16

Drawn: Joseph LovreweB

Reviewed: David Lytle

Approved: David Lytle

Rev No: Q

Notes:

Figure 32 - O'Neal No. 4 Wellbore Schematic

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 56 of 80

-------
* +

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Seobtodbort)

UCL-Penetrating AOR Well SHU (API:
42-025-..)

Gm« PftA(l)

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 58 of 80

-------
4.2.1 Future Drilling

Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations have proven to date to be nonproductive in this area, and therefore Ozona does not see
this as a risk. This is supported by a review of the TRRC Rule 13 (Casing, Cementing, Drilling, Well
Control, and Completion Requirements), 16TAC §3.13. The Sligo is not among the formations listed
for which operators in Bee County and District 2 (where the O'Neal No. 4 is located) are required to
comply with TRCC Rule 13; therefore, the TRRC does not believe there are productive horizons
below the Sligo. The O'Neal No. 4 drilling permit is provided in Appendix A-2.

4.2.2 Groundwater Wells

The results of a groundwater well search found five wells within the MMA, as identified by the Texas
Water Development Board as shown in Figure 35 and in tabular form in Appendix B-2.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 59 of 80

-------
1:12,500

SN

s

7832309

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from Plume Ertert s> End of Injection)

Maximum MonAonng Aru (|/2-Hle
. I BiifSfr from Plume E*teot 9
SuMuation)

nvDB GrtxifkbtiM Wells

Figure 35 - Groundwater Wells Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 60 of 80

-------
The surface, intermediate, and production casings of the O'Neal No. 4, as shown in Figure 32, are
designed to protect the shallow freshwater aquifers, consistent with applicable TRRC regulations,
and the GAU letter issued for this location is provided in Appendix A-l. The wellbore casings and
compatible cements prevent CO2 leakage to the surface along the borehole. Ozona concludes that
leakage of the sequestered CO2 to the groundwater wells is unlikely.

4.3	Leakage Through Faults and Fractures

Detailed mapping of openhole logs surrounding the O'Neal No. 4 did not identify any faulting within
either the Pearsall orSligo sections. However, there is a general lack of deep penetrators within the
area that limits the amount of openhole coverage available.

The majority of the published literature suggests that faulting near the project area is restricted to
the shallower, overlying Cenozoic section, as shown in Figure 9, with shallow faults dying out before
reaching the Pearsall Formation. One source interpreted the potential for faulting to the south
(Swanson et al., 2016). The potential fault is depicted in Figure 8 relative to the location of the
O'Neal No. 4. According to the map, the interpreted fault lies approximately 4.25 mi south-
southeast of the well and approximately 3.9 mi south-southeast of the stabilized plume extent in
the year 2047. In the unlikely scenario in which the injection plume or pressure front reaches the
potential fault, and the potential fault was to act as a transmissive pathway, the upper confining
Pearsall shale contains sufficient thickness and petrophysical properties required to confine and
protect injectates from leaking outside of the permitted injection zone.

Section 2.1.2 discusses regional structure and faulting, and Section 2.3 covers local structure, for
additional material relevant to this topic.

4.4	Leakage Through the Upper Confining Zone

The Sligo injection zone has competent sealing intervals present above and below the targeted
carbonate sequence of the Sligo section. The overlying Pine Island shale member of the Pearsall
Formation is approximately 130 ft thick at the O'Neal No. 4. Above this confining unit, the Cow
Creek Limestone, Cow Creek shale, and Bexar Shale Members of the Pearsall Formation will act as
additional confinement between the injection interval and the USDW. The USDW lies well above
the sealing properties of the formations outlined above, making stratigraphic migration of fluids into
the USDW highly unlikely. The petrophysical properties of the lower Sligo and Hosston Formations
make these ideal for lower confinement. The low porosity and permeability of these underlying
formations minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injectate to the in situ reservoir fluid makes migration below the lower confining layer
unlikely.

4.5	Leakage from Natural or Induced Seismicitv

The O'Neal No. 4 is located in an area of the Gulf of Mexico considered to be active from a seismic
perspective. Therefore, the Bureau of Economic Geology's TexNet (from 2017 to present) and
USGS's Advanced National Seismic System (from 1971 to present) databases were reviewed to

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 61 of 80

-------
identify any recorded seismic events within 25 kilometer (km) of the O'Neal No. 4.

The investigation identified a multitude of seismic events within the 25 km search radius; however,
the magnitude of most of the events was below 2.5. The nearest seismic event with a recorded
magnitude of 3.0 or greater was measured approximately 5.6 km northwest of the O'Neal No. 4 at
a depth of 5 km. The results of the investigation are plotted on the map provided in Figure 36
relative to the O'Neal No. 4 and the 25-km search radius.

The Facility will have operating procedures and set points programmed into the control and SCADA
systems to ensure operating pressures are maintained below the fracture gradient of the injection
and confining intervals, thus avoiding the potential for inducing seismicity.

Given the seismic activity in the area, Ozona will closely monitor nearby TexNet station EF71 for
activity and any corresponding irregularities in the operating pressures of O'Neal No. 4. If a seismic
event of 3.0 or greater is recorded at Station EF71 or if anomalies are identified in the operating
data, Ozona will review the data and determine if any changes occurred that indicate potential
leakage. Ozona would take appropriate measures based on their findings, including limiting the
injection pressure and reducing the injection rate.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 62 of 80

-------
2T.EF69

V

'I'

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o

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Figure 36 - 25-km Seismicity Review

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 63 of 80

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SECTION 5 - MONITORING FOR LEAKAGE

This section discusses the strategy that Ozona will employ for detecting and quantifying surface
leakage of CO2 through the pathways identified in Section 4, to meet the requirements of 40 CFR
§98.448(a)(3). As the injectate stream contains both H2S and CO2, the H2S will be a proxy for CO2
leakage and therefore the monitoring systems in place to detect H2S will also indicate a release of
CO2. Table 9 summarizes the monitoring of the following potential leakage pathways to the surface.
Monitoring will occur during the planned 12-year injection period or cessation of injection
operations, plus a proposed 10-year post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults or fractures

•	Leakage through confining seals

•	Leakage through natural or induced seismicity

Table 9 - Summary of Leakage Monitoring Methods

Leakage Pathway

Monitoring Method

Surface equipment

Fixed H2S monitors at the Plant and well site

Visual inspections

Monitor SCADA systems for the Plant and well site

Existing wells within the MMA

Monitor C02 levels in above zone producing wells

Mechanical Integrity Tests (MIT) of the AGI Well every 5 years

Visual inspections

Annual soil gas sampling near well locations that penetrate the
Upper Confining Zone within the AMA

• Leakage through
groundwater wells

Annual groundwater samples from existing water well(s)

• Leakage from future wells

Monitor drilling activity and compliance with TRRC Rule 13
Regulations

Faults and Fractures

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Upper confining zone

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Natural or induced seismicity

Monitor C02 levels in Above Zone producing wells

Monitor existing TexNet station



Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 64 of 80

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5.1 Leakage from Surface Equipment

The facility depicted in Figure 37 and the O'Neal No. 4 were designed to operate in a safe manner
to minimize the risk of an escape of CO2 and H2S. Leakage from surface equipment is unlikely and
would quickly be detected and addressed. The facility design minimizes leak points through the
equipment used, and key areas are constructed with materials that are NACE and API compliant. A
baseline atmospheric CO2 concentration will be established prior to commencing operation once
facility construction has been completed. Ambient H2S monitors will be located at the facility and
near the O'Neal No. 4 site for local alarm and are connected to the SCADA system for continuous
monitoring.

The facility and the O'Neal No. 4 are continuously monitored through automated control systems.
These monitoring points were discussed in Section 4.1. In addition, field personnel conduct routine
visual field inspections of gauges, and gas monitoring equipment. The effectiveness of the internal
and external corrosion control program is monitored through the periodic inspection of the
corrosion coupons and inspection of the cathodic protection system. These inspections and the
automated systems allow Ozona to detect and respond to any leakage situation quickly. The surface
equipment will be monitored for the injection and post-injection period. Should leakage be
detected during active injection operations, the volume of CO2 released will be calculated based on
operating conditions at the time of the event, per 40 CFR §98.448(a)(5) and §98.444(d).

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 65 of 80

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Residue Gas

L 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 J

Figure 37 - O'Neal No. 4 Process Flow Diagram

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 66 of 80

-------
Pressures, temperatures, and flow rates through the surface equipment are continuously monitored
during operations. If a release occurred from surface equipment, the amount of CO2 released would
be quantified based on the operating conditions, including pressure, flow rate, percentage of CO2 in
the injectate, size of the leak-point opening, and duration of the leak. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7.

5.2 Leakage Through Existing and Future Wells Within the MMA

Ozona continuously monitors and collects injection volumes, pressures, and temperatures through
their SCADA systems, for the O'Neal No. 4. This data is reviewed by qualified personnel and will
follow response and reporting procedures when data exceeds acceptable performance limits. A
change of injection or annular pressure would indicate the presence of a possible leak and be
thoroughly investigated. In addition, MITs performed every 5 years, as expected by the TRRC and
UIC, would also indicate the presence of a leak. Upon a negative MIT, the well would be isolated
and investigated to develop a leak mitigation plan.

As discussed previously, TRRC Rule 13 ensures that new wells in the field are constructed with
proper materials and practices to prevent migration from the injection interval.

In addition to the fixed monitors described previously, Ozona will also establish and operate an in-
field monitoring program to detect CO2 leakage within the AMA. This would include H2S monitoring
as a proxy for CO2 at the well site and annual soil gas samples taken near any identified wells that
penetrate the injection interval within the AMA. These samples will be analyzed by a qualified third
party. Prior to commencing operation, and through the post-injection monitoring period, Ozona
will have these monitoring systems in place.

Currently, there is only one well in the MMA identified that penetrates the injection interval. This
well was plugged and abandoned in 2007. The TRRC records are provided in Appendix A-4. Ozona
will take an annual soil gas sample from this area, which will be analyzed by a third-party lab.
Additional monitoring will be added as the AMA is updated over time. In the unlikely event a leak
occurs, Ozona will quantify the leak volumes by the methodologies discussed in Section 7 and
present these results and related activities in the annual report.

Ozona will also utilize shallower producing gas wells as proxies for above-zone monitoring wells.
Production data from these wells is analyzed for monthly production statements, and therefore
would be an early indicator of any possible subsurface issues. Should any material change from
historical trends in the CO2 concentration occur, Ozona would investigate and develop a corrective
action plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is
very low, as the producing reservoir provides an ideal containment given the upper confining zone
of this reservoir has proven competent. In the unlikely event a leak occurs, Ozona would quantify
the leak per the strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443
based on the actual circumstances and include these results in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 67 of 80

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5.2.1 Groundwater Quality Monitoring

Ozona will monitor the groundwater quality above the confining interval by sampling from
groundwater wells near the O'Neal No. 4 and analyzing the samples with a third-party laboratory
on an annual basis. In the case of the O'Neal No. 4, 5 existing groundwater wells have been
identified within the AMA (Figure 38). Initial groundwater quality tests will be performed to
establish a baseline prior to commencing operations.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 68 of 80

-------
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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 69 of 80

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5.3 Leakage Through Faults, Fractures, or Confining Seals

Ozona will continuously monitorthe operations of the O'Neal No. 4 through the automated controls
and SCADA systems. Any deviation from normal operating volume and corresponding injection
pressure could indicate movement into a potential leak pathway, such as a fault or breakthrough of
the confining seal and would trigger an alert due to a change in the injection pressure. Any such
alert would be reviewed by field personnel and appropriate action would be taken, including
shutting in the well, if necessary.

Ozona will also utilize shallower producing wells as proxies for above-zone monitoring wells.
Production data is analyzed regularly for monthly production statements and therefore would be
an early indicator of any possible subsurface issues. Should any material change from historical
trends in the CO2 concentration occur, Ozona would investigate and develop a corrective action
plan. Should any CO2 migrate vertically from the Sligo Formation, the magnitude risk of this event
is very low, as the producing reservoir provides an ideal containment given the upper confining zone
has proven competent. In the unlikely event a leak occurs, Ozona would quantify the leak per the
strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443 based on the
actual circumstances.

5.4 Leakage Through Natural or Induced Seismicitv

While the likelihood of a natural or induced seismicity event is low, Ozona plans to use the nearest
TexNet seismic monitoring station, EF71, to monitor the area around the O'Neal No. 4. This station
is approximately 3 mi to the northwest, as shown in Figure 38. This is sufficient distance to allow
for accurate and detailed monitoring of the seismic activity in the area. Ozona will monitor this
station for any seismic activity, and if a seismic event of 3.0 magnitude or greater is detected, Ozona
will review the injection volumes and pressures of the O'Neal No. 4 to determine if any significant
changes have occurred that would indicate potential leakage.

Ozona will also continuously monitor operations through the SCADA system. Any deviation from
normal operating pressure and volume set points would trigger an alarm for investigation by
operations staff. Such a variance could indicate movement into a potential leak pathway, such as a
fault or breakthrough of the confining seal. Any such alert would be reviewed by field personnel
and appropriate action would be taken, including shutting in the well, if necessary

These are the two primary strategies for mitigating risks for induced seismicity. In the unlikely event
a leak occurs, Ozona will quantify the leak per the strategies discussed in Section 7, or as may be
applicable provided in 40 CFR §98.443 based on the actual circumstances.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 70 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 71 of 80

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SECTION 6 - BASELINE DETERMINATIONS

This section identifies the strategies Ozona will undertake to establish the expected baselines for
monitoring CO2 surface leakage per 40 CFR §98.448(a)(4). Ozona will use the existing SCADA
monitoring systems to identify changes from the expected performance that may indicate leakage
of injectate and calculate a corresponding amount of CO2.

6.1	Visual Inspections

Regular inspections will be conducted by field personnel at the facility and O'Neal No. 4 site. These
inspections will aid in identifying and addressing possible issues to minimize the risk of leakage. If
any issues are identified, such as vapor clouds or ice formations, corrective actions will be taken
prudently and safely to address such issues.

6.2	H2S/ CO2 Monitoring

In addition to the fixed monitors in the facility and at the wellsite, Ozona will establish and perform
an annual in-field sampling program to monitor and detect any CO2 leakage within the AMA. This
will consist of soil gas sampling near any artificial penetrations of the injection zone and sampling of
water wells. These probes have special membrane inserts that collect the gas samples over a 21-
day period. These will be analyzed by a third-party lab to be analyzed for CO2, H2S, and trace
contaminants typically found in a hydrocarbon gas stream. The lab results will be provided in the
annual report should they indicate a material variance from the baseline. Initial samples will be
taken and analyzed before the commencement of operations and will establish the baseline
reference levels.

6.3	Operational Data

Upon starting injection operations, baseline measurements of injection volumes and pressures will
be recorded. Any significant deviations over time will be analyzed for indication of leakage of
injectate and the corresponding component of CO2.

6.4	Continuous Monitoring

The total mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly,
as the injection stream for this project is near the OSHA Permissible Exposure Limit (PEL) 8-hour
Time Weighted Average (TWA) of 5,000 ppm. Direct leak surveys present a hazard to personnel due
to the presence of H2S in the gas stream. Continuous monitoring systems will trigger alarms if there
is a release. The mass of the CO2 released would be calculated based on the operating conditions,
including pressure, flow rate, percentage of CO2, size of the leak-point opening, and duration. This
method is consistent with 40 CFR §98.448(a)(5) and §98.444(d), allowing the operator to calculate
site-specific variables used in the mass balance equation.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 72 of 80

-------
In the case of a depressuring event, the acid gas stream will be sent to a flare stack to be safely
processed and will be reported under reporting requirements for the facility. Any such events will
be accounted for in the sequestered reporting volumes consistent with Section 7.

6.5 Groundwater Monitoring

Initial samples will be taken from groundwater wells in the area of the O'Neal No. 4 upon approval
of the MRV plan, and before commencement of CO2 injection. These samples will be analyzed and
reports prepared by a third-party laboratory testing for pH, total dissolved solids (TDS), CO2, and
volatile organic compounds (VOC). Initial samples will be taken and analyzed before the
commencement of operations and will establish the baseline reference levels. Sampling select wells
will be performed annually. In the event a material deviation in the sample analysis occurs, the
results will be provided in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 73 of 80

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SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS

BALANCE EQUATION

This section identifies how Ozona will calculate the mass of CO2 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the CO2 emissions from equipment leaks and
vented emissions of CO2 between the injection flow meter and the injection well, per 40 CFR
§98.448(a)(5).

7.1	Mass of CO2 Received

Per 40 CFR §98.443, the mass of CO2 received must be calculated using the specified CO2 received
equations "unless you follow the procedures in 40 CFR §98.444(a)(4)." The 40 CFR §98.444(a)(4)
states that "if the CO2 you receive is wholly injected and is not mixed with any other supply of CO2,
you may report the annual mass of CO2 injected that you determined following the requirements
under paragraph (b) of this section as the total annual mass of CO2 received instead of using
Equation RR-1 or RR-2 of this subpart to calculate CO2 received." The CO2 received for this injection
well is injected and not mixed with any other supply; the annual mass of CO2 injected will equal the
amount received less any amounts calculated in accordance with the equations of this section. Any
future streams would be metered separately before being combined into the calculated stream.

7.2	Mass of CO2 Injected

Per 40 CFR §98.444(b), since the flow rate of CO2 injected will be measured with a volumetric flow
meter, the total annual mass of CO2, in metric tons, will be calculated by multiplying the mass flow
by the CO2 concentration in the flow according to Equation RR-5:

C02,u = Annual CO2 mass injected (metric tons) as measured by flow meter u

Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard
conditions (standard cubic meters per quarter)

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682

Cco2,p,u = CO2 concentration measurement in flow for flow meter u in quarter p (vol. percent
CO2, expressed as a decimal fraction)

p = Quarter of the year

u = Flow meter

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 74 of 80

4

p= 1

Where:

-------
7.3 Mass of CO2 Produced

The O'Neal No. 4 is not part of an enhanced oil recovery project; therefore, no CO2 will be produced.
7.4 Mass of CO2 Emitted by Surface Leakage

The mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly due
to the H2S concentration in the injection stream. Direct leak surveys are dangerous and present a
hazard to personnel. Because no venting is expected to occur, the calculations would be based on
the unusual event that a blowdown is required and those emissions would be sent to a flare stack
and reported as a part of the required GHG reporting for the facility. Any leakage would be detected
and managed as an upset event. Continuous monitoring systems should trigger an alarm upon a
release of H2S and CO2. The mass of the CO2 released would be calculated for the operating
conditions, including pressure, flow rate, size of the leak-point opening, and duration of the leak.
This method is consistent with 40 CFR §98.448(a)(5), allowing the operator to calculate site-specific
variables used in the mass balance equation.

In the unlikely event that CO2 was released because of surface leakage, the mass emitted would be
calculated for each surface pathway according to methods outlined in the plan and totaled using
Equation RR-10 as follows:

CO2E = Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year
C02,x= Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting year
X = Leakage pathway

Calculation methods using equations from Subpart W will be used to calculate CO2 emissions due to
any surface leakage between the flow meter used to measure injection quantity and the injection
wellhead.

As discussed previously, the potential for pathways for all previously mentioned forms of leakage is
unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, Ozona believes the most appropriate method to quantify the mass of CO2
released will be determined on a case-by-case basis. Any mass of CO2 detected leaking to the
surface will be quantified by using industry proven engineering methods including, but not limited
to, engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling,
and history-matching of the sequestering reservoir performance, among others. In the unlikely
Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 75 of 80

X

x=l

Where:

-------
event that a leak occurs, it will be addressed, quantified, and documented within the appropriate
timeline. Any records of leakage events will be kept and stored as provided in Section 10.

7.5 Mass of CO2 Sequestered

The mass of CO2 sequestered in subsurface geologic formations will be calculated based on Equation
RR-12. Data collection for calculating the amount of CO2 sequestered in the O'Neal No. 4 will begin
once the subsurface recompletion work, and the surface facilities construction has been completed,
and subject to approval of the MRV plan. The calculation of sequestered volumes utilizes the
following equation as the O'Neal No. 4 will not actively produce oil, natural gas, or any other fluids:

C02 — C02i — C02e ~ C02pi

Where:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year

CO21 = Total annual CO2 mass injected (metric tons) in the well or group of wells covered by
this source category in the reporting year

CO2E = Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year

CO2F1 = Total annual CO2 mass emitted (metric tons) from equipment leaks and vented
emissions of CO2 from equipment located on the surface, between the flow meter used to
measure injection quantity and the injection wellhead, for which a calculation procedure is
provided in subpart W of this part.

CO2F1 will be calculated in accordance with Subpart W for reporting of GHGs. Because no venting is
expected to occur, the calculations would be based on the unusual event that a system blowdown
event occurs. Those emissions would be sent to a flare stack and reported as part of the GHG
reporting for the facility.

• Calculation methods from Subpart W will be used to calculate (Remissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 76 of 80

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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN

The O'Neal Gas Unit No. 4 is an existing natural gas well that will be recompleted as a Class II well
with corrosion-resistant materials. The Class II permit is still in process with the TRRC. Until this
permit is issued, Ozona cannot specify a date to acquire the baseline testing data. Ozona is
submitting this MRV application to the GHGRP to comply with the requirements of Subpart RR. The
MRV plan, including acquisition of baseline data, will be implemented upon receiving EPA approval.
The Annual Subpart RR Report will be filed on March 31 of the year following the reporting year.

Table 10 - Baseline Sampling Schedule

Sampling Location

Estimated Date

Comments

Fixed H2S/CO2 Monitors

Oct. 1, 2024

Baseline readings will be
established during
commissioning activities.

Soil gas sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Water well sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Notes:

•	Above dates are estimates subject to adjustment based on actual regulatory
approval dates and facilities construction timelines.

•	All baseline sampling will be performed prior to the start of recording data for
reporting under this MRV.

•	Commissioning activities include installation of surface facilities, including flowline,
compressors, manifolds, etc.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 77 of 80

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SECTION 9 - QUALITY ASSURANCE

This section identifies how Ozona plans to manage quality assurance and control to meet the

requirements of 40 CFR §98.444.

9.1	Monitoring QA/QC

CO2 Injected

•	The flow rate of the CO2 being injected will be measured with a volumetric flow meter,
consistent with API standards. These flow rates will be compiled quarterly.

•	The composition of the injectate stream will be measured upstream of the volumetric flow
meter with a continuous gas composition analyzer or representative sampling consistent
with API standards.

•	The gas composition measurements of the injected stream will be averaged quarterly.

•	The CO2 measurement equipment will be calibrated per the requirements of 40 CFR
§98.444(e) and §98.3(i).

CO2 Emissions from Leaks and Vented Emissions

•	Gas monitors at the facility and O'Neal No. 4 will be operated continuously, except for
maintenance and calibration.

•	Gas monitors will be calibrated according to the requirements of 40 CFR §98.444(e) and
§98.3(i).

•	Calculation methods from Subpart W will be used to calculate CChemissionsfrom equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Measurement Devices

•	Flow meters will be continuously operated except for maintenance and calibration.

•	Flow meters will be calibrated according to 40 CFR §98.3(i).

•	Flow meters will be operated and maintained in accordance with applicable standards as
published by a consensus-based standards organization.

All measured volumes of CO2 will be converted to standard cubic meters at a temperature of 60°F

and an absolute pressure of 1 atmosphere.

9.2	Missing Data

In accordance with 40 CFR §98.445, Ozona will use the following procedures to estimate missing

data if unable to collect the data needed for the mass balance calculations:

•	If a quarterly quantity of CO2 injected is missing, the amount will be estimated using a
representative quantity of CO2 injected from the nearest previous period at a similar
injection pressure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 78 of 80

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• Fugitive CO2 emissions from equipment leaks from facility surface equipment will be
estimated and reported per the procedures specified in Subpart W of 40 CFR §98.

9.3 MRV Plan Revisions

If any changes outlined in 40 CFR §98.448(d) occur, Ozona will revise and submit an amended MRV
plan within 180 days to the Administrator for approval.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 79 of 80

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SECTION 10 - RECORDS RETENTION

Ozona will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
3 years and include the following:

•	Quarterly records of the CO2 injected

o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the CO2 stream

•	Annual records of the information used to calculate the CO2 emitted by surface leakage from
leakage pathways.

•	Annual records of the information used to calculate CO2 emitted from equipment leaks and
vented emissions of CO2 from equipment located on the surface, between the flow meter
used to measure injection quantity and the injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 80 of 80

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APPENDICES
APPENDIX A - O'Neal No. 4 TRRC FORMS

APPENDIX A-l: GAU GROUNDWATER PROTECTION DETERMINATION

APPENDIX A-2: DRILLING PERMIT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

APPENDIX A-3: COMPLETION REPORT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

•	MINI FRACTURE REPORT

APPENDIX A-4: API 42-025-30388 CHARLIE C. OVERBY GU PLUGGING RECORDS

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APPENDIX B - AREA OF REVIEW

APPENDIX B-l: OIL AND GAS WELLS WITHIN THE MMA LIST

APPENDIX B-2: WATER WELLS WITHIN THE MMA LIST

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Appendix B: Submissions and Responses to Requests for Additional

Information

-------
©)zona

Carbon Capture & Sequestration

Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
O'Neal Gas Unit Well No. 4

Bee County, TX

Prepared for Ozona CCS, LLC
San Antonio, TX

By

Lonquist Sequestration, LLC
Austin, TX

Version 4.0
August 2024

LONQUIST

SEQUESTRATION LLC

Hi

-------
INTRODUCTION

Ozona CCS, LLC (Ozona) has a pending Class II acid gas injection (AGI) permit application with the
Texas Railroad Commission (TRRC), which was submitted in September of 2023 for its O'Neal Gas
Unit Well No. 4 (O'Neal No. 4), API No. 42-025-32658. Granting of this application would
authorize Ozona to inject up to 1.5 million standard cubic feet per day (MMscf/D) of treated acid
gas (TAG) into the Sligo Formation at a depth of 15,874 feet (ft) to 16,056 ft, with a maximum
allowable surface pressure of 7,920 pounds per square inch gauge (psig). The TAG for this AGI
well is associated with StarTex's Pawnee Treating Facility, located in a rural area of Bee County,
Texas, approximately 2.0 miles (mi) south of Pawnee, Texas, as shown in Figure 1.

Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4

Subpart RR MRV Plan - O'Neal No. 4

Page 2 of 80

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Ozona is submitting this Monitoring, Reporting, and Verification (MRV) plan to the EPA for
approval underTitle 40, U.S. Code of Federal Regulations (40 CFR) §98.440(a), Subpart RR, of the
Greenhouse Gas Reporting Program (GHGRP). In addition to submitting this MRV plan to the
EPA, Ozona has applied to the TRRC for the O'Neal GU No. 4's Class II permit. Ozona plans to
inject TAG for approximately 12 years. Table 1 shows the expected composition of the gas stream
to be sequestered from the nearby treating facility.

Table 1 - Expected TAG Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

Subpart RR MRV Plan - O'Neal No. 4

Page 3 of 80

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ACRONYMS AND ABBREVIATIONS

AMA
BCF
CH4
CMG

C02
E

EOS

EPA

ESD

FG

ft

GAPI

GAU

GEM

GHG

GHGRP

GL

H2S

JPHIE

mD

mi

MIT

MM

MMA

MCF

MMcf

MMscf

Subpart RR MRV Plan - O'Neal No. 4

Active Monitoring Area
Billion Cubic Feet
Methane

Computer Modelling Group, Ltd.

Carbon Dioxide (may also refer to other carbon

oxides)

East

Equation of State
Environmental Protection Agency
Emergency Shutdown
Fracture Gradient
Foot (Feet)

Gamma Units of the American Petroleum Institute
Groundwater Advisory Unit
Computer Modelling Group's GEM 2023.2
Greenhouse Gas

Greenhouse Gas Reporting Program
Ground Level Elevation
Hydrogen Sulfide

Effective Porosity (corrected for clay content)

Millidarcy

Mile(s)

Mechanical Integrity Test
Million

Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet

Page 4 of 80

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Mscf/D	Thousand Standard Cubic Feet per Day

MMscf/D	Million Standard Cubic Feet per Day

MRV	Monitoring, Reporting, and Verification

v	Poisson's Ratio

N	North

NW	Northwest

OBG	Overburden Gradient

PG	Pore Gradient

pH	Scale of Acidity

ppm	Parts per Million

psi	Pounds per Square Inch

psig	Pounds per Square Inch Gauge

S	South

SE	Southeast

SF	Safety Factor

SWD	Saltwater Disposal

TAC	Texas Administrative Code

TAG	Treated Acid Gas

TOC	Total Organic Carbon

TRRC	Texas Railroad Commission

UIC	Underground Injection Control

USDW	Underground Source of Drinking Water

W	West

Subpart RR MRV Plan - O'Neal No. 4

Page 5 of 80

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TABLE OF CONTENTS

INTRODUCTION	2

ACRONYMS AND ABBREVIATIONS	4

SECTION 1 - UIC INFORMATION	10

1.1	Underground Injection Control Permit Class: Class II	10

1.2	UIC Well Identification Number	10

1.3	Facility Address	10

SECTION 2 - PROJECT DESCRIPTION	11

2.1	Regional Geology	11

2.1.1	Geologic Setting and Depositional Environment	13

2.1.2	Regional Structure and Faulting	15

2.2	Site Characterization	17

2.2.1	Stratigraphy and Lithologic Characteristics	17

2.2.2	Upper Confining Interval - Pearsall Formation	19

2.2.3	Injection Interval - Upper Sligo Formation	21

2.2.4	Formation Fluid	23

2.2.5	Fracture Pressure Gradient	24

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations	25

2.3	Local Structure	25

2.4	Injection and Confinement Summary	30

2.5	Groundwater Hydrology	30

2.6	References	34

2.7	Description of the Injection Process	35

2.7.1 Current Operations	35

2.8	Reservoir Characterization Modeling	35

2.8.1 Simulation Modeling	39

SECTION 3 - DELINEATION OF MONITORING AREA	48

3.1	Maximum Monitoring Area	48

3.2	Active Monitoring Area	50

SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE	52

4.1	Leakage from Surface Equipment	53

4.2	Leakage Through Existing Wells Within the MMA	55

4.2.1	Future Drilling	59

4.2.2	Groundwater Wells	59

4.3	Leakage Through Faults and Fractures	61

4.4	Leakage Through the Upper Confining Zone	61

4.5	Leakage from Natural or Induced Seismicity	61

SECTION 5 - MONITORING FOR LEAKAGE	64

5.1	Leakage from Surface Equipment	65

5.2	Leakage Through Existing and Future Wells Within the MMA	67

5.2.1 Groundwater Quality Monitoring	68

5.3	Leakage Through Faults, Fractures, or Confining Seals	70

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5.4 Leakage Through Natural or Induced Seismicity	70

SECTION 6 - BASELINE DETERMINATIONS	72

6.1	Visual Inspections	72

6.2	H2S/ CO2 Monitoring	72

6.3	Operational Data	72

6.4	Continuous Monitoring	72

6.5	Groundwater Monitoring	73

SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION	74

7.1	Mass of CO2 Received	74

7.2	Mass of CO2 Injected	74

7.3	Mass of CO2 Produced	75

7.4	Mass of CO2 Emitted by Surface Leakage	75

7.5	Mass of CO2 Sequestered	76

SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN	77

SECTION 9 - QUALITY ASSURANCE	78

9.1	Monitoring QA/QC	78

9.2	Missing Data	78

9.3	MRV Plan Revisions	79

SECTION 10 - RECORDS RETENTION	80

Figures

Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4	2

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-

Ashby etal., 2012)	11

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby

etal., 2012)	12

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The
proposed injection interval is shaded light blue and proposed confining intervals are shaded light

yellow (modified from Bebout et al., 1981)	13

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981)	14

Figure 6-Generalized northwest to southeast schematic cross section of the Trinity Group, south
Texas (the line of section depicted in Figure 5). The red star and line represent the approximate
location of the O'Neal No. 4 (modified from Kirkland et al., 1987)	 15

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated
porosity and permeability values of typical facies (modified from Talbert and Atchley, 2000).. 15
Figure 8 - Structural features and fault zones near the proposed injection site. The red star
represents the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

	16

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through
Word field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).. 17

Subpart RR MRV Plan - O'Neal No. 4

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Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted	18

Figure 11 - Porosity-Permeability Crossplot of Pearsall Formation Crushed Rock Core Data

(Swanson et al., 2016)	20

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map. The
red star represents the approximate location of the O'Neal No. 4 (modified from Bebout et al.,

1981)	20

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)	21

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded

green >0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms	22

Figure 15 - Offset Wells Used for Formation Fluid Characterization	24

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

	25

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the

location of the O'Neal No. 4	27

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the

locator map	28

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on

the locator map	29

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of

the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	31

Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006)	 32

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	32

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	33

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model	37

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection)	41

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)	42

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

	44

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End

of Simulation)	45

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time	46

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum

Monitoring Area	49

Figure 31 - Active Monitoring Area	51

Figure 32 - O'Neal No. 4 Wellbore Schematic	56

Figure 33 - All Oil and Gas Wells Within the MMA	57

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA	58

Figure 35 - Groundwater Wells Within the MMA	60

Figure 36 - 25-km Seismicity Review	63

Figure 37 - O'Neal No. 4 Process Flow Diagram	66

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Figure 38 - Groundwater Wells	69

Figure 39 - Seismic Events and Monitoring Station	71

Tables

Table 1 - Expected TAG Composition	3

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo

oil-field brine samples	24

Table 3 - Gas Composition	35

Table 4 - Modeled Injectate Composition	36

Table 5 - GEM Model Layer Package Properties	38

Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection	47

Table 7 - Potential Leakage Pathway Risk Assessment	52

Table 8 - Summary of TAG Monitors and Equipment	54

Table 9 - Summary of Leakage Monitoring Methods	64

Table 10 - Baseline Sampling Schedule	77

Appendices

Appendix A - TRRC O'Neal Gas Unit Well No. 4 Forms

Appendix A-l - GAU Groundwater Protection Determination
Appendix A-2 - Drilling Permit
Appendix A-3 - Completion Report
Appendix A-4 - Plugging Records

Appendix B - Area of Review

Appendix B-l - Oil and Gas Wells Within the MMA List
Appendix B-2 - Water Wells Within the MMA List

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SECTION 1 - UIC INFORMATION

This section contains key information regarding the Underground Injection Control (UIC) Permit.

1.1	Underground Injection Control Permit Class: Class II

The TRRC regulates oil and gas activities in Texas and has primacy to implement the Underground
Injection Control (UIC) Class II program. The TRRC classifies the O'Neal No. 4 as a UIC Class II well.
Ozona has applied for a Class II permit for the O'Neal No. 4 under TRRC Rules 36 (Oil, Gas, or
Geothermal Resource Operation in Hydrogen Sulfide Areas) and 46 (Fluid Injection into Productive
Reservoirs).

1.2	UIC Well Identification Number

•	O'Neal No. 4, API No. 42-025-32658, UIC No. 56819

1.3	Facility Address

•	Facility Name: StarTex Pawnee Treating Facility

•	Operator: StarTex Field Services, LLC

•	Facility ID No. 568661

•	Coordinates in North American Datum for 1983 (NAD 83) for this facility:

o Latitude: 28.622211
o Longitude: -97.992772

•	Greenhouse Gas Reporting Program ID Information:

o Ozona will report under GHGRP ID No. 587021 for this Monitoring, Reporting
and Verification plan

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SECTION 2 - PROJECT DESCRIPTION

This section discusses the geologic setting, planned injection process and volumes, and reservoir
and plume modeling performed for the O'Neal No. 4 well.

The O'Neal No. 4 will inject the TAG stream into the Sligo Formation at a depth of 15,874 ft to
16,056 ft, and approximately 14,924 ft below the base of the Underground Source of Drinking
Water (USDW). Therefore, the well and the facility are designed to protect against the leakage
out of the injection interval, to protect against contaminating other subsurface formations, and —
most critically—to prevent surface releases.

2.1 Regional Geology

The O'Neal No. 4 (API No. 42-025-32658) is located in south Texas within the Gulf of Mexico
Basin. The onshore portion of the Gulf of Mexico basin spans approximately 148,049,000 acres
and encompasses portions of Texas, Louisiana, Mississippi, Alabama, Arkansas, Missouri,
Kentucky, Tennessee, Florida, and Georgia to the state-waters boundary of the United States
(Roberts-Ashby et al., 2012). The location of the O'Neal No. 4 is designated by the red star in
Figure 2, relative to the present coastal extent and major structural features of the basin.

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-Ashby et

al., 2012)

Subpart RR MRV Plan - O'Neal No. 4

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Figure 3 depicts a generalized stratigraphic column of the U.S. Gulf Coast, with light blue shading
signifying the proposed injection interval and green stars indicating productive formations
identified within 5 miles of the O'Neal No. 4. The injection interval is found within the Sligo
Formation, with confinement provided by the overlying Pearsall Formation and tight underlying
fades of the Lower Sligo and Hosston Formations.

System /
Series

Global
Chronostratigraphic
Units

Calabrian

Piacenzian
Zanclean

Messinian
Tortonian
Serravallian

Langhian
Burdigalian
Aquitanian

Chattian

Rupelian

Priabonian

Bartonian
Lutetian

Ypresian

Thanetian
Selandian
Danian

Maastrichtian

Campanian

Santonian
Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian
Hauterivian

Valanginian
Berriasian

North American
Chronostratigraphic
Units

Middle Mioc. Fleming Fm

Chickasawhayan

Vicksburgian

Jacksonian

Claibornian

Sabinian

Midwayan

Navarroan

Tayloran

Austinian

Eaglefordian

Woodbinian

Washitan-
Fredericksburgian

Trinitian

Nuevoleonian

Durangoan

Stratigraphic Unit

Undifferentiated

Undifferentiated

Upper Mioc.

Lower Mioc.

^X-Catahoula
W Fm /

Fm / Ss

Frio Formation

Vicksburg Formation

Jackson Group

Sparta Sand

Claiborne Group Cane River Fm

	Carrizo Sand

Wilcox Group

Midway Group

Navarro Group

Taylor Group

Austin Group /
Tokio Formation /
Eutaw Formation

Eagle Ford Shale

Woodbine / Tuscaloosa Fms

Washita Group
(Buda Ls)

Fredericksburg Group ,
(Edwards Ls / Paluxy Fm)'

Glen Rose Ls
(Rusk / Rodessa Fms)

Pearsall Formation |

Sligo"^f

Fm

Hosston
Formation

UPPER CONFINING INTERVAL
INJECTION INTERVAL

LOWER CONFINING
INTERVAL

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby et al.,

2012).

Subpart RR MRV Plan - O'Neal No. 4

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The targeted formations of this study are located entirely within the Trinity Group, as clarified by
the detailed stratigraphic column provided in Figure 4. During this time the area of interest was
located along a broad, shallow marine carbonate platform that extended along the northern rim
of the ancestral Gulf of Mexico. The Lower Cretaceous platform spanned approximately 870 mi
from western Florida to northeastern Mexico, with a shoreline-to-basin margin that ranged
between 45 to 125 mi wide (Yurewicz et al., 1993).

00
D
O

UJ

O
<
>—
UJ

ce
o

.

'E

Pearsal

Sliao

H osston

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The proposed
injection interval is shaded light blue and proposed confining intervals are shaded light yellow (modified

from Bebout et ai., 1981).

2.1.1 Geologic Setting and Depositional Environment

The depositional environment during the Lower Cretaceous generally consisted of a well-defined
platform margin with a shallow marine platform interior or lagoon to the north, a shallow marine
outer platform to the south, and a foreslope that gradually dipped southward towards the basin
center. The platform margin remained stable for tens of millions of years during the Cretaceous
but experienced episodic changes in sea level that resulted in cyclic deposition of several key
facies that vary both spatially and within the geologic section. Facies distributions were heavily
impacted by positioning relative to the margin, the height of the water column at any given time,
and the degree of energy or wave action within the system (Galloway, 2008; Yurewicz et al.,
1993).

In general, long stands of reef development and ooid shoaling developed primary porosity and
permeability along the shallow, high-energy carbonate platform and represent reservoir quality

Subpart RR MRV Plan - O'Neal No. 4

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-------
rock found within Cretaceous reef deposits. Deeper, basinward deposits tend to result in tighter
petrophysical properties due to a relative increase in the amount of entrained clay associated
with the heightening of the water column while moving downslope. Backreef deposits have the
potential for porosity development but tend to have low permeability due to a general lack of
wave action caused by restricted access to open water by the platform margin. Facies and
petrophysical properties of the Lower Cretaceous section are anticipated to be relatively
homogenous moving southwest-northwest along reef trend, with increased heterogeneity
moving northwest-southeast due to the orientation of the carbonate rim and its effect on
deposition and facies distributions (Yurewicz et a I1993).

Figure 5 displays the paleogeography during deposition of the Lower Cretaceous section to
visually demonstrate the position of the O'Neal No. 4 relative to the Sligo shelf margin and updip
extents of Sligo deposition. A generalized schematic cross section of the Trinity Group is provided
in Figure 6, which nearly intersects the project area from the northwest. The schematic illustrates
the gross section thickening basinward, with primary reservoir development improving with
proximity to the reef margin. Figure 7 displays a depositional model of the Lower Cretaceous
carbonate platform to visually conceptualize depositional environments and anticipated
petrophysical properties of facies introduced above.

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the
approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981).

Subpart RR MRV Plan - O'Neal No. 4	Page 14 of 80

-------
outcrop

subsurface

NW

SE

D
a

o
<

I

QC

o

o
w

5

D

Figure 6 - Generalized northwest to southeast schematic cross section of the Trinity Group, south Texas
(the line of section depicted in Figure 5). The red star and line represent the approximate location of the

O'Neal No, 4 (modified from Kirkland et al., 1987)

0=15-25
K>200

0=10-15
K=20-100

SHOAL

0=2-12
K<1

BACKREEF

Windward Fairweather Wave Base

FOREREEF
W CLAY

FOREREEF
W/NO CLAY

CLAY-RICH

LEGEND

Sedimentary Structures Grains

* Current Rippte
—— Flaser/Wavy Bedding
— mm Laminations
—v— Mud Cracks

- Ptanar and Festoon Bedding
1J Burrow Clay Seam

e Ootd Q) Oyster uncfrff
. PetokJ Bivalve uidiff.
C> Rudtst undrff. § Gastropod
Solitary Coral ® Echinoderm
O Dic&conus @ Ammonite

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated porosity and
permeability values of typical facies (modified from Talbert and Atchley, 2000).

2.1.2 Regional Structure arid Faulting

The Gulf of Mexico basin was formed by crustal extension and sea-floor spreading associated
with the Mesozoic breakup of Pangea. Rifting of northwest to southeast trending transfer faults
during the Middle Jurassic lasted approximately 25 million years and resulted in variable
thickness of the transcontinental crust underlying the region. By the Lower Cretaceous time, the
general outline and morphology of the Gulf were similar to that of present-day (Galloway, 2008;

GLEN ROSE

PEARSALL (undifferentiated!

SYCAMORE I

I HOSSTON

SLIGO

HAYNESVILLE

PALEOZOIC
|undif(erentiatedl

Subpart RR MRV Plan - O'Neal No. 4

Page 15 of 80

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Yurewicz et al,, 1993). Lower Cretaceous tectonic activity was limited to regional subsidence
associated with areas of variable crustal thickness and local structuring caused by movement of
Louann Salt (Yurewicz et al., 1993). The combination of these processes resulted in the structural
development of regional arches, grabens, uplifts, embayments, salt domes, and salt basins
around the northern edge of the basin (Dennen and Hackley, 2012; Galloway, 2008). The location
of these structural features can be referenced in Figures 2 and 8 relative to the location of the
O'Neal No. 4.

The schematic dip-oriented cross section displayed in Figure 9 presents a common interpretation
of the current structural setting. Most of the published literature suggests that faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as displayed in Figure 9,
with shallow faulting dying out before reaching the Pearsall Formation. However, one source did
interpret the potential for faulting to the south (Swanson et al., 2016). The closest potential fault
is depicted in Figure 8 relative to the location of the O'Neal No. 4. According to the map, the
interpreted fault lies approximately 4.25 miles south-southeast of the well and approximately 3.9
miles south-southeast of the stabilized plume extent in the year 2047.

50

50
_L_

~T—r

100 Kilometers

100 Miles
J	I

EXPLANATION

O
*

Uplift

Plateau

Basin

TPS boundary
Fault zone

Lower Cretaceous shelf margin
County line

Field in Edwards Limestone
associated with fault zones

Salt structure

Anticlinal axis; large arrow indicates
direction of plunge

GOM Gulf of Mexico

Figure 8 - Structural features and fault zones near the proposed injection site. The red star represents
the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

Rio Grande
embayment

Edwards plateau

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! MMe	EXPLANATION

-|	1	| | Edwards Limestone, potential reservoir

1 Kilometer	facies (shallow-water facies)

1 Pearsall Fm.

~ Sligo Formation, wedges of downslope
debris

Fault

Sligo Fm.

Hosston Fm.

Sligo Fm.
shelf margin

Edwards Ls.

Pearsall Fm.

Word field

Published
Edwards Ls.
shelf margin

Taylor Gp.

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through Word
field, northeast of the O'Neal No. 4 project area (modified from Swanson et a!., 2016).

2.2 Site Characterization

The following section discusses site-specific geological characteristics of the O'Neal No. 4 well
2.2.1 Stratigraphy and Lithologic Characteristics

Figure 10 depicts openhole logs from two offset wells (API No. 42-025-00473 and API No. 42-025-
31892) to the O'Neal No. 4, indicating the injection and primary upper confining zones. The
Tomasek No. 1 (API No. 42-025-00473) is located approximately 1 mi northeast of the O'Neal No.
4 and displays the shallow section from 0-8,200 ft. The Gordon No. 3 (API No. 42-025-31892) is
located approximately 1.6 mi northeast of the O'Neal No. 4 and displays a shallow section from
8,200-16,400 ft.

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BB-SOUTHTEX, LLC

TOMASEKGAS UNIT 1

42025004730000

-:r::

BASE USDW

SPARTA
WECHES SS

QUEEN_CITY

RECKLAW

COOK MOUNTAIN

PIONEER NATURAL RESOURCES

A. GORDON GAS UNIT 3

42025318920000

ffl

midway





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ttttt =tJ1|ft|

AUSTIN
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Figure 10-Type Log with Tops, Confining, and Injection Intervals Depicted

Subpart RR MRV Plan - O'Neal No. 4

Page 18 of 80

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2.2.2 Upper Confining Interval - Pearsall Formation

Following the deposition of the Sligo Formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
Formation throughout the region (Roberts-Ashby et al., 2012). The Pine Island Shale consists of
alternating beds of pelagic mudstone, hemipelagic mudstone, and Fe-rich dolomitic mudstone
interpreted to have been deposited along the outer ramp. This is in agreement with core data
published by Bebout and others (1981), and later by Swanson and others (2016), who identified
the presence of C. Margerelli, a nannofossil indicative of anoxic conditions. The core-derived
porosity-permeability relationship displayed in Figure 11 suggests that the permeability of the
Pine Island Shale is incredibly low and stays below 0.0001 mD, regardless of porosity (Figure 11;
Hull, 2011). This is further supported by the 2012 U.S. Geological Survey (USGS) CO2 Storage
Resource Assessment, which suggests that the Pine Island Shale contains the physical properties
required to act as a regional seal and was chosen as the upward confining interval for their
C50490108 Storage Assessment Unit (SAU) assessment of the Gulf Coast. The 2012 USGS report
also noted that the Pine Island Shale is a sufficient regional seal with as little as 50 ft of contiguous
shale development. The top of the Pearsall is encountered at a depth of 15,339 ft in the O'Neal
No. 4, with a gross thickness of 535 ft (Figure 14). The Pine Island Shale member is approximately
130 ft thick at the O'Neal No. 4 location, with deposition of additional members of the overlying
Pearsall Formation, which include the Cow Creek Limestone, Cow Creek shale, and Bexar Shale
Members (Roberts-Ashby et al., 2012; Swanson et al., 2016).

The seismic line displayed in Figure 12 runs northwest to southeast across the Stuart City reef
trend southwest of the project area. The top of the Buda, Pearsall, and Sligo Formation markers
are depicted in color to demonstrate the lateral continuity of the section near the O'Neal No. 4.
Seismic reflectors within the Pearsall Formation appear to lack deformation, suggesting
consistent deposition over the reef margin. This is in agreement with reviewed published
literature, which suggests deposition of the Pine Island Shale occurred during widespread marine
transgression (Bebout et al., 1981; Hull, 2011.; Roberts-Ashby et al., 2012, Swanson et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 19 of 80

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0.0001
(100 nd;

Permeability and Porosity-
Crushed Rock Data

"O

E

-O

ro

d)

E

-------
2.2.3 Injection Interval - Upper Sligo Formation

The Sligo Formation underlies the Pearsall Formation and is predominately composed of shelf-
edge limestones that were deposited along the Lower Cretaceous platform (Roberts-Ashby et al.,
2012). However, the Cretaceous also experienced episodic changes in sea level that resulted in
the deposition of cyclic Sligo facies that vary both spatially and within the geologic section. The
overall Sligo interval is interpreted to be a transgressive sequence occasionally interrupted by
progradational cycles that consists of porous shoaling-upward sequences that represent primary
reservoir potential within the system (Bebout et al., 1981). Facies distributions of these reef
complexes are heavily impacted by positioning relative to the margin, the height of the water
column at any given time, and the degree of energy or wave action within the system (Galloway,
2008). Figure 13 depicts an idealized environmental setting of the Lower Cretaceous platform
during deposition. Primary porosity and permeability of the upper Sligo Formation tends to
develop in high-energy sequences with normal marine conditions that are dominated by the
deposition of oolitic and skeletal grainstones.

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)

According to the 2012 USGS CO2 Storage Resource Assessment, "the average porosity in the
porous intervals of the storage reservoir decreases with depth from 9 to 16 percent" for their
C50490108 DEEP SAU assessment of the Gulf Coast (>13,000 ft). The study also reported that
"the average permeability in the storage reservoirs decreases with depth from 0.05 to 200 mD,
with a most-likely value of 8 mD" for their C50490108 DEEP SAU assessment of the Gulf Coast
(Roberts-Ashby et al., 2012).

The top of the upper Sligo is encountered at a depth of 15,874 ft in the O'Neal No. 4 with a gross
thickness of 183 ft (Figure 14). The type log displayed in Figure 14 plots effective porosity for the
confining interval and the total porosity of the injection interval, to account for the increased

Subpart RR MRV Plan - O'Neal No. 4

Page 21 of 80

-------
volume of shale (Vshale) seen in the Pearsall Formation. The porosity data was compared to the
analysis performed by Nutech to generate a permeability curve with a reasonable porosity-
permeability relationship. The permeability curve was generated utilizing the Coates
permeability equation, incorporated with a 20% irreducible brine saturation to match analysis
provided by Nutech. Petrophysical analysis of the O'Neal No. 4 indicates an average porosity of
4.6%, a maximum porosity of 15%, an average permeability of 0.16 mD, and a maximum
permeability of 3.3 mD. These curves have been extrapolated to the injection site and used to
establish reservoir characteristics in the plume model.

BB-SOUTHTEX, LLC

ONEAL GAS UNIT 4

o

42025326580000

GR

0

150

0.2

ILD

> 5 ohm 2000

K_COATES20
10	0

0.3

PHIE

>0 %

0

DPHI

0.3

> 0 %

0

Pearsall

Very Low Perm:
Pine Island Shale

Very Low Perm:
Lower Sligo
Formation

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded green
>0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms.

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2.2.4 Formation Fluid

The USGS National Produced Waters Geochemical Database version 3.0 was reviewed for
chemical analyses of Sligo oil-field brines within the state of Texas (Blondes et al., 2023). Only
two samples were identified from the Sligo Formation: one located approximately 29 mi north-
northeast in Karnes County and one located approximately 72 mi northeast in Gonzales County.
The locations of these wells are shown in Figure 15 relative to the O'Neal No. 4. A summary of
water chemistry analyses conducted on the two Texas Sligo oil-field brine samples is provided in
Table 2 (page 25).

Averages from the samples were utilized for model assumptions due to the minimal Sligo sample
availability and wide geographic spread of Sligo analysis. Total Dissolved Solids (TDS) of the
samples contain a wide range of reported values but averaged 176,470 parts per million (ppm).
Model sensitivities were established by running iterations with varying TDS values to understand
the effect of brine concentrations on plume extents. The results suggested higher density brine
values lead to smaller plumes; therefore, a value of 150,000 ppm was established in the model
for a conservative approach. If the actual formation fluid sample that will be tested during the
recompletion work produces a material difference in the plume, Ozona will submit an updated
MRV plan.

Based on the results of the investigation, in situ Sligo reservoir fluid is anticipated to contain
greater than 20,000 ppm TDS near the O'Neal No. 4, qualifying the aquifer as saline. These
analyses indicate the in situ reservoir fluid of the Sligo Formation is compatible with the proposed
injection fluids.

Subpart RR MRV Plan - O'Neal No. 4

Page 23 of 80

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Figure 15 - Offset Wells Used for Formation Fluid Characterization

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo oil-field

brine samples.

Measurement

Karnes County
Sample

Gonzales
County Sample

Average

Total Dissolved Solids (mg/L)

234,646

117,470

176,058

Sodium (mg/L)

51,168

27,909

39,539

Calcium (mg/L)

34,335

8,684

21,510

Chloride (mg/L)

146,500

57,811

102,156

Sample Depth (ft)

13,580 to 13,660

8,290-8,305

-

pH

5.9

8.2

7.05

2.2.5 Fracture Pressure Gradient

The fracture pressure gradient was obtained from a fracture report taken during the April 1993
completion of the Sligo interval in the O'Neal No. 4. The Sligo was perforated between the depths
of 15,874 ft and 16,056 ft, with continuous monitoring during the minifrac job. The report noted
a calculated fracture gradient of 0.954 psi/ft based on an initial shut-in pressure (ISIP) of 8,312

Subpart RR MRV Plan - O'Neal No. 4

Page 24 of 80

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psi. A 10% safety factor was then applied to the calculated gradient, resulting in a maximum
allowed bottomhole pressure of 0.86 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.

2.2.6 Lower Confining Interval - Lower Sligo and Hosston Formations

The O'Neal No. 4 reaches its total depth in the lower Sligo Formation, directly below the upper
Sligo proposed injection interval. The lower Sligo is interpreted by Bebout and others (1981) to
represent the seaward extension of the low-energy lagoon and tidal-flat system of the underlying
Hosston Formation, a sequence of siliciclastics, evaporites, and dolomitic mudstone (Figure 16).
The Hosston to lower Sligo "contact" represents a gradational package with a decrease in
terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the lower Sligo. The lower Sligo consists of numerous cycles
of subtidal to supratidal carbonates deposited in a low-energy lagoon and tidal-flat system
(Bebout et al., 1981). These low permeability facies of the lower Sligo and underlying Hosston
Formation will provide lower confinement to the upper Sligo injection interval. Figure 16
illustrates the typical environmental setting for the deposition of tidal flat facies along the Lower
Cretaceous margin. The type log displayed in Figure 14 (Section 2.2.3) illustrates that the
porosity of the lower Sligo ranges between 0-2% with permeability staying close to 0 mD.
Therefore, the petrophysicai characteristics of the lower Sligo and Hosston are ideal for
prohibiting the migration of the injection stream outside of the injection interval.

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

2.3 Local Structure

Structures surrounding the proposed sequestration site were influenced by regional arches,
grabens, uplifts, embayments, movement of Louann Salt, and the development of carbonate reef
complexes around the northern edge of the basin. However, one potential fault was identified
in the literature within proximity and lies approximately 4.25 mi south-southeast of the well and

Subpart RR MRV Plan - O'Neal No. 4

Page 25 of 80

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approximately 3.9 mi south-southeast of the stabilized plume extent in the year 2062 (Swanson
et al., 2016). The location of these structural features can be referenced in Figures 2 and 8
relative to the location of the O'Neal No. 4.

A subsea true vertical depth (SSTVD) structure map on the top of the Sligo Formation is provided
in Figure 17. The map illustrates the gentle basinward dip of the Sligo from the northwest to the
southeast. The structural cross sections provided in Figures 18 and 19 (pages 28 and 29,
respectively) illustrate the structural changes encountered in moving away from the O'Neal No.
4 site. The figures also demonstrate the laterally continuous nature of the Pearsall Formation
that overlies the injection interval, with sufficient thickness and modeled petrophysical
properties to alleviate the risk of upward migration of injected fluids. Section 2.1.2, discussing
regional structure and faulting, presents a regional discussion pertinent to this topic.

Subpart RR MRV Plan - O'Neal No. 4

Page 26 of 80

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Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the location of the O'Neal No. 4.

Subpart RR MRV Plan - O'Neal No. 4

Page 27 of 80

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13400

15400
15500
15600
15700
15800

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Color Fill

ASTN

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11800
11900
12000
12100
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14400

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Jpper Confining Zone
(Pearsall Formation)

SLGO

Injection Reservoir
(Sligo Formation)

SLGOJNJ
BASE

11700
11800
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12700
12800
12900
13000
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13200

1M

Logged
cased
hole in
EDRD,
DPHI
Over-
estimated

CLRS

Figure 18- Northwest to southeast structural cross section: A-A' Oriented along regional dip.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 28 of 80

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16650
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15350"
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16850
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16050
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SLGO

Injection Reservoir
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SLGOJNJ
BASE

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Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 29 of 80

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2.4 Injection and Confinement Summary

The lithologic and petrophysical characteristics of the Sligo Formation at the O'Neal No. 4 well
location indicate that the reservoir contains the necessary thickness, porosity, and permeability to
receive the proposed injection stream. The overlying Pearsall Formation is regionally extensive at
the O'Neal No. 4 with low permeability and sufficient thickness to serve as the upper confining
interval. Beneath the injection interval, the low permeability, low porosity facies tidal flat, and
lagoonal facies of the lower Sligo and underlying Hosston Formation are unsuitable for fluid
migration and serve as the lower confining interval.

2.5 Groundwater Hydrology

Bee County falls within the boundary of the Bee Groundwater Conservation District. Only one
aquifer is identified by the Texas Water Development Board's Texas Aquifers Study near the O'Neal
No. 4 well location, the unconfined to semi-confined Gulf Coast aquifer. The Gulf Coast aquifer
parallels the Gulf of Mexico and extends across the state of Texas from the Mexican border to the
border of Louisiana (Bruun et al., 2016). The extents of the Gulf Coast aquifer are provided in Figure
20 for reference.

The Gulf Coast aquifer is a major aquifer system comprised of several individual aquifers: the Jasper,
Evangeline, and Chicot. These aquifers are composed of discontinuous clay, silt, sand, and gravel
beds that range from Miocene to Holocene in age (Figure 21, page 32). Numerous interbedded
lenses and layers of silt and clay are present within the aquifers, which can confine individual aquifers
locally. The underlying Oligocene Catahoula tuff represents the lower confining interval, but it
should be noted that the formation is prone to leaking along the base of the aquifer. However, the
Burkeville confining interval provides isolation between Jasper and Evangeline aquifers which helps
protect the shallower Evangeline and Chicot Aquifers (Bruun et al., 2016).

The schematic cross section provided in Figure 22 (page 32) runs south of the O'Neal No. 4,
illustrating the structure and stratigraphy of the aquifer system. The thickness of individual
sedimentary units within the Cenozoic section tends to thicken towards the Gulf of Mexico due to
the presence of growth faults that allow additional loading of unconsolidated sediment. The total
net sand thickness of the aquifer system ranges between 700 ft of sand in the south, to over 1,300
ft in the north, with the saturated freshwater thickness averaging 1,000 ft.

The water quality of the aquifer system varies with depth and locality but water quality generally
improves towards the central to northeastern portions of the aquifer where TDS values are less than
500 milligrams per liter (mg/L). The salinity of the Gulf Coast aquifer increases to the south, where
TDS ranges between 1,000 mg/L to more than 10,000 mg/L. The Texas Water Development Board's
Texas Aquifers Study (2016) suggests that areas associated with higher salinities are possibly
associated with saltwater intrusion likely "resulting from groundwater pumping or to brine migration
in response to oil field operations and natural flows from salt domes intruding into the aquifer"
(Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 30 of 80

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According to the TDS map of the Gulf Coast aquifer (Figure 23), the TDS in northern Bee County
range between 500-3,000 mg/L near the O'Neal No, 4, categorizing the aquifer as fresh to slightly
saline.

The TRRC's Groundwater Advisory Unit (GAU) identified the Base of Useable Quality water (BUQW)
at a depth of 250 ft and the base of the USDW at a depth of 950 ft at the location of the O'Neal No.
4. Approximately 14,924 ft is therefore separating the base of the USDW and the injection interval.
(A copy of the GAU's Groundwater Protection Determination letter issued by the TRRC as part of the
Class II permitting process for the O'Neal No. 4 is provided in Exhibit A-l.) The base of the deepest
aquifer is separated from the injection interval by more than 14,924 ft of rock, including 4,200 feet
of Midway shale. Though unlikely for reasons outlined in the sections here on confinement and
potential leaks, if the migration of injected fluid did occur above the Pearsall Formation, thousands
of feet of tight sandstone, limestone, shale, and anhydrite beds occur between the injection interval
and the lowest water-bearing aquifer.

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of the
O'Neal No. 4 (modified from Bruun, B., et al., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 31 of 80

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System

Series

Stratigraphic Units

Hydrostratigraphy

Baker(1979)

Quaternary

Holocene

Alluvium

Chicot aquifer

Pleistocene

Beaumont Clay

Lissie
Formation

Montgomery
Formation

Bentley
Formation

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Tertiary

Pliocene

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Evangeline aquifer

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Oligocene

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Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury arid Turco, 2006)

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun et a!., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 32 of 80

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,nderson

Brown

Hamilton

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Houston

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Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 33 of 80

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2.6 References

Bebout, D.G., Budd, D.A., and Schatzinger, R.A. (1981). Depositional and Diagenetic History of the
Sligo and Hosston Formations (Lower Cretaceous) in South Texas: The University of Texas at
Austin, Bureau of Economic Geology, Report of Investigations No. 109.

Blondes, M.S., Gans, K.D., Engle, M.A. et al. (2018). U.S. Geological Survey National Produced Waters
Geochemical Database (Ver. 2.3, January 2018): U.S. Geological Survey data release,
https://doi.org/10.5066/F7J964W8.

Bruun, B., Anaya, R., Boghici, R. et al. (2016). Texas Aquifers Study: Chapter 6, Gulf Coast Aquifers.

Chowdhury, A.H. and Turco, M.J. (2006). Geology of the Gulf Coast Aquifer, Texas. In: Mace, R.E., et
al., Eds., Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report.

Dennen, K.O. and Hackley, P.C. (2012). Definition of Greater Gulf Basin Lower Cretaceous and Upper
Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico
basin onshore and state waters: https://pubs.usgs.gov/publication/70176229.

Galloway, W.E. (2008). Sedimentary Basins of the World, Chapter 15: Depositional Evolution of the
Gulf of Mexico Sedimentary Basin, 505-549.

Hull, D.C. (2011). Stratigraphic Architecture, Depositional Systems, and Reservoir Characteristics of
the Pearsall Shale-Gas System, Lower Cretaceous, South Texas: Thesis for M.S. of Science in
Geology, University of Texas, Austin.

Kirkland, B.L., Lighty, R.G., Rezak, R., and Tieh, T.T. (1987). Lower Cretaceous barrier reef and outer
shelf facies, Sligo Formation, south Texas, United States.

Roberts-Ashby, T.L., Brennan, S.T., Buursink, M.L. et al. (2012). Geologic framework for the national
assessment of carbon dioxide storage resources: U.S. Gulf Coast. USGS.

Swanson, S.M., Enomoto, C.B., Dennen, K.O. et al. (2017). Geologic assessment of undiscovered oil
and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate
rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain
and State Waters: U.S. Geological Survey Open-File Report 2016-1199, 69 p.,
https://doi.org/10.3133/ofr20161199.

Talbert, S.J. and Atchley, S.J. (2000). Sequence Stratigraphy of the Lower Cretaceous (Albian)
Fredericksburg Group, Central and North Texas: Department of Geology, Baylor University,
Waco, Texas 76798.

Yurewicz, D.A., Marler, T.B., Meyerholtz, K.A., and Siroky, F.X. (1993). Early Cretaceous Carbonate
Platform, North Rim of the Gulf of Mexico, Mississippi, and Louisiana.

Subpart RR MRV Plan - O'Neal No. 4

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2.7 Description of the Injection Process

2.7.1 Current Operations

The Pawnee Treating Facility and the O'Neal No. 4 are existing operating assets. The O'Neal No. 4
will be recompleted for acid gas injection service under the Class II permit process. Under the Class
II application, the maximum injection rate is 28 MT/yr (1.5 MMscf/d). The TAG is 98.2% CO2, which
equates to 27.5 MT/yr of CO2 each year. The current composition of the TAG stream is displayed in
Table 3.

Table 3 - Gas Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

The facility is designed to treat, dehydrate, and compress the natural gas produced from the
surrounding acreage in Bee County. The facility uses an amine unit to remove the CO2 and other
constituents from the gas stream. The TAG stream is then dehydrated, compressed, and routed
directly to the O'Neal No. 4 for injection. The remaining gas stream is processed to separate the
natural gas liquids from the natural gas. The facility is monitored 24 hours per day, 7 days per week.

2.8 Reservoir Characterization Modeling

The modeling software used to evaluate this project was Computer Modelling Group, Ltd.'s GEM
2023.2 (GEM) simulator, one of the most comprehensive reservoir simulation software packages for
conventional, unconventional, and secondary recovery. The GEM utilizes equation-of-state (EOS)
algorithms in conjunction with some of the most advanced computational methods to evaluate
compositional, chemical, and geochemical processes and characteristics. This results in the creation
of exceedingly precise and dependable simulation models for carbon injection and storage. The
GEM model holds recognition from the EPA for its application in the delineation modeling aspect of
the area of review, as outlined in the Class VI Well Area of Review Evaluation and Corrective Action
Guidance document.

The Sligo Formation serves as the target formation for the O'Neal No. 4 (API No. 42-025-32658).
The Petra software package was utilized to construct the geological model for this target formation.
Within Petra, formation top contours were generated and subsequently brought into GEM to
outline the geological structure.

Porosity and permeability estimates were determined using the porosity log from the O'Neal No. 4.
A petrophysical analysis was then conducted to establish a correlation between porosity values and
permeability, employing the Coates equation. Both the porosity and permeability estimates from

Subpart RR MRV Plan - O'Neal No. 4

Page 35 of 80

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the O'Neal No. 4 were incorporated into the model, with the assumption that they exhibit lateral
homogeneity throughout the reservoir.

The reservoir is assumed to be at hydrostatic equilibrium. Given the geological formation in which
this well is located and its previous history as a gas producer, the model is assumed to be primarily
saturated with gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine
saturated, as deduced from the well log data. The modeled injection interval exhibits an average
permeability of 0.23 mD and an average porosity of 5%. All layers within the model have been
perforated. An infinite-acting reservoir has been created to simulate the boundary conditions.

The gas injectate is composed predominantly of CO2 as shown in Table 4. The modeled composition
takes into consideration the carbon dioxide and other constituents of the total stream. As the
facility has been in operation for many years, the gas composition for the proposed injection period
is expected to remain constant.

Table 4 - Modeled Injectate Composition

Component

Expected Composition
(mol %)

Modeled
Composition (mol %)

Carbon Dioxide (C02)

98.2

98.2

Hydrocarbons

1.03

Hydrocarbons

Hydrogen Sulfide

0.4

Hydrogen Sulfide

Nitrogen

0.37

Nitrogen

Core data from the literature review was used to determine residual gas saturation (Keelan and
Pugh, 1975) and relative permeability curves between carbon dioxide and the connate brine within
the Sligo carbonates (Bennion and Bachu, 2010). A maximum residual gas saturation of 35% was
assigned to the model based on core from the literature review. The Corey-Brooks method was
used to create relative permeability curves. The key inputs used to create the relative permeability
curves in the model include a Corey exponent for brine of 1.8, a Corey exponent for gas of 2.5, brine
and gas relative permeability endpoints of 0.8 and 0.5, respectively, and an irreducible brine
saturation of 20%. The relative permeability curves used for the GEM model are shown in Figure
24.

Subpart RR MRV Plan - O'Neal No. 4

Page 36 of 80

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1

2-Phase (C02/Brine) Relative Permeability Curves
O'Neal No. 4 Sligo Formation

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Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model

The grid contains 81 blocks in the x-direction (east-west) and 81 blocks in the y-direction (north-
south), resulting in a total of 6,561 grid blocks per layer. Each grid block spans dimensions of 250 ft
x 250 ft. This configuration yields a grid size measuring 20,250 ft x 20,250 ft, equating to just under
15 square miles in area. The grid cells in the vicinity of the O'Neal No. 4, within a radius of 0.5 mi,
have been refined to dimensions of 83.333 ft x 83.333 ft in all layers. This refinement is employed
to ensure a more accurate representation of the plume and pressure effects near the wellbore.

In the model, each layer is characterized by homogeneous permeability and porosity values. These
values are derived from the porosity log of the O'Neal No. 4. The model encompasses a total of 61
layers, each featuring a thickness of approximately 3 ft per layer. As previously mentioned, the
model is perforated in each layer, with the top layer being the top of the injection interval and the
bottom layer being the lowest portion of the injection interval. The summarized property values for
each of these packages are displayed in Table 5.

Subpart RR MRV Plan - O'Neal No. 4

Page 37 of 80

-------
Table 5 - GEM Model Layer Package Properties

Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

1

15,874

3

0.004

3.75%

2

15,877

3

0.002

2.98%

3

15,880

3

0.001

1.62%

4

15,883

3

0.001

1.78%

5

15,886

3

0.002

2.32%

6

15,889

3

0.001

1.96%

7

15,892

3

0.002

3.10%

8

15,895

3

0.002

2.99%

9

15,898

3

0.003

3.52%

10

15,901

3

0.006

4.00%

11

15,904

3

0.005

3.93%

12

15,907

3

0.001

2.15%

13

15,910

3

0.001

1.99%

14

15,913

3

0.002

2.97%

15

15,916

3

0.001

2.22%

16

15,919

3

0.002

2.88%

17

15,922

3

0.001

2.38%

18

15,925

3

0.093

6.68%

19

15,928

3

0.005

2.62%

20

15,931

3

0.002

2.58%

21

15,934

3

0.003

3.07%

22

15,937

3

0.006

3.62%

23

15,940

3

0.002

2.68%

24

15,943

3

0.001

1.08%

25

15,946

3

0.002

1.87%

26

15,949

3

0.025

4.70%

27

15,952

3

0.024

4.37%

28

15,955

3

0.001

1.97%

29

15,958

3

0.003

2.27%

30

15,961

3

0.007

3.09%

31

15,964

3

0.110

6.75%

32

15,967

3

0.037

5.62%

33

15,970

3

0.011

4.41%

34

15,973

3

0.022

4.59%

35

15,976

3

0.297

7.88%

36

15,979

3

0.440

9.21%

37

15,982

3

0.060

5.90%

38

15,985

3

0.001

2.22%

39

15,988

3

0.001

2.21%

Subpart RR MRV Plan - O'Neal No. 4

Page 38 of 80

-------
Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

40

15,991

3

0.001

1.12%

41

15,994

3

0.003

2.05%

42

15,997

3

0.014

4.56%

43

16,000

3

0.007

4.15%

44

16,003

3

0.033

5.95%

45

16,006

3

1.233

10.25%

46

16,009

3

1.476

12.04%

47

16,012

3

0.566

10.08%

48

16,015

3

1.679

12.18%

49

16,018

3

2.194

13.08%

50

16,021

3

1.235

12.02%

51

16,024

3

0.788

11.22%

52

16,027

3

0.944

10.48%

53

16,030

3

0.424

9.05%

54

16,033

3

0.378

8.85%

55

16,036

3

0.378

8.81%

56

16,039

3

0.378

8.84%

57

16,042

3

0.736

9.91%

58

16,045

3

0.232

7.94%

59

16,048

3

0.238

7.97%

60

16,051

3

0.012

3.01%

61

16,054

3

0.038

4.30%

2.8.1 Simulation Modeling

The primary objectives of the model simulation were as follows:

1.	Estimate the maximum areal extent and density drift of the injectate plume after injection.

2.	Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone.

3.	Assess the likelihood of the injectate plume migrating into potential leak pathways.

The reservoir is assumed to have an irreducible brine saturation of 20%. The salinity of the brine
within the formation is estimated to be 150,000 ppm (USGS National Produced Waters Geochemical
Database, Ver. 2.3), typical for the region and formation. The injectate stream is primarily composed
of CO2 and H2S as stated previously. Core data from the literature was used to help generate relative
permeability curves. From the literature review, also as previously discussed, cores that most
closely represent the carbonate rock formation of the Sligo seen in this region were identified, and
the Corey-Brooks equations were used to develop the curves (Bennion and Bachu, 2010). A low,
conservative residual gas saturation based on the cores from the literature review was then used to
estimate the size of the plume (Keelan and Pugh, 1975).

Subpart RR MRV Plan - O'Neal No. 4

Page 39 of 80

-------
The model is initialized with a reference pressure of 10,995 psig at a subsea depth of 15,740 ft. This,
when a Kelly Bushing "KB" elevation of 334 ft is considered, correlates to a gradient of 0.684 psi/ft.
This pressure gradient was determined from production data of the O'Neal No. 4. An initial reservoir
pressure of 0.76 psi/ft was calculated before initial production. However, in 1997, after producing
approximately 0.5 billion cubic feet (Bcf) of gas, the well was shut in. The last bottomhole pressure
reading was calculated to be 0.480 psi/ft. This assumes the reservoir repressurizes after production
ceases, but not fully back to in situ conditions. Therefore, a 10% safety factor was given to the initial
reservoir pressure gradient of 0.76 psi/ft, and a gradient of 0.684 psi/ft was implemented into the
model as a conservative estimate. A skin factor of -2 was applied to the well to simulate the
stimulation of the O'Neal No. 4 for gas production from the Sligo Formation, which is based on the
acid fracture report, provided in Appendix A-3.

The fracture gradient of the injection zone was estimated to be 0.954 psi/ft, which was determined
from the acid fracture report. A 10% safety factor was then applied to this number, putting the
maximum bottomhole pressure allowed in the model at 0.86 psi/ft, which is equivalent to 13,652
psig at the top of the Sligo injection interval.

The model, which begins in January 2025, runs for a total of 22 years, comprising 12 years of active
injection, and is then succeeded by 10 years of density drift. Throughout the entire 12-year injection
period, an injection rate of 1.5 MMscf/D is used to model the maximum available rate, yielding the
largest estimate of the plume size. After the 12-year injection period, when the O'Neal No. 4 ceases
injection, the density drift of the plume continues until the plume stabilizes 10 years later. The
maximum plume extent during the 12-year injection period is shown in Figure 25. The final extent
after 10 years of density drift after injection ceases is shown in Figure 26 (page 42).

Subpart RR MRV Plan - O'Neal No. 4

Page 40 of 80

-------
C02 Saturation at End of Injection

	i	i

283750 -

282500

281250

280000 -

N

0.80-—j

0.70

-0.60

-0.50

-0.40

-0.30

-0.20

I0'10

O.oJ

278750 —	Actual Scale: 1:0

Y/X: 1:1
Axis Units: ft
Total Blocks: 459,269
Active Blocks: 459,269

I	I	I	I	I	I

2316000	2318000	2320000	2322000	2324000	2326000

Figure 25 - Areal View of Saturation Piume at Shut-in (End of injection)

Subpart RR MRV Plan - O'Neal No. 4

Page 41 of 80

-------
283750 -

282500

281250

280000 -

278750

CO? Saturation at End of Simulation

.	i 	i

o I

0.70

-0.60

-0.50

-0.40

-0.30

-0.20

|

0.03J

Actual Scale: 1:0
Y/X: 1:1
Axis Units: ft
Total Blocks: 459.269
Active Blocks: 459.269

I

2324000

2316000

2318000

2320000

2322000

2326000

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal No. 4

Page 42 of 80

-------
The cross-sectional view of the O'Neal No. 4 shows the extent of the plume from a side-view angle,
cutting through the formation at the wellbore. Figure 27 shows the maximum plume extent during
the 12-year injection period. During this time, gas from the injection well is injected into the
permeable layers of the formation and predominantly travels laterally. Figure 28 (page 45) shows
the final extent of the plume after 10 years of migration. Then, the effects of residual gas saturation
and migration due to density drift are clearly shown. At least 35% of injected gas that travels into
each grid cell is trapped, as the gas travels mostly vertically—as it is less dense than the formation
brine—until an impermeable layer is reached. Both figures are shown in an east-to-west view.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 43 of 80

-------
C02 Saturation at End of Injection

15500 -

15563 -

15625 -

15688 -

15750 -

15813 -



0.70

0.60

0.50

0.40

0.30

-0.20

|

0.03-1

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Loc^cal See: 2 of 3
Total Blocks: 459.269
Active Bocks: 459.269

2319000

r

2321000

West

r

2323000

East

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 44 of 80

-------
C02 Saturation at End of Simulation

15500

15563

15625

15688

15750

15813

0.80-

1

0.70

0.60

0.50

0.40

-0.30

1-0.20

J 0.10

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical Sfcce: 2 of 3
Total Bocks: 459.269
Active Bocks: 459.269

2319000

2321000

West

2323000

East

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 45 of 80

-------
Figure 29 shows the surface injection rate, bottom hole pressures, and surface pressures over the
injection period—and the period of density drift after injection ceases. The bottomhole pressure
increases the most as the injection rate ends, reaching a maximum pressure of 13,337 psig, at the
end of injection. This buildup of 2,362 psig keeps the bottomhole pressure below the fracture
pressure of 13,652 psig. The maximum surface pressure associated with the maximum bottomhole
pressure reached is 6,095 psig, well below the maximum allowable 7,937 psig per the TRRC UIC
permit application for this well. Bottomhole and wellhead pressures are provided in Table 6.

2,000,000









16,000
14,000
12,000

10,000 J

v>
v>

8,000 §
5,000 (jq"
4,000
2,000









J., /







,





_ 1,500,000
-a
>

jn 1,250,000
0)

4-»

£ 1,000,000

£
o

y 750,000

'E

— 500,000
250,000
0

C

f











v	











	















































5 10 15 20

Time (years)



Gas Rate (scf/d) BHP (psig) WHP(psig) — — — BHP Constraint (psig) ——

— WHP Constraint (psig)



Figure 29-Well Injection Rate and Bottomhole and Surface Pressures Over Time

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 46 of 80

-------
Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection

Time from Start of Injection
(years)

BHP (psig)

WHP (psig)

0

10,975

-

10

13,311

6,073

12 (End of Inj.)

13,337

6,095

20

11,029

-

22 (End of Model)

11,013

-

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 47 of 80

-------
SECTION 3 - DELINEATION OF MONITORING AREA

This section discusses the delineation of both the maximum monitoring area (MMA) and active
monitoring area (AMA) as described in 40 CFR §98.448(a)(1).

3.1 Maximum Monitoring Area

The MMA is defined as equal to or greater than the area expected to contain the free-phase CO2
plume until the plume has stabilized, plus an all-around buffer zone of at least one half mile.
Numerical simulation was used to predict the size and drift of the plume. With CMG's GEM software
package, reservoir modeling was used to determine the areal extent and density drift of the plume.
The model considers the following:

•	Offset well logs to estimate geologic properties

•	Petrophysical analysis to calculate the heterogeneity of the rock

•	Geological interpretations to determine faulting and geologic structure

•	Offset injection history to predict the density drift of the plume adequately

Ozona's expected gas composition was used in the model. The injectate is estimated at a molar
composition of 98.2% CO2 and 1.8% of other constituents. The StarTex Pawnee Treating Facility has
been in stable operations for many years. Ozona believes the gas analysis provided in Table 1 is an
accurate representation of the injectate. In the future, if the actual gas analysis varies materially
from the injectate composition herein, an update to this MRV plan will be submitted to the GHGRP.
As discussed in Section 2, the gas will be injected into the Sligo Formation. The geomodel was
created based on the rock properties of the Sligo.

The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of
3% gas saturation was used to determine the boundary of the plume. When injection ceases in Year
12, the area expanse of the plume will be approximately 270 acres. The maximum distance between
the wellbore and the edge of the plume is approximately 0.42 mi to the west. After 10 additional
years of density drift, the areal extent of the plume is 303 acres with a maximum distance to the
edge of the plume of approximately 0.45 mi to the west. Since the plume shape is relatively circular,
the maximum distance from the injection well after density drift was used to define the circular
boundary of the MMA. The AMA and the MMA have similar areas of influence, with the AMA being
only marginally smaller than the MMA. Therefore, Ozona will set the AMA equal to the MMA as the
basis for the area extent of the monitoring program.

This is shown in Figure 30 with the plume boundary at the end of injection, the stabilized plume
boundary, and the MMA. The MMA boundary represents the stabilized plume boundary after 10
years of density drift plus an all-around buffer zone of one half mile.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 48 of 80

-------
l>'N»4l Unit *4
lUiimum Woiiiloiim) Aim

0/o«w CCS UC
•»* county, ix

t» Minify 'O. | Of.* I .V ¦''),'» | *p
-------
3.2 Active Monitoring Area

The AMA was initially set equal to the expected total injection period of 12-years. The AMA was
analyzed by superimposing the area based on a one-half mile buffer around the anticipated plume
location after 12 years of injection (2037), with the area of the projected free-phase CO2 plume at
five additional years (2042). In this case, as shown in Figure 31, the plume boundary in 2042 is within
the plume in 2037 plus the one-half mile buffer. Since the AMA boundary is only slightly smaller
than the MMA boundary, Ozona will define the AMA to be equal to the MMA. By 2037, Ozona will
submit a revised MRV plan to provide an updated AMA and MMA.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 50 of 80

-------
Figure 31 - Active Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 51 of 80

-------
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE

This section identifies and discusses the potential pathways within the MMA for CO2 to reach the
surface and is summarized in Table 7. Also included are the likelihood, magnitude, and timing of
such potential leakage. The potential leakage pathways are:

•	Surface equipment

•	Existing wells within the MMA

•	Faults and fractures

•	Upper confining layer

•	Natural or induced seismicity

Table 7 - Potential Leakage Pathway Risk Assessment

Potential Leakage
Pathway

Likelihood



Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low

Low. Automated systems
will detect leaks and
execute shut-down
procedures.

During active
injection period.
Thereafter the well
will be plugged.

Existing wells within
the MMA

Unlikely. One artificial
penetration was drilled into
the injection interval. This
well has been properly
plugged and abandoned.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Faults and fractures

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Upper confining zone

Unlikely. The lateral
continuity of the UCZ
consisting primarily of the
Pearsall Formation which is
over 500 ft thick is
recognized as a very
competent seal.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Natural or induced
seismicity

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of C02 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

1 - UCZ is defined as the upper confining zone.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 52 of 80

-------
Magnitude Assessment Description

Low - catergorized as little to no impact to safety, health and the environment and the costs to mitigate

are minimal.	

Medium - potential risks to the USDW and for surface releases does exist, but circumstances can be

	easily remediated.	

High - dangerto the USDW and significant surface release may exist, and if occurs this would require
	significant costs to remediate.	

4.1 Leakage from Surface Equipment

The Pawnee Treating Facility and O'Neal No. 4 are designed for separating, transporting, and
injecting TAG, primarily consisting of CO2, in a manner to ensure safety to the public, the employees,
and the environment. The mechanical aspects of this are noted in Table 8 and Figure 32. The
facilities have been designed to minimize leakage and failure points, following applicable National
Association of Corrosion Engineers (NACE) and American Petroleum Institute (API) applicable
standards and practices. As the TAG stream contains H2S, monitors installed for H2S detection will
also indicate the presence of CO2. These monitors will be installed at key locations around the
facility and the O'Neal No. 4 location. These devices will be continuously monitored by the
Supervisory Control and Data Acquisition (SCADA) system and will alarm at set points determined
by the facility's Health, Safety and Environment (HS&E) Director, consistent with Occupational
Safety and Health Administration (OSHA) requirements. The facility will set the detection and alarm
states for personnel at 10 ppm and at 40 ppm for initiating Emergency Shutdown. Key monitoring
points and parameters are also provided in Table 8.

The facilities will incorporate important safety equipment to ensure reliable and safe operations. In
addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-pressure
shutoff settings to isolate the facility, the O'Neal No. 4, and other components, StarTex has a flare
stackto safely handle the TAG when a depressuring event occurs. These facilities will be constructed
in the coming months. The exact location of this equipment is not yet known, but it will be installed
in accordance with applicable engineering and safety standards.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 53 of 80

-------
Table 8 - Summary of TAG Monitors and Equipment

Device

Location

Set Point

H2S Monitors (1-4)

O'Neal No. 4 wellsite

10 ppm High Alarm
40 ppm Emergency Shutdown

H2S Monitors (5-8)

In-Plant Monitors

10 ppm High Alarm
40 ppm Emergency Shutdown

Flare Stack

Plant Site Perimeter

N/A

AGI Flowmeter

In-Plant (downstream of
the Amine Unit)

Calibrated per API specifications

Emergency Shutdown

In-Plant Monitors

40 ppm Facility Shutdown

Emergency Shutdown

O'Neal No. 4 wellsite

40 ppm Facility Shutdown

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 54 of 80

-------
With the continuous air monitoring at the facility and the well site, a release of CO2 would be quickly
identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The CO2 injected into the O'Neal No. 4 is from the amine
unit at the Pawnee Treating Facility. If any leakage were to be detected, the volume of CO2 released
would be quantified based on the operating conditions at the time of release, as stated in Section 7,
in accordance with 40 CFR §98.448(a)(5). Ozona concludes that the leakage of CO2 through the
surface equipment is unlikely.

4.2 Leakage Through Existing Wells Within the MMA

The O'Neal No. 4 is engineered to prevent migration from the injection interval to the surface
through a special casing and cementing design as depicted in the schematic provided in Figure 32.
Mechanical integrity tests (MITs), required under Statewide Rule (SWR) §3.46 [40 CFR §146.23
(b)(3)], will take place every 5 years to verify that the well and wellhead can contain the appropriate
operating pressures. If the MIT were to indicate a leak, the well would be isolated and the leak
mitigated to prevent leakage of the injectate to the atmosphere.

A map of all oil and gas wells within the MMA is shown in Figure 33. Figure 34 is a map of all the oil
and gas wells that penetrate the MMA's gross injection zone. Only one well penetrated the MMA's
gross injection zone. This well was non-productive and has been plugged and abandoned in
accordance with TRRC requirements. A summary table of all oil and gas wells within the MMA is
provided in Appendix B-l.

This table in Appendix B-l provides the total depth (TD) of all wells within the MMA. The wells that
are shallower and do not penetrate the injection zone are separated by the Pearsall Formation with
a gross thickness of 535 ft. The Pine Island Shale comprises approximately 130 ft of this interval as
discussed in Section 2.2.2 and provides a competent regional seal—making vertical migration of
fluids above the injection zone unlikely.

The shallower offset hydrocarbon wells within the MMA will also serve as above zone monitoring
wells. Should any of the sequestered volumes migrate vertically, they would potentially enter the
shallower hydrocarbon reservoir. Regular sampling and analysis is performed on the produced
hydrocarbons. If a material difference in the quantity of CO2 in the sample occurs indicating a
potential migration of injectate from the Sligo Formation, Ozona would investigate and develop a
mitigation plan. This may include reducing the injection rate or shutting in the well. Based on the
investigation, the appropriate equation in Section 7 would be used to make any adjustments to the
reported volumes.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 55 of 80

-------
'P.

0

C2J—

(4>

(5>5

L I

SSSV

CasingiTubing Information

Label



2

a

4

E

Type

Coa&mIH



Hamml

PtadusBun LlMt

Tufcinfl

OD

-

1Q-3W

7-5.-S"

5" (new)

5" i.oidi

2-3'8"

D

-

9.760"

5.625"

•A-276"

4.276"

1.867"

Drift ID

-

9.504"

6.500*

¦4.151"

4-151"

1.773"

COD

-

11.750"

B.500"

5.553"

5-553"

3.063"

Weight

-

555 tv-t

39.0 lth"t

18.0 Itrft

18-0 bit

5 .8 bit

Grade

-

3-95

CY-95

F-110

Q-125

L-90

Hole
Size

MIA

14-3/4*

9-1."2*

HJA

6-1 or

M'A

Depth
S#1

Driven to
Refusa

3,510'

15.340"

Top: 0*
Bottom: 14,030

Top: 14,089'
Bottom 16,101"

15,720'

Cement

M'A

Lead: 1,125 sks

HLC
Tal: 350 s*5 H

Lead: 575 sfcs
50:50 Paz H
Tail: 400 5*5 H

Lead: 650 sits
50:50 PozsH
Tall; 110 sfcs CO2
Res. Sfrurry

200 «s Premium

WA

TOC

HM

Surface

7359'

Surface

3urface

MM

%
EXC-frtG







Lead: 10%
Tail: 0%

-

M'A

\

Top of Intermec ate I-errer: g 7.2-E9



P>ftjrd Cement arB^Jx-atert

Top of Corrosion Resistant Cemenfc 13,300"
Edwards Perforations g- 13-,525' - 13-8*11 squeezed!

W- -
W^7-

CO.;-Resatar; Permanent Packer 15,700'

Do«nho»-e Check. Vafve

Re-Perforate Initial Production Zone >gj 15.S7-A' - 16,Q£.5"
Injection Interval @ 15,874' - S 6,056'

(4>

TD@tS.1Dr

0]

LONQUIST

SEQUESTRATION L

Ozona CCS

Country: USA

API No: 42-025-32658

C02 Injection Well
Proposed Well Design - O'Neal Gas Unit No. 4

State/Province: Texas

Field: TBD

County/Parish: Bee County

Well Type/Status: Proposes

Texas License F-5652

Location: 28.0031807, -35.0017001

Project No: LSI 90

Date: 10/13/2023

12912 mi Courtrj Evd Ste -2110
Austto, Texas 73738
Tfel: 512.732.9812
=ar 512.732.9S16

Drawn: Joseph LovreweB

Reviewed: David Lytle

Approved: David Lytle

Rev No: Q

Notes:

Figure 32 - O'Neal No. 4 Wellbore Schematic

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 56 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 58 of 80

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4.2.1 Future Drilling

Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations have proven to date to be nonproductive in this area, and therefore Ozona does not see
this as a risk. This is supported by a review of the TRRC Rule 13 (Casing, Cementing, Drilling, Well
Control, and Completion Requirements), 16TAC §3.13. The Sligo is not among the formations listed
for which operators in Bee County and District 2 (where the O'Neal No. 4 is located) are required to
comply with TRCC Rule 13; therefore, the TRRC does not believe there are productive horizons
below the Sligo. The O'Neal No. 4 drilling permit is provided in Appendix A-2.

4.2.2 Groundwater Wells

The results of a groundwater well search found five wells within the MMA, as identified by the Texas
Water Development Board as shown in Figure 35 and in tabular form in Appendix B-2.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 59 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 60 of 80

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The surface, intermediate, and production casings of the O'Neal No. 4, as shown in Figure 32, are
designed to protect the shallow freshwater aquifers, consistent with applicable TRRC regulations,
and the GAU letter issued for this location is provided in Appendix A-l. The wellbore casings and
compatible cements prevent CO2 leakage to the surface along the borehole. Ozona concludes that
leakage of the sequestered CO2 to the groundwater wells is unlikely.

4.3	Leakage Through Faults and Fractures

Detailed mapping of openhole logs surrounding the O'Neal No. 4 did not identify any faulting within
either the Pearsall orSligo sections. However, there is a general lack of deep penetrators within the
area that limits the amount of openhole coverage available.

The majority of the published literature suggests that faulting near the project area is restricted to
the shallower, overlying Cenozoic section, as shown in Figure 9, with shallow faults dying out before
reaching the Pearsall Formation. One source interpreted the potential for faulting to the south
(Swanson et al., 2016). The potential fault is depicted in Figure 8 relative to the location of the
O'Neal No. 4. According to the map, the interpreted fault lies approximately 4.25 mi south-
southeast of the well and approximately 3.9 mi south-southeast of the stabilized plume extent in
the year 2047. In the unlikely scenario in which the injection plume or pressure front reaches the
potential fault, and the potential fault was to act as a transmissive pathway, the upper confining
Pearsall shale contains sufficient thickness and petrophysical properties required to confine and
protect injectates from leaking outside of the permitted injection zone.

Section 2.1.2 discusses regional structure and faulting, and Section 2.3 covers local structure, for
additional material relevant to this topic.

4.4	Leakage Through the Upper Confining Zone

The Sligo injection zone has competent sealing intervals present above and below the targeted
carbonate sequence of the Sligo section. The overlying Pine Island shale member of the Pearsall
Formation is approximately 130 ft thick at the O'Neal No. 4. Above this confining unit, the Cow
Creek Limestone, Cow Creek shale, and Bexar Shale Members of the Pearsall Formation will act as
additional confinement between the injection interval and the USDW. The USDW lies well above
the sealing properties of the formations outlined above, making stratigraphic migration of fluids into
the USDW highly unlikely. The petrophysical properties of the lower Sligo and Hosston Formations
make these ideal for lower confinement. The low porosity and permeability of these underlying
formations minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injectate to the in situ reservoir fluid makes migration below the lower confining layer
unlikely.

4.5	Leakage from Natural or Induced Seismicitv

The O'Neal No. 4 is located in an area of the Gulf of Mexico considered to be active from a seismic
perspective. Therefore, the Bureau of Economic Geology's TexNet (from 2017 to present) and
USGS's Advanced National Seismic System (from 1971 to present) databases were reviewed to

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 61 of 80

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identify any recorded seismic events within 25 kilometer (km) of the O'Neal No. 4.

The investigation identified a multitude of seismic events within the 25 km search radius; however,
the magnitude of most of the events was below 2.5. The nearest seismic event with a recorded
magnitude of 3.0 or greater was measured approximately 5.6 km northwest of the O'Neal No. 4 at
a depth of 5 km. The results of the investigation are plotted on the map provided in Figure 36
relative to the O'Neal No. 4 and the 25-km search radius.

The Facility will have operating procedures and set points programmed into the control and SCADA
systems to ensure operating pressures are maintained below the fracture gradient of the injection
and confining intervals, thus avoiding the potential for inducing seismicity.

Given the seismic activity in the area, Ozona will closely monitor nearby TexNet station EF71 for
activity and any corresponding irregularities in the operating pressures of O'Neal No. 4. If a seismic
event of 3.0 or greater is recorded at Station EF71 or if anomalies are identified in the operating
data, Ozona will review the data and determine if any changes occurred that indicate potential
leakage. Ozona would take appropriate measures based on their findings, including limiting the
injection pressure and reducing the injection rate.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 62 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 63 of 80

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SECTION 5 - MONITORING FOR LEAKAGE

This section discusses the strategy that Ozona will employ for detecting and quantifying surface
leakage of CO2 through the pathways identified in Section 4, to meet the requirements of 40 CFR
§98.448(a)(3). As the injectate stream contains both H2S and CO2, the H2S will be a proxy for CO2
leakage and therefore the monitoring systems in place to detect H2S will also indicate a release of
CO2. Table 9 summarizes the monitoring of the following potential leakage pathways to the surface.
Monitoring will occur during the planned 12-year injection period or cessation of injection
operations, plus a proposed 10-year post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults or fractures

•	Leakage through confining seals

•	Leakage through natural or induced seismicity

Table 9 - Summary of Leakage Monitoring Methods

Leakage Pathway

Monitoring Method

Surface equipment

Fixed H2S monitors at the Plant and well site

Visual inspections

Monitor SCADA systems for the Plant and well site

Existing wells within the MMA

Monitor C02 levels in above zone producing wells

Mechanical Integrity Tests (MIT) of the AGI Well every 5 years

Visual inspections

Annual soil gas sampling near well locations that penetrate the
Upper Confining Zone within the AMA

• Leakage through
groundwater wells

Annual groundwater samples from existing water well(s)

• Leakage from future wells

Monitor drilling activity and compliance with TRRC Rule 13
Regulations

Faults and Fractures

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Upper confining zone

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Natural or induced seismicity

Monitor C02 levels in Above Zone producing wells

Monitor existing TexNet station



Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 64 of 80

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5.1 Leakage from Surface Equipment

The facility depicted in Figure 37 and the O'Neal No. 4 were designed to operate in a safe manner
to minimize the risk of an escape of CO2 and H2S. Leakage from surface equipment is unlikely and
would quickly be detected and addressed. The facility design minimizes leak points through the
equipment used, and key areas are constructed with materials that are NACE and API compliant. A
baseline atmospheric CO2 concentration will be established prior to commencing operation once
facility construction has been completed. Ambient H2S monitors will be located at the facility and
near the O'Neal No. 4 site for local alarm and are connected to the SCADA system for continuous
monitoring.

The facility and the O'Neal No. 4 are continuously monitored through automated control systems.
These monitoring points were discussed in Section 4.1. In addition, field personnel conduct routine
visual field inspections of gauges, and gas monitoring equipment. The effectiveness of the internal
and external corrosion control program is monitored through the periodic inspection of the
corrosion coupons and inspection of the cathodic protection system. These inspections and the
automated systems allow Ozona to detect and respond to any leakage situation quickly. The surface
equipment will be monitored for the injection and post-injection period. Should leakage be
detected during active injection operations, the volume of CO2 released will be calculated based on
operating conditions at the time of the event, per 40 CFR §98.448(a)(5) and §98.444(d).

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 65 of 80

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Residue Gas

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Figure 37 - O'Neal No. 4 Process Flow Diagram

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 66 of 80

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Pressures, temperatures, and flow rates through the surface equipment are continuously monitored
during operations. If a release occurred from surface equipment, the amount of CO2 released would
be quantified based on the operating conditions, including pressure, flow rate, percentage of CO2 in
the injectate, size of the leak-point opening, and duration of the leak. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7.

5.2 Leakage Through Existing and Future Wells Within the MMA

Ozona continuously monitors and collects injection volumes, pressures, and temperatures through
their SCADA systems, for the O'Neal No. 4. This data is reviewed by qualified personnel and will
follow response and reporting procedures when data exceeds acceptable performance limits. A
change of injection or annular pressure would indicate the presence of a possible leak and be
thoroughly investigated. In addition, MITs performed every 5 years, as expected by the TRRC and
UIC, would also indicate the presence of a leak. Upon a negative MIT, the well would be isolated
and investigated to develop a leak mitigation plan.

As discussed previously, TRRC Rule 13 ensures that new wells in the field are constructed with
proper materials and practices to prevent migration from the injection interval.

In addition to the fixed monitors described previously, Ozona will also establish and operate an in-
field monitoring program to detect CO2 leakage within the AMA. This would include H2S monitoring
as a proxy for CO2 at the well site and annual soil gas samples taken near any identified wells that
penetrate the injection interval within the AMA. These samples will be analyzed by a qualified third
party. Prior to commencing operation, and through the post-injection monitoring period, Ozona
will have these monitoring systems in place.

Currently, there is only one well in the MMA identified that penetrates the injection interval. This
well was plugged and abandoned in 2007. The TRRC records are provided in Appendix A-4. Ozona
will take an annual soil gas sample from this area, which will be analyzed by a third-party lab.
Additional monitoring will be added as the AMA is updated over time. In the unlikely event a leak
occurs, Ozona will quantify the leak volumes by the methodologies discussed in Section 7 and
present these results and related activities in the annual report.

Ozona will also utilize shallower producing gas wells as proxies for above-zone monitoring wells.
Production data from these wells is analyzed for monthly production statements, and therefore
would be an early indicator of any possible subsurface issues. Should any material change from
historical trends in the CO2 concentration occur, Ozona would investigate and develop a corrective
action plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is
very low, as the producing reservoir provides an ideal containment given the upper confining zone
of this reservoir has proven competent. In the unlikely event a leak occurs, Ozona would quantify
the leak per the strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443
based on the actual circumstances and include these results in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 67 of 80

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5.2.1 Groundwater Quality Monitoring

Ozona will monitor the groundwater quality above the confining interval by sampling from
groundwater wells near the O'Neal No. 4 and analyzing the samples with a third-party laboratory
on an annual basis. In the case of the O'Neal No. 4, 5 existing groundwater wells have been
identified within the AMA (Figure 38). Initial groundwater quality tests will be performed to
establish a baseline prior to commencing operations.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 68 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 69 of 80

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5.3 Leakage Through Faults, Fractures, or Confining Seals

Ozona will continuously monitorthe operations of the O'Neal No. 4 through the automated controls
and SCADA systems. Any deviation from normal operating volume and corresponding injection
pressure could indicate movement into a potential leak pathway, such as a fault or breakthrough of
the confining seal and would trigger an alert due to a change in the injection pressure. Any such
alert would be reviewed by field personnel and appropriate action would be taken, including
shutting in the well, if necessary.

Ozona will also utilize shallower producing wells as proxies for above-zone monitoring wells.
Production data is analyzed regularly for monthly production statements and therefore would be
an early indicator of any possible subsurface issues. Should any material change from historical
trends in the CO2 concentration occur, Ozona would investigate and develop a corrective action
plan. Should any CO2 migrate vertically from the Sligo Formation, the magnitude risk of this event
is very low, as the producing reservoir provides an ideal containment given the upper confining zone
has proven competent. In the unlikely event a leak occurs, Ozona would quantify the leak per the
strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443 based on the
actual circumstances.

5.4 Leakage Through Natural or Induced Seismicitv

While the likelihood of a natural or induced seismicity event is low, Ozona plans to use the nearest
TexNet seismic monitoring station, EF71, to monitor the area around the O'Neal No. 4. This station
is approximately 3 mi to the northwest, as shown in Figure 38. This is sufficient distance to allow
for accurate and detailed monitoring of the seismic activity in the area. Ozona will monitor this
station for any seismic activity, and if a seismic event of 3.0 magnitude or greater is detected, Ozona
will review the injection volumes and pressures of the O'Neal No. 4 to determine if any significant
changes have occurred that would indicate potential leakage.

Ozona will also continuously monitor operations through the SCADA system. Any deviation from
normal operating pressure and volume set points would trigger an alarm for investigation by
operations staff. Such a variance could indicate movement into a potential leak pathway, such as a
fault or breakthrough of the confining seal. Any such alert would be reviewed by field personnel
and appropriate action would be taken, including shutting in the well, if necessary

These are the two primary strategies for mitigating risks for induced seismicity. In the unlikely event
a leak occurs, Ozona will quantify the leak per the strategies discussed in Section 7, or as may be
applicable provided in 40 CFR §98.443 based on the actual circumstances.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 70 of 80

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 71 of 80

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SECTION 6 - BASELINE DETERMINATIONS

This section identifies the strategies Ozona will undertake to establish the expected baselines for
monitoring CO2 surface leakage per 40 CFR §98.448(a)(4). Ozona will use the existing SCADA
monitoring systems to identify changes from the expected performance that may indicate leakage
of injectate and calculate a corresponding amount of CO2.

6.1	Visual Inspections

Regular inspections will be conducted by field personnel at the facility and O'Neal No. 4 site. These
inspections will aid in identifying and addressing possible issues to minimize the risk of leakage. If
any issues are identified, such as vapor clouds or ice formations, corrective actions will be taken
prudently and safely to address such issues.

6.2	H2S/ CO2 Monitoring

In addition to the fixed monitors in the facility and at the wellsite, Ozona will establish and perform
an annual in-field sampling program to monitor and detect any CO2 leakage within the AMA. This
will consist of soil gas sampling near any artificial penetrations of the injection zone and sampling of
water wells. These probes have special membrane inserts that collect the gas samples over a 21-
day period. These will be analyzed by a third-party lab to be analyzed for CO2, H2S, and trace
contaminants typically found in a hydrocarbon gas stream. The lab results will be provided in the
annual report should they indicate a material variance from the baseline. Initial samples will be
taken and analyzed before the commencement of operations and will establish the baseline
reference levels.

6.3	Operational Data

Upon starting injection operations, baseline measurements of injection volumes and pressures will
be recorded. Any significant deviations over time will be analyzed for indication of leakage of
injectate and the corresponding component of CO2.

6.4	Continuous Monitoring

The total mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly,
as the injection stream for this project is near the OSHA Permissible Exposure Limit (PEL) 8-hour
Time Weighted Average (TWA) of 5,000 ppm. Direct leak surveys present a hazard to personnel due
to the presence of H2S in the gas stream. Continuous monitoring systems will trigger alarms if there
is a release. The mass of the CO2 released would be calculated based on the operating conditions,
including pressure, flow rate, percentage of CO2, size of the leak-point opening, and duration. This
method is consistent with 40 CFR §98.448(a)(5) and §98.444(d), allowing the operator to calculate
site-specific variables used in the mass balance equation.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 72 of 80

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In the case of a depressuring event, the acid gas stream will be sent to a flare stack to be safely
processed and will be reported under reporting requirements for the facility. Any such events will
be accounted for in the sequestered reporting volumes consistent with Section 7.

6.5 Groundwater Monitoring

Initial samples will be taken from groundwater wells in the area of the O'Neal No. 4 upon approval
of the MRV plan, and before commencement of CO2 injection. These samples will be analyzed and
reports prepared by a third-party laboratory testing for pH, total dissolved solids (TDS), CO2, and
volatile organic compounds (VOC). Initial samples will be taken and analyzed before the
commencement of operations and will establish the baseline reference levels. Sampling select wells
will be performed annually. In the event a material deviation in the sample analysis occurs, the
results will be provided in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 73 of 80

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SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS

BALANCE EQUATION

This section identifies how Ozona will calculate the mass of CO2 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the CO2 emissions from equipment leaks and
vented emissions of CO2 between the injection flow meter and the injection well, per 40 CFR
§98.448(a)(5).

7.1	Mass of CO2 Received

Per 40 CFR §98.443, the mass of CO2 received must be calculated using the specified CO2 received
equations "unless you follow the procedures in 40 CFR §98.444(a)(4)." The 40 CFR §98.444(a)(4)
states that "if the CO2 you receive is wholly injected and is not mixed with any other supply of CO2,
you may report the annual mass of CO2 injected that you determined following the requirements
under paragraph (b) of this section as the total annual mass of CO2 received instead of using
Equation RR-1 or RR-2 of this subpart to calculate CO2 received." The CO2 received for this injection
well is injected and not mixed with any other supply; the annual mass of CO2 injected will equal the
amount received less any amounts calculated in accordance with the equations of this section. Any
future streams would be metered separately before being combined into the calculated stream.

7.2	Mass of CO2 Injected

Per 40 CFR §98.444(b), since the flow rate of CO2 injected will be measured with a volumetric flow
meter, the total annual mass of CO2, in metric tons, will be calculated by multiplying the mass flow
by the CO2 concentration in the flow according to Equation RR-5:

C02,u = Annual CO2 mass injected (metric tons) as measured by flow meter u

Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard
conditions (standard cubic meters per quarter)

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682

Cco2,p,u = CO2 concentration measurement in flow for flow meter u in quarter p (vol. percent
CO2, expressed as a decimal fraction)

p = Quarter of the year

u = Flow meter

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 74 of 80

4

p= 1

Where:

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7.3 Mass of CO2 Produced

The O'Neal No. 4 is not part of an enhanced oil recovery project; therefore, no CO2 will be produced.
7.4 Mass of CO2 Emitted by Surface Leakage

The mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly due
to the H2S concentration in the injection stream. Direct leak surveys are dangerous and present a
hazard to personnel. Because no venting is expected to occur, the calculations would be based on
the unusual event that a blowdown is required and those emissions would be sent to a flare stack
and reported as a part of the required GHG reporting for the facility. Any leakage would be detected
and managed as an upset event. Continuous monitoring systems should trigger an alarm upon a
release of H2S and CO2. The mass of the CO2 released would be calculated for the operating
conditions, including pressure, flow rate, size of the leak-point opening, and duration of the leak.
This method is consistent with 40 CFR §98.448(a)(5), allowing the operator to calculate site-specific
variables used in the mass balance equation.

In the unlikely event that CO2 was released because of surface leakage, the mass emitted would be
calculated for each surface pathway according to methods outlined in the plan and totaled using
Equation RR-10 as follows:

CO2E = Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year
C02,x= Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting year
X = Leakage pathway

Calculation methods using equations from Subpart W will be used to calculate CO2 emissions due to
any surface leakage between the flow meter used to measure injection quantity and the injection
wellhead.

As discussed previously, the potential for pathways for all previously mentioned forms of leakage is
unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, Ozona believes the most appropriate method to quantify the mass of CO2
released will be determined on a case-by-case basis. Any mass of CO2 detected leaking to the
surface will be quantified by using industry proven engineering methods including, but not limited
to, engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling,
and history-matching of the sequestering reservoir performance, among others. In the unlikely
Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 75 of 80

X

x=l

Where:

-------
event that a leak occurs, it will be addressed, quantified, and documented within the appropriate
timeline. Any records of leakage events will be kept and stored as provided in Section 10.

7.5 Mass of CO2 Sequestered

The mass of CO2 sequestered in subsurface geologic formations will be calculated based on Equation
RR-12. Data collection for calculating the amount of CO2 sequestered in the O'Neal No. 4 will begin
once the subsurface recompletion work, and the surface facilities construction has been completed,
and subject to approval of the MRV plan. The calculation of sequestered volumes utilizes the
following equation as the O'Neal No. 4 will not actively produce oil, natural gas, or any other fluids:

C02 — C02i — C02e ~ C02pi

Where:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year

CO21 = Total annual CO2 mass injected (metric tons) in the well or group of wells covered by
this source category in the reporting year

CO2E = Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year

CO2F1 = Total annual CO2 mass emitted (metric tons) from equipment leaks and vented
emissions of CO2 from equipment located on the surface, between the flow meter used to
measure injection quantity and the injection wellhead, for which a calculation procedure is
provided in subpart W of this part.

CO2F1 will be calculated in accordance with Subpart W for reporting of GHGs. Because no venting is
expected to occur, the calculations would be based on the unusual event that a system blowdown
event occurs. Those emissions would be sent to a flare stack and reported as part of the GHG
reporting for the facility.

• Calculation methods from Subpart W will be used to calculate (Remissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 76 of 80

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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN

The O'Neal Gas Unit No. 4 is an existing natural gas well that will be recompleted as a Class II well
with corrosion-resistant materials. The Class II permit is still in process with the TRRC. Until this
permit is issued, Ozona cannot specify a date to acquire the baseline testing data. Ozona is
submitting this MRV application to the GHGRP to comply with the requirements of Subpart RR. The
MRV plan, including acquisition of baseline data, will be implemented upon receiving EPA approval.
The Annual Subpart RR Report will be filed on March 31 of the year following the reporting year.

Table 10 - Baseline Sampling Schedule

Sampling Location

Estimated Date

Comments

Fixed H2S/CO2 Monitors

Oct. 1, 2024

Baseline readings will be
established during
commissioning activities.

Soil gas sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Water well sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Notes:

•	Above dates are estimates subject to adjustment based on actual regulatory
approval dates and facilities construction timelines.

•	All baseline sampling will be performed prior to the start of recording data for
reporting under this MRV.

•	Commissioning activities include installation of surface facilities, including flowline,
compressors, manifolds, etc.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 77 of 80

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SECTION 9 - QUALITY ASSURANCE

This section identifies how Ozona plans to manage quality assurance and control to meet the

requirements of 40 CFR §98.444.

9.1	Monitoring QA/QC

CO2 Injected

•	The flow rate of the CO2 being injected will be measured with a volumetric flow meter,
consistent with API standards. These flow rates will be compiled quarterly.

•	The composition of the injectate stream will be measured upstream of the volumetric flow
meter with a continuous gas composition analyzer or representative sampling consistent
with API standards.

•	The gas composition measurements of the injected stream will be averaged quarterly.

•	The CO2 measurement equipment will be calibrated per the requirements of 40 CFR
§98.444(e) and §98.3(i).

CO2 Emissions from Leaks and Vented Emissions

•	Gas monitors at the facility and O'Neal No. 4 will be operated continuously, except for
maintenance and calibration.

•	Gas monitors will be calibrated according to the requirements of 40 CFR §98.444(e) and
§98.3(i).

•	Calculation methods from Subpart W will be used to calculate CChemissionsfrom equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Measurement Devices

•	Flow meters will be continuously operated except for maintenance and calibration.

•	Flow meters will be calibrated according to 40 CFR §98.3(i).

•	Flow meters will be operated and maintained in accordance with applicable standards as
published by a consensus-based standards organization.

All measured volumes of CO2 will be converted to standard cubic meters at a temperature of 60°F

and an absolute pressure of 1 atmosphere.

9.2	Missing Data

In accordance with 40 CFR §98.445, Ozona will use the following procedures to estimate missing

data if unable to collect the data needed for the mass balance calculations:

•	If a quarterly quantity of CO2 injected is missing, the amount will be estimated using a
representative quantity of CO2 injected from the nearest previous period at a similar
injection pressure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 78 of 80

-------
• Fugitive CO2 emissions from equipment leaks from facility surface equipment will be
estimated and reported per the procedures specified in Subpart W of 40 CFR §98.

9.3 MRV Plan Revisions

If any changes outlined in 40 CFR §98.448(d) occur, Ozona will revise and submit an amended MRV
plan within 180 days to the Administrator for approval.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 79 of 80

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SECTION 10 - RECORDS RETENTION

Ozona will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
3 years and include the following:

•	Quarterly records of the CO2 injected

o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the CO2 stream

•	Annual records of the information used to calculate the CO2 emitted by surface leakage from
leakage pathways.

•	Annual records of the information used to calculate CO2 emitted from equipment leaks and
vented emissions of CO2 from equipment located on the surface, between the flow meter
used to measure injection quantity and the injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 80 of 80

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APPENDICES
APPENDIX A - O'Neal No. 4 TRRC FORMS

APPENDIX A-l: GAU GROUNDWATER PROTECTION DETERMINATION

APPENDIX A-2: DRILLING PERMIT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

APPENDIX A-3: COMPLETION REPORT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

•	MINI FRACTURE REPORT

APPENDIX A-4: API 42-025-30388 CHARLIE C. OVERBY GU PLUGGING RECORDS

-------
APPENDIX B - AREA OF REVIEW

APPENDIX B-l: OIL AND GAS WELLS WITHIN THE MMA LIST

APPENDIX B-2: WATER WELLS WITHIN THE MMA LIST

-------
Request for Additional Information: O'Neal Gas Unit Well No. 4

August 7, 2024

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

1.

N/A

N/A

We recommend adding a process flow diagram (with locations of
flow meters that will be used for subpart RR) to illustrate the path
of CO2 at the facility.

A process flow diagram has been added in Section 5.1.

2.

10



"Ozona will file an application for a separate Facility ID No. under
Subpart RR for its sequestration assets."

Please clarify this statement. E.g., does Ozona intend to change the
facility ID number associated with this MRV plan, or is this referring
to other sequestration?

This MRV plan is reporting under GHGRP ID No. 587021.

3.

7.2

72

"COco2,P,u = Quarterly CO2 concentration measurement in flow for
flow meter u in quarter p (vol. percent CO2, expressed as a decimal
fraction)"

Per 40 CFR 98.443(C)(2), this variable should be "COco2,P,u = CO2
concentration measurement in flow for flow meter u in quarter p
(vol. percent CO2, expressed as a decimal fraction)." Equations and
variables cannot be modified from the regulations. Please revise
this section and ensure that all equations listed are consistent with
the text in 40 CFR 98.443.

The definition has been edited to be consistent with 40 CFR
98.443(C)(2).

1

-------
@)zona

Carbon Capture & Sequestration

Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
O'Neal Gas Unit Well No. 4

Bee County, TX

Prepared for Ozona CCS, LLC
San Antonio, TX

By

Lonquist Sequestration, LLC
Austin, TX

Version 2.0
January 2024

LONQUIST

SEQUESTRATION LLC

H

-------
INTRODUCTION

Ozona CCS, LLC (Ozona) has a pending Class II acid gas injection (AGI) permit application with the
Texas Railroad Commission (TRRC), which was submitted in September of 2023 for its O'Neal Gas
Unit Well No. 4 (O'Neal No. 4), API No. 42-025-32658. Granting of this application would
authorize Ozona to inject up to 1.5 million standard cubic feet per day (MMscf/D) of treated acid
gas (TAG) into the Sligo Formation at a depth of 15,874 feet (ft) to 16,056 ft, with a maximum
allowable surface pressure of 7,920 pounds per square inch gauge (psig). The TAG for this AGI
well is associated with StarTex's Pawnee Treating Facility, located in a rural area of Bee County,
Texas, approximately 2.0 miles (mi) south of Pawnee, Texas, as shown in Figure 1.



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Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4

Subpart RR MRV Plan - O'Neal No. 4

Page 2 of 78

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Ozona is submitting this Monitoring, Reporting, and Verification (MRV) plan to the EPA for
approval under Title 40, U.S. Code of Federal Regulations (40 CFR) 98.440(a), Subpart RR, of the
Greenhouse Gas Reporting Program (GHGRP). In addition to submitting this MRV plan to the
EPA, Ozona has applied to the TRRC for the O'Neal GU No. 4's Class II permit. Ozona plans to
inject TAG for approximately 12 years. Table 1 shows the expected composition of the gas stream
to be sequestered from the nearby treating facility.

Table 1 - Expected TAG Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

Subpart RR MRV Plan - O'Neal No. 4

Page 3 of 78

-------
ACRONYMS AND ABBREVIATIONS

AMA
BCF
CH4
CMG

C02
E

EOS

EPA

ESD

FG

ft

GAPI

GAU

GEM

GHG

GHGRP

GL

H2S

JPHIE

mD

mi

MIT

MM

MMA

MCF

MMcf

MMscf

Subpart RR MRV Plan - O'Neal No. 4

Active Monitoring Area
Billion Cubic Feet
Methane

Computer Modelling Group, Ltd.

Carbon Dioxide (may also refer to other carbon

oxides)

East

Equation of State
Environmental Protection Agency
Emergency Shutdown
Fracture Gradient
Foot (Feet)

Gamma Units of the American Petroleum Institute
Groundwater Advisory Unit
Computer Modelling Group's GEM 2023.2
Greenhouse Gas

Greenhouse Gas Reporting Program
Ground Level Elevation
Hydrogen Sulfide

Effective Porosity (corrected for clay content)

Millidarcy

Mile(s)

Mechanical Integrity Test
Million

Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet

Page 4 of 78

-------
Mscf/D	Thousand Standard Cubic Feet per Day

MMscf/D	Million Standard Cubic Feet per Day

MRV	Monitoring, Reporting, and Verification

v	Poisson's Ratio

N	North

NW	Northwest

OBG	Overburden Gradient

PG	Pore Gradient

pH	Scale of Acidity

ppm	Parts per Million

psi	Pounds per Square Inch

psig	Pounds per Square Inch Gauge

S	South

SE	Southeast

SF	Safety Factor

SWD	Saltwater Disposal

TAC	Texas Administrative Code

TAG	Treated Acid Gas

TOC	Total Organic Carbon

TRRC	Texas Railroad Commission

UIC	Underground Injection Control

USDW	Underground Source of Drinking Water

W	West

Subpart RR MRV Plan - O'Neal No. 4

Page 5 of 78

-------
TABLE OF CONTENTS

INTRODUCTION	2

ACRONYMS AND ABBREVIATIONS	4

SECTION 1 - UIC INFORMATION	10

1.1	Underground Injection Control Permit Class: Class II	10

1.2	UIC Well Identification Number	10

1.3	Facility Address	10

SECTION 2 - PROJECT DESCRIPTION	11

2.1	Regional Geology	11

2.1.1	Geologic Setting and Depositional Environment	13

2.1.2	Regional Structure and Faulting	15

2.2	Site Characterization	17

2.2.1	Stratigraphy and Lithologic Characteristics	17

2.2.2	Upper Confining Interval - Pearsall Formation	19

2.2.3	Injection Interval - Upper Sligo Formation	21

2.2.4	Formation Fluid	23

2.2.5	Fracture Pressure Gradient	24

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations	25

2.3	Local Structure	25

2.4	Injection and Confinement Summary	30

2.5	Groundwater Hydrology	30

2.6	References	34

2.7	Description of the Injection Process	35

2.7.1 Current Operations	35

2.8	Reservoir Characterization Modeling	35

2.8.1 Simulation Modeling	39

SECTION 3 - DELINEATION OF MONITORING AREA	48

3.1	Maximum Monitoring Area	48

3.2	Active Monitoring Area	50

SECTION 4- POTENTIAL PATHWAYS FOR LEAKAGE	52

4.1	Leakage from Surface Equipment	53

4.2	Leakage Through Existing Wells Within the MMA	55

4.2.1	Future Drilling	59

4.2.2	Groundwater Wells	59

4.3	Leakage Through Faults and Fractures	61

4.4	Leakage Through the Upper Confining Zone	61

4.5	Leakage from Natural or Induced Seismicity	61

SECTION 5 - MONITORING FOR LEAKAGE	64

5.1	Leakage from Surface Equipment	65

5.2	Leakage Through Existing and Future Wells Within the MMA	65

5.2.1 Groundwater Quality Monitoring	66

5.3	Leakage Through Faults, Fractures, or Confining Seals	68

Subpart RR MRV Plan - O'Neal No. 4

Page 6 of 78

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5.4 Leakage Through Natural or Induced Seismicity	68

SECTION 6 - BASELINE DETERMINATIONS	70

6.1	Visual Inspections	70

6.2	H2S/ CO2 Monitoring	70

6.3	Operational Data	70

6.4	Continuous Monitoring	70

6.5	Groundwater Monitoring	71

SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION	72

7.1	Mass of CO2 Received	72

7.2	Mass of CO2 Injected	72

7.3	Mass of CO2 Produced	73

7.4	Mass of CO2 Emitted by Surface Leakage	73

7.5	Mass of CO2 Sequestered	74

SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN	75

SECTION 9 - QUALITY ASSURANCE	76

9.1	Monitoring QA/QC	76

9.2	Missing Data	76

9.3	MRV Plan Revisions	77

SECTION 10 - RECORDS RETENTION	78

Figures

Figure 1 - Location of StarTex's Pawnee Treating Facility and the O'Neal No. 4	2

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-

Ashby etal., 2012)	11

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby

etal., 2012)	12

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The
proposed injection interval is shaded light blue and proposed confining intervals are shaded light

yellow (modified from Bebout et al., 1981)	13

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981)	14

Figure 6-Generalized northwest to southeast schematic cross section of the Trinity Group, south
Texas (the line of section depicted in Figure 5). The red star and line represent the approximate

location of the O'Neal No. 4 (modified from Kirkland et al., 1987)	 15

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated
porosity and permeability values of typical facies (modified from Talbert and Atchley, 2000).. 15
Figure 8 - Structural features and fault zones near the proposed injection site. The red star
represents the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

	16

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through
Word field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).. 17

Subpart RR MRV Plan - O'Neal No. 4

Page 7 of 78

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Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted	18

Figure 11 - Porosity-Permeability Crossplot of Pearsall Formation Crushed Rock Core Data

(Swanson et al., 2016)	20

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map. The
red star represents the approximate location of the O'Neal No. 4 (modified from Bebout et al.,

1981)	20

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)	21

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded

green >0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms	22

Figure 15 - Offset Wells Used for Formation Fluid Characterization	24

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

	25

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the

location of the O'Neal No. 4	27

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the

locator map	28

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on

the locator map	29

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of

the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	31

Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006)	32

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	32

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	33

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model	37

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection)	41

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)	42

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

	44

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End

of Simulation)	45

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time	46

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum

Monitoring Area	49

Figure 31 - Active Monitoring Area	51

Figure 32 - O'Neal No. 4 Wellbore Schematic	56

Figure 33 - All Oil and Gas Wells Within the MMA	57

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA	58

Figure 35 - Groundwater Wells Within the MMA	60

Figure 36 - 25-km Seismicity Review	63

Figure 37 - Groundwater Wells	67

Subpart RR MRV Plan - O'Neal No. 4

Page 8 of 78

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Figure 38 - Seismic Events and Monitoring Station

69

Tables

Table 1 - Expected TAG Composition	3

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo

oil-field brine samples	24

Table 3 - Gas Composition	35

Table 4 - Modeled Injectate Composition	36

Table 5 - GEM Model Layer Package Properties	38

Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection	47

Table 7 - Potential Leakage Pathway Risk Assessment	52

Table 8 - Summary of TAG Monitors and Equipment	54

Table 9 - Summary of Leakage Monitoring Methods	64

Table 10- Baseline Sampling Schedule	75

Appendices

Appendix A - TRRC O'Neal Gas Unit Well No. 4 Forms

Appendix A-l - GAU Groundwater Protection Determination
Appendix A-2 - Drilling Permit
Appendix A-3 - Completion Report
Appendix A-4 - Plugging Records

Appendix B - Area of Review

Appendix B-l - Oil and Gas Wells Within the MMA List
Appendix B-2 - Water Wells Within the MMA List

Subpart RR MRV Plan - O'Neal No. 4

Page 9 of 78

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SECTION 1 - UIC INFORMATION

This section contains key information regarding the Underground Injection Control (UIC) Permit.

1.1	Underground Injection Control Permit Class: Class II

The TRRC regulates oil and gas activities in Texas and has primacy to implement the Underground
Injection Control (UIC) Class II program. The TRRC classifies the O'Neal No. 4 as a UIC Class II well.
Ozona has applied for a Class II permit for the O'Neal No. 4 under TRRC Rules 36 (Oil, Gas, or
Geothermal Resource Operation in Hydrogen Sulfide Areas) and 46 (Fluid Injection into Productive
Reservoirs).

1.2	UIC Well Identification Number

•	O'Neal No. 4, API No. 42-025-32658, UIC No. 56819

1.3	Facility Address

•	Facility Name: StarTex Pawnee Treating Facility

•	Operator: StarTex Field Services, LLC

•	Coordinates in North American Datum for 1983 (NAD 83) for this facility:

o Latitude: 28.622211
o Longitude: -97.992772

•	Greenhouse Gas Reporting Program ID Information:

o StarTex's gathering and boosting assets are currently reporting under Subpart W

via Facility ID No. 568661.
o Upon sequestration of CO2 StarTex will also report in accordance with Subpart

PP requirements using the same Facility ID No.
o Ozona will file an application for a separate Facility ID No. under Subpart RR for its
sequestration assets.

Subpart RR MRV Plan - O'Neal No. 4

Page 10 of 78

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SECTION 2 - PROJECT DESCRIPTION

This section discusses the geologic setting, planned injection process and volumes, and reservoir
and plume modeling performed for the O'Neal No. 4 well.

The O'Neal No. 4 will inject the TAG stream into the Sligo Formation at a depth of 15,874 ft to
16,056 ft, and approximately 14,924 ft below the base of the Underground Source of Drinking
Water (USDW). Therefore, the well and the facility are designed to protect against the leakage
out of the injection interval, to protect against contaminating other subsurface formations, and—
most critically—to prevent surface releases.

2.1 Regional Geology

The O'Neal No. 4 (API No. 42-025-32658) is located in south Texas within the Gulf of Mexico
Basin. The onshore portion of the Gulf of Mexico basin spans approximately 148,049,000 acres
and encompasses portions of Texas, Louisiana, Mississippi, Alabama, Arkansas, Missouri,
Kentucky, Tennessee, Florida, and Georgia to the state-waters boundary of the United States
(Roberts-Ashby et al., 2012). The location of the O'Neal No. 4 is designated by the red star in
Figure 2, relative to the present coastal extent and major structural features of the basin.

Figure 2 - Structural Features of the Guif of Mexico and Locator Map (modified from Roberts-Ashby et

al., 2012)

Subpart RR MRV Plan - O'Neal No. 4

Page 11 of 78

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Figure 3 depicts a generalized stratigraphic column of the U.S. Gulf Coast, with light blue shading
signifying the proposed injection interval and green stars indicating productive formations
identified within 5 miles of the O'Neal No. 4. The injection interval is found within the Sligo
Formation, with confinement provided by the overlying Pearsall Formation and tight underlying
fades of the Lower Sligo and Hosston Formations.

System /
Series

Global
Chronostratigraphic
Units

Calabrian

Piacenzian
Zanclean

Messinian
Tortonian
Serravallian

Langhian
Burdigalian
Aquitanian

Chattian

Rupelian

Priabonian

Bartonian
Lutetian

Ypresian

Thanetian
Selandian
Danian

Maastrichtian

Campanian

Santonian
Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian
Hauterivian

Valanginian
Berriasian

North American
Chronostratigraphic
Units

Middle Mioc. Fleming Fm

Chickasawhayan

Vicksburgian

Jacksonian

Claibornian

Sabinian

Midwayan

Navarroan

Tayloran

Austinian

Eaglefordian

Woodbinian

Washitan-
Fredericksburgian

Trinitian

Nuevoleonian

Durangoan

Stratigraphic Unit

Undifferentiated

Undifferentiated

Upper Mioc.

Anahuac

Fm / Ss " i	-7 Fm

Frio Formation

^X-Catahoula
^ Fm / Rq

Vicksburg Formation

Jackson Group

Sparta Sand

Claiborne Group Cane River Fm

	Carrizo Sand

Wilcox Group

Midway Group

Navarro Group

Taylor Group

Austin Group /
Tokio Formation /
Eutaw Formation

Eagle Ford Shale

Woodbine / Tuscaloosa Fms

Washita Group
(Buda Ls)

Fredericksburg Group i
(Edwards Ls / Paluxy Fm)^

Glen Rose Ls
(Rusk/ Rodessa Fms)

Pearsall Formation |

Sligo^f

Hosston
Formation

Fm

UPPER CONFINING INTERVAL
INJECTION INTERVAL

LOWER CONFINING
INTERVAL

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roherts-Ashby et al.,

2012).

Subpart RR MRV Plan - O'Neal No. 4

Page 12 of 78

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The targeted formations of this study are located entirely within the Trinity Group, as clarified by
the detailed stratigraphic column provided in Figure 4. During this time the area of interest was
located along a broad, shallow marine carbonate platform that extended along the northern rim
of the ancestral Gulf of Mexico. The Lower Cretaceous platform spanned approximately 870 mi
from western Florida to northeastern Mexico, with a shoreline-to-basin margin that ranged
between 45 to 125 mi wide (Yurewicz et al., 1993).

-------
rock found within Cretaceous reef deposits. Deeper, basinward deposits tend to result in tighter
petrophysical properties due to a relative increase in the amount of entrained clay associated
with the heightening of the water column while moving downslope. Backreef deposits have the
potential for porosity development but tend to have low permeability due to a general lack of
wave action caused by restricted access to open water by the platform margin. Facies and
petrophysical properties of the Lower Cretaceous section are anticipated to be relatively
homogenous moving southwest-northwest along reef trend, with increased heterogeneity
moving northwest-southeast due to the orientation of the carbonate rim and its effect on
deposition and facies distributions (Yurewicz et al., 1993).

Figure 5 displays the paleogeography during deposition of the Lower Cretaceous section to
visually demonstrate the position of the O'Neal No. 4 relative to the Sligo shelf margin and updip
extents of Sligo deposition. A generalized schematic cross section of the Trinity Group is provided
in Figure 6, which nearly intersects the project area from the northwest. The schematic illustrates
the gross section thickening basinward, with primary reservoir development improving with
proximity to the reef margin. Figure 7 displays a depositional model of the Lower Cretaceous
carbonate platform to visually conceptualize depositional environments and anticipated
petrophysical properties of facies introduced above.

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the
approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981).

Subpart RR MRV Plan - O'Neal No. 4

Page 14 of 78

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Figure 6 - Generalized northwest to southeast schematic cross section of the Trinity Group, south Texas
(the line of section depicted in Figure 5). The red star and line represent the approximate location of the

O'Neal No. 4 (modified from Kirkland et al., 1987)

0=15-25
K>200

0=10-15
K=20-100

SHOAL

=2-12
K<1

BACKREEF

Windward Fairweather Wave Base

FOREREEF
W CLAY

CLAY-RICH

LEGEND

Sedimentary Structures Grains

Current Ripple
—— Flaser/Wavy Bedding

mm Laminations
—v— Mud Cracks

— Planar and Festoon Bedding
{J Burrow Clay Seam

e Ooid Q) Oyster undiff
• Peloid Bivalve imdiff.
t>Rudist undiff. § Gastropod
(g> Solitary Coral ® Echinoderm
CZ Dictyconus @ Ammonite

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated porosity and
permeability values of typical facies (modified from Talbert and Atchley, 2000).

2.1.2 Regional Structure and Faulting

The Gulf of Mexico basin was formed by crustal extension and sea-floor spreading associated
with the Mesozoic breakup of Pangea. Rifting of northwest to southeast trending transfer faults
during the Middle Jurassic lasted approximately 25 million years and resulted in variable
thickness of the transcontinental crust underlying the region. By the Lower Cretaceous time, the
general outline and morphology of the Gulf were similar to that of present-day (Galloway, 2008;

Subpart RR MRV Plan - O'Neal No. 4

Page 15 of 78

-------
Yurewicz et al., 1993). Lower Cretaceous tectonic activity was limited to regional subsidence
associated with areas of variable crustal thickness and local structuring caused by movement of
Louann Salt (Yurewicz et al., 1993). The combination of these processes resulted in the structural
development of regional arches, grabens, uplifts, embayments, salt domes, and salt basins
around the northern edge of the basin (Dennen and Hackley, 2012; Galloway, 2008). The location
of these structural features can be referenced in Figures 2 and 8 relative to the location of the
O'Neal No. 4.

The schematic dip-oriented cross section displayed in Figure 9 presents a common interpretation
of the current structural setting. Most of the published literature suggests that faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as displayed in Figure 9,
with shallow faulting dying out before reaching the Pearsall Formation. However, one source did
interpret the potential for faulting to the south (Swanson et al., 2016). The closest potential fault
is depicted in Figure 8 relative to the location of the O'Neal No. 4. According to the map, the
interpreted fault lies approximately 4.25 miles south-southeast of the well and approximately 3.9
miles south-southeast of the stabilized plume extent in the year 2047.

EXPLANATION

I

50

50
_J	

I—r

100 Kilometers

100 Miles
J	I

Uplift

Plateau

Basin

TPS boundary
Fault zone

Lower Cretaceous shelf margin
County line

Field in Edwards Limestone
associated with fault zones

O Salt structure
GOM Gulf of Mexico

Anticlinal axis; large arrow indicates
direction of plunge

Figure 8 - Structural features and fault zones near the proposed injection site. The red star represents
the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

Edwards plateau

Rio Grande
embayment

Subpart RR MRV Plan - O'Neal No. 4

Page 16 of 78

-------
NW

Published
Edwards Ls.
shelf margin

SE

Word field

1 Kilometer

I Edwards Limestone, potential reservoir
facies (shallow-water facies)

~	Pearsall Fm.

~	Sligo Formation, wedges of downslope
debris



Fault

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through Word
field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).

2.2 Site Characterization

The following section discusses site-specific geological characteristics of the O'Neal No. 4 well.
2.2.1 Stratigraphy and Lithologic Characteristics

Figure 10 depicts openhole logs from two offset wells (API No. 42-025-00473 and API No. 42-025-
31892) to the O'Neal No. 4, indicating the injection and primary upper confining zones. The
Tomasek No. 1 (API No. 42-025-00473) is located approximately 1 mi northeast of the O'Neal No.
4 and displays the shallow section from 0-8,200 ft. The Gordon No. 3 (API No. 42-025-31892) is
located approximately 1.6 mi northeast of the O'Neal No. 4 and displays a shallow section from
8,200-16,400 ft.

Subpart RR MRV Plan - O'Neal No. 4

Page 17 of 78

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AUSTIN
EAGLE_FORD

EDWARDS

COOK_MOUNTAIN

PRSL

SLGO

BB-SOUTHTEX, LLC

TOMASEK GAS UNIT 1

42025004730000

BUQW

BASE_USDW

SPARTA
WECHES_SS

QUEEN_CITY

CARRIZO
WILCOX

PIONEER NATURAL RESOURCES

A. GORDON GAS UNIT 3

42025318920000

MIDWAY

Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted

Subpart RR MRV Plan - O'Neal No. 4	Page 18 of 78

-------
2.2.2 Upper Confining Interval - Pearsall Formation

Following the deposition of the Sligo Formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
Formation throughout the region (Roberts-Ashby et al., 2012). The Pine Island Shale consists of
alternating beds of pelagic mudstone, hemipelagic mudstone, and Fe-rich dolomitic mudstone
interpreted to have been deposited along the outer ramp. This is in agreement with core data
published by Bebout and others (1981), and later by Swanson and others (2016), who identified
the presence of C. Margerelli, a nannofossil indicative of anoxic conditions. The core-derived
porosity-permeability relationship displayed in Figure 11 suggests that the permeability of the
Pine Island Shale is incredibly low and stays below 0.0001 mD, regardless of porosity (Figure 11;
Hull, 2011). This is further supported by the 2012 U.S. Geological Survey (USGS) CO2 Storage
Resource Assessment, which suggests that the Pine Island Shale contains the physical properties
required to act as a regional seal and was chosen as the upward confining interval for their
C50490108 Storage Assessment Unit (SAU) assessment of the Gulf Coast. The 2012 USGS report
also noted that the Pine Island Shale is a sufficient regional seal with as little as 50 ft of contiguous
shale development. The top of the Pearsall is encountered at a depth of 15,339 ft in the O'Neal
No. 4, with a gross thickness of 535 ft (Figure 14). The Pine Island Shale member is approximately
130 ft thick at the O'Neal No. 4 location, with deposition of additional members of the overlying
Pearsall Formation, which include the Cow Creek Limestone, Cow Creek shale, and Bexar Shale
Members (Roberts-Ashby et al., 2012; Swanson et al., 2016).

The seismic line displayed in Figure 12 runs northwest to southeast across the Stuart City reef
trend southwest of the project area. The top of the Buda, Pearsall, and Sligo Formation markers
are depicted in color to demonstrate the lateral continuity of the section near the O'Neal No. 4.
Seismic reflectors within the Pearsall Formation appear to lack deformation, suggesting
consistent deposition over the reef margin. This is in agreement with reviewed published
literature, which suggests deposition of the Pine Island Shale occurred during widespread marine
transgression (Bebout et al., 1981; Hull, 2011.; Roberts-Ashby et al., 2012, Swanson et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 19 of 78

-------
0.0001
(100 nd;

Permeability and Porosity-
Crushed Rock Data

~o
E

~ 0.00001
TO (10 nd)

-------
2.2.3 Injection Interval - Upper Sligo Formation

The Sligo Formation underlies the Pearsall Formation and is predominately composed of shelf-
edge limestones that were deposited along the Lower Cretaceous platform (Roberts-Ashby et al.,
2012). However, the Cretaceous also experienced episodic changes in sea level that resulted in
the deposition of cyclic Sligo facies that vary both spatially and within the geologic section. The
overall Sligo interval is interpreted to be a transgressive sequence occasionally interrupted by
progradational cycles that consists of porous shoaling-upward sequences that represent primary
reservoir potential within the system (Bebout et al., 1981). Facies distributions of these reef
complexes are heavily impacted by positioning relative to the margin, the height of the water
column at any given time, and the degree of energy or wave action within the system (Galloway,
2008). Figure 13 depicts an idealized environmental setting of the Lower Cretaceous platform
during deposition. Primary porosity and permeability of the upper Sligo Formation tends to
develop in high-energy sequences with normal marine conditions that are dominated by the
deposition of oolitic and skeletal grainstones.

ilSSSTON

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)

According to the 2012 USGS CO2 Storage Resource Assessment, "the average porosity in the
porous intervals of the storage reservoir decreases with depth from 9 to 16 percent" for their
C50490108 DEEP SAU assessment of the Gulf Coast (>13,000 ft). The study also reported that
"the average permeability in the storage reservoirs decreases with depth from 0.05 to 200 mD,
with a most-likely value of 8 mD" for their C50490108 DEEP SAU assessment of the Gulf Coast
(Roberts-Ashby et al., 2012).

The top of the upper Sligo is encountered at a depth of 15,874 ft in the O'Neal No. 4 with a gross
thickness of 183 ft (Figure 14). The type log displayed in Figure 14 plots effective porosity for the
confining interval and the total porosity of the injection interval, to account for the increased

Subpart RR MRV Plan - O'Neal No. 4

Page 21 of 78

-------
volume of shale (Vshale) seen in the Pearsall Formation. The porosity data was compared to the
analysis performed by Nutech to generate a permeability curve with a reasonable porosity-
permeability relationship. The permeability curve was generated utilizing the Coates
permeability equation, incorporated with a 20% irreducible brine saturation to match analysis
provided by Nutech. Petrophysical analysis of the O'Neal No. 4 indicates an average porosity of
4.6%, a maximum porosity of 15%, an average permeability of 0.16 mD, and a maximum
permeability of 3.3 mD. These curves have been extrapolated to the injection site and used to
establish reservoir characteristics in the plume model.

BB-SOUTHTEX, LLC

ONEAL GAS UNIT 4

o

42025326580000

GR

0

150

0.2

ILD

> 5 ohm 2000

K_COATES20
10	0

0.3

PHIE

>0 %

0

DPHI

0.3

> 0 %

0

Pearsall

Very Low Perm:
Pine Island Shale

Very Low Perm:
Lower Sligo
Formation

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded green
>0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms.

Subpart RR MRV Plan - O'Neal No. 4

Page 22 of 78

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2.2.4 Formation Fluid

The USGS National Produced Waters Geochemical Database version 3.0 was reviewed for
chemical analyses of Sligo oil-field brines within the state of Texas (Blondes et al., 2023). Only
two samples were identified from the Sligo Formation: one located approximately 29 mi north-
northeast in Karnes County and one located approximately 72 mi northeast in Gonzales County.
The locations of these wells are shown in Figure 15 relative to the O'Neal No. 4. A summary of
water chemistry analyses conducted on the two Texas Sligo oil-field brine samples is provided in
Table 2 (page 25).

Averages from the samples were utilized for model assumptions due to the minimal Sligo sample
availability and wide geographic spread of Sligo analysis. Total Dissolved Solids (TDS) of the
samples contain a wide range of reported values but averaged 176,470 parts per million (ppm).
Model sensitivities were established by running iterations with varying TDS values to understand
the effect of brine concentrations on plume extents. The results suggested higher density brine
values lead to smaller plumes; therefore, a value of 150,000 ppm was established in the model
for a conservative approach. If the actual formation fluid sample that will be tested during the
recompletion work produces a material difference in the plume, Ozona will submit an updated
MRV plan.

Based on the results of the investigation, in situ Sligo reservoir fluid is anticipated to contain
greater than 20,000 ppm TDS near the O'Neal No. 4, qualifying the aquifer as saline. These
analyses indicate the in situ reservoir fluid of the Sligo Formation is compatible with the proposed
injection fluids.

Subpart RR MRV Plan - O'Neal No. 4

Page 23 of 78

-------
Figure 15 - Offset Wells Used for Formation Fluid Characterization

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo oil-field

brine samples.

Measurement

Karnes County
Sample

Gonzales
County Sample

Average

Total Dissolved Solids (mg/L)

234,646

117,470

176,058

Sodium (mg/L)

51,168

27,909

39,539

Calcium (mg/L)

34,335

8,684

21,510

Chloride (mg/L)

146,500

57,811

102,156

Sample Depth (ft)

13,580 to 13,660

8,290-8,305

-

pH

5.9

8.2

7.05

2.2,5 Fracture Pressure Gradient

The fracture pressure gradient was obtained from a fracture report taken during the April 1993
Icompletion of the Sligo interval in the O'Neal No. 4. The Sligo was perforated between the
depths of 15,874 ft and 16,056 ft, with continuous monitoring during the minifrac job. The report
noted a calculated fracture gradient of 0.954 psi/ft based on an initial shut-in pressure (ISIP) of

Subpart RR MRV Plan - O'Neal No. 4

Page 24 of 78

-------
8,312 psi. A 10% safety factor was then applied to the calculated gradient, resulting in a
maximum allowed bottomhole pressure of 0.86 psi/ft. This was done to ensure that the injection
pressure would never exceed the fracture pressure of the injection zone.

2.2.6 Lower Confining Interval - Lower Sligo and Hosston Formations

The O'Neal No. 4 reaches its total depth in the lower Sligo Formation, directly below the upper
Sligo proposed injection interval. The lower Sligo is interpreted by Bebout and others (1981) to
represent the seaward extension of the low-energy lagoon and tidal-flat system of the underlying
Hosston Formation, a sequence of siliciclastics, evaporites, and dolomitic mudstone (Figure 16).
The Hosston to lower Sligo "contact" represents a gradational package with a decrease in
terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the lower Sligo. The lower Sligo consists of numerous cycles
of subtidal to supratidal carbonates deposited in a low-energy lagoon and tidal-flat system
(Bebout et al., 1981). These low permeability facies of the lower Sligo and underlying Hosston
Formation will provide lower confinement to the upper Sligo injection interval. Figure 16
illustrates the typical environmental setting forthe deposition of tidal flat facies along the Lower
Cretaceous margin. The type log displayed in Figure 14 (Section 2.2,3) illustrates that the
porosity of the lower Sligo ranges between 0-2% with permeability staying close to 0 mD.
Therefore, the petrophysicai characteristics of the lower Sligo and Hosston are ideal for
prohibiting the migration of the injection stream outside of the injection interval.

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)
2.3 Local Structure

Structures surrounding the proposed sequestration site were influenced by regional arches,
grabens, uplifts, embayments, movement of Louann Salt, and the development of carbonate reef
complexes around the northern edge of the basin. However, one potential fault was identified
in the literature within proximity and lies approximately 4.25 mi south-southeast of the well and

Subpart RR MRV Plan - O'Neal No. 4

Page 25 of 78

-------
approximately 3.9 mi south-southeast of the stabilized plume extent in the year 2062 (Swanson
et al., 2016). The location of these structural features can be referenced in Figures 2 and 8
relative to the location of the O'Neal No. 4.

A subsea true vertical depth (SSTVD) structure map on the top of the Sligo Formation is provided
in Figure 17. The map illustrates the gentle basinward dip of the Sligo from the northwest to the
southeast. The structural cross sections provided in Figures 18 and 19 (pages 28 and 29,
respectively) illustrate the structural changes encountered in moving away from the O'Neal No.
4 site. The figures also demonstrate the laterally continuous nature of the Pearsall Formation
that overlies the injection interval, with sufficient thickness and modeled petrophysical
properties to alleviate the risk of upward migration of injected fluids. Section 2.1.2, discussing
regional structure and faulting, presents a regional discussion pertinent to this topic.

Subpart RR MRV Plan - O'Neal No. 4

Page 26 of 78

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Legend
^ SHL C.I, = 200'

idwards Reef Trend
Sligo Reef Trend

1M00

o Sligo Penetration

-12M0

_

-12200

—

-12400

—

-12600

—

-12800

—

-130W

—

-13200

—

-13400

—

-moo

—

-13800

_



—

-14200

—

-14400

—

-14603

—

-14S00

—

-15000

_

-13200

—

-15400

—

-156M

—

-15SOO

-

-19000

—

-16200

—

-16400

—

-iwoo

—

-16800

—

-17000

—

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the location of the O'Neal No. 4.
Subpart RR MRV Plan - O'Neal No. 4	Page 27 of 78

-------
13300
13400
13500
13600
13700
13800
13900
14000
14100
14200
14300
14400

"TOW

14600
14700
14800

15000
15100
15200

15400
15500
15600
15700
15800
15900
16000

16100
16200
16300
16400
16500

16600
16700
16800

| | Injection Reservoir
Color Fill

ASTN

LEGFD

EDRD

PRSL

SLGO

SLGOJNJ
BASE

PRSL

Jpper Confining Zone
(Pearsall Formation)

Injection Reservoir SLGO
(Sligo Formation)

SLGOJNJ
BASE

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200

"WW

13400

13600
13700
13800
13900
TioTO"
14100
14200
14300
14400
14500
14600
14700
14800

w

15000
15100
15200
XM.
15400
15500
15600
15700
15800

imr

16000

16100
16200
16300
16400
16500
16600
16700

13700
13800
13900
14000
14100
14200
14300
14400
14500
14600
14700
14800
14900
15000
15100
15200
15300
15400
I J3BI!I
15600
15700
15800
15900

16100
16200
16300

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200
13300
13400

13600

Logged
cased
hole in
EDRD, „
DPHI
Over-
estimated

CLRS

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 28 of 78

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422973335t00
MCMORAN EX PL CO
DUUAHA N JOSE PHI NE

422973332700
SPARTAN RETRO CORP
STRIDDE OSCAR

14250
14300
14350
14400
14450
14500
14550

14300
14350
14400
14450
14500
14550
14600

14600

"14650'
14700
14750
14800
14850
14900
14950
15000
15050

14650

14700

14750
14800

14350
14900
14950
15000

15050

15100
15150
15200

15100

15150
15200
15250
15300
15350

15250
15300
15350
15400
15450
15500
15550
15600
15650

15400
15450
15500
15550
15600
i^n

15700
15750
15800
15850

15700
15750
15800
15850
15900
15950
16000
ifiren

15900

15950
16000

16050

16100
16150
16200
16250
16300
16350

16100
16150

16200

16250

16300
16350

16400
16450
16500
16550
16600
16650

16400
16450
16500
16550
16600
16650
16700
16750
16800
16850

16700
16750
16800
16850
16900
16950
17000
17050
17100

420253285800
BB-SOUiHTEX LLC
OVERB Y CMftRLI E C GA

14400
14450
14500
14550
14600
14650
14700
14750
14800
14850
14900
14950
15000
15050
15100
15150
15200
15250
15300

14450
14500
14550
14600
14650
14700
14750

14850
14900
14950
15000
15050
15100

estimated

15150
15200
15250
15300
15350
15400
15450

"T535TT
15400
15450
15500
15550
15600

15500

15550
15600
15650
15700
15750
15800
15850
15900
15950

15700

15750
15800
15850

15900
15950
16000
16050
16100
16150
16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750
16800
16850
16900
16950
17000
17050
17100
17150
17200
17250

16000
16050
16100
16150

16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750
16800
16850
16900
16950
17000
17050
17100
17150
17200
17250

KARNES

ATASCOSA

~ Injection Reservoir
Color Fill

GLRS

GLRS

PRSL

SLGO

SLGOJN
BASE

PRSL

Upper Confining Zone
(Pearsall Formation)

SLGO

Injection Reservoir
(Sligo Formation)

ASTN
LEGFD

BUDA

DLRO
EDRD

SLGO_INJ
BASE

Logged

cased

hole in

EDRD,

DPHI

Over-

16900
16950
17000
17050
171Q0

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 29 of 78

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2.4 Injection and Confinement Summary

The lithologic and petrophysical characteristics of the Sligo Formation at the O'Neal No. 4 well
location indicate that the reservoir contains the necessary thickness, porosity, and permeability to
receive the proposed injection stream. The overlying Pearsall Formation is regionally extensive at
the O'Neal No. 4 with low permeability and sufficient thickness to serve as the upper confining
interval. Beneath the injection interval, the low permeability, low porosity facies tidal flat, and
lagoonal facies of the lower Sligo and underlying Hosston Formation are unsuitable for fluid
migration and serve as the lower confining interval.

2.5 Groundwater Hydrology

Bee County falls within the boundary of the Bee Groundwater Conservation District. Only one
aquifer is identified by the Texas Water Development Board's Texas Aquifers Study near the O'Neal
No. 4 well location, the unconfined to semi-confined Gulf Coast aquifer. The Gulf Coast aquifer
parallels the Gulf of Mexico and extends across the state of Texas from the Mexican border to the
border of Louisiana (Bruun et al., 2016). The extents of the Gulf Coast aquifer are provided in Figure
20 for reference.

The Gulf Coast aquifer is a major aquifer system comprised of several individual aquifers: the Jasper,
Evangeline, and Chicot. These aquifers are composed of discontinuous clay, silt, sand, and gravel
beds that range from Miocene to Holocene in age (Figure 21, page 32). Numerous interbedded
lenses and layers of silt and clay are present within the aquifers, which can confine individual aquifers
locally. The underlying Oligocene Catahoula tuff represents the lower confining interval, but it
should be noted that the formation is prone to leaking along the base of the aquifer. However, the
Burkeville confining interval provides isolation between Jasper and Evangeline aquifers which helps
protect the shallower Evangeline and Chicot Aquifers (Bruun et al., 2016).

The schematic cross section provided in Figure 22 (page 32) runs south of the O'Neal No. 4,
illustrating the structure and stratigraphy of the aquifer system. The thickness of individual
sedimentary units within the Cenozoic section tends to thicken towards the Gulf of Mexico due to
the presence of growth faults that allow additional loading of unconsolidated sediment. The total
net sand thickness of the aquifer system ranges between 700 ft of sand in the south, to over 1,300
ft in the north, with the saturated freshwater thickness averaging 1,000 ft.

The water quality of the aquifer system varies with depth and locality but water quality generally
improves towards the central to northeastern portions of the aquifer where TDS values are less than
500 milligrams per liter (mg/L). The salinity of the Gulf Coast aquifer increases to the south, where
TDS ranges between 1,000 mg/L to more than 10,000 mg/L. The Texas Water Development Board's
Texas Aquifers Study (2016) suggests that areas associated with higher salinities are possibly
associated with saltwater intrusion likely "resulting from groundwater pumping or to brine migration
in response to oil field operations and natural flows from salt domes intruding into the aquifer"
(Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 30 of 78

-------
According to the IDS map of the Gulf Coast aquifer (Figure 23), the TDS in northern Bee County
range between 500-3,000 mg/L near the O'Neal No. 4, categorizing the aquifer as fresh to slightly
saline.

The TRRC's Groundwater Advisory Unit (GAU) identified the Base of Useable Quality water (BUQW)
at a depth of 250 ft and the base of the USDW at a depth of 950 ft at the location of the O'Neal No.
4. Approximately 14,924 ft is therefore separating the base of the USDW and the injection interval.
(A copy of the GAU's Groundwater Protection Determination letter issued by the TRRC as part of the
Class II permitting process for the O'Neal No. 4 is provided in Exhibit A-l.) The base of the deepest
aquifer is separated from the injection interval by more than 14,924 ft of rock, including 4,200 feet
of Midway shale. Though unlikely for reasons outlined in the sections here on confinement and
potential leaks, if the migration of injected fluid did occur above the Pearsall Formation, thousands
of feet of tight sandstone, limestone, shale, and anhydrite beds occur between the injection interval
and the lowest water-bearing aquifer.

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of the
O'Neal No. 4 (modified from Bruun, B., et al., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 31 of 78

-------
System

Series

Stratigraphic Units

Hydrostratigraphy

Baker (1979)



Holocene

Alluvium



£¦
ra



Beaumont Clay

Chicot aquifer

sz
aj

CD
3

o

Pleistocene

Lissle
Formation

Montgomery
Formation





Bentley
Formation







Willis Sand





Pliocene

Goliad Sand

Evangeline aquifer





Fleming Formation/
Lagarto Clay

- _ _



Miocene

	



Burkeville Confining System





/



Tertiary



Oakville Sandstone

Jasper aquifer





" 2

Upper part of
i , i Catahoula tuff







oaianouia xun
or sandstone/

2Anahuac
Formation

Catahoula Confining System



Oligocene

		

2 Frio
Formation







Frio Clay^'-^icksburg Group
equivalent



Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006)

s



*1,000-



2,000

		.



0)

-3,000

c



o

CO
>
Q)
UU

-4,000

-5, ODD-
'S ,000-
-7,000-

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No, 4 (modified from Bruun et al., 2016)

S'

25 Miles

Chicot Aquifer

Evangeline Aquifer

Subpart RR MRV Plan - O'Neal No. 4

Page 32 of 78

-------
Freestone1

,nderson

Brown

Hamilton

lacogdoche]

McLennan Limestoro

Coryell

Houston

Angelina

tobertson

Madison"

Hardin

Travis

Montgomery

'ashingto

Bastrop

Jefferson

Austin

Harris

Kendall

F^tte

Caldweli

lambeb.

Comal

Colorado

Guadalupi

Fort Bend

Lavaca

Wharton

Brazoria

Wilson

Dewitt

Jackson j Matagorda

.Barnes

Victoria

Goliad

McMullfisn

Duval Ji,n Well^lljece"s>;

Kleberg J/

Brooks

Kenedy

Willacy

Hidalgo

Cameron

San Saba>amPasas

X	

£ Burnet /	Milam \ J | Ltfvalker

Mason Llano ? 7 Williamson \	Sjirazos}	SiinJac

J	—^ L	u li eson \	A.

Gillespie

Blanco

Bandera

Medina

La Salle

Webb •

Gulf of Mexico

Mexico

120

¦ Miles

Total dissolved solids (milligrams per liter)

1-1,000 Fresh	1,000-3,000 Slighty saline	3.000-10,000 Moderately saline	10,000-35,000 Very saline

^ State boundary | | County boundary | j Aquifer boundary

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No, 4 (modified from Bruun et al,, 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 33 of 78

-------
2.6 References

Bebout, D.G., Budd, D.A., and Schatzinger, R.A. (1981). Depositional and Diagenetic History of the
Sligo and Hosston Formations (Lower Cretaceous) in South Texas: The University of Texas at
Austin, Bureau of Economic Geology, Report of Investigations No. 109.

Blondes, M.S., Gans, K.D., Engle, M.A. et al. (2018). U.S. Geological Survey National Produced Waters
Geochemical Database (Ver. 2.3, January 2018): U.S. Geological Survey data release,
https://doi.org/10.5066/F7J964W8.

Bruun, B., Anaya, R., Boghici, R. et al. (2016). Texas Aquifers Study: Chapter 6, Gulf Coast Aquifers.

Chowdhury, A.H. and Turco, M.J. (2006). Geology of the Gulf Coast Aquifer, Texas. In: Mace, R.E., et
al., Eds., Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report.

Dennen, K.O. and Hackley, P.C. (2012). Definition of Greater Gulf Basin Lower Cretaceous and Upper
Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico
basin onshore and state waters: https://pubs.usgs.gov/publication/70176229.

Galloway, W.E. (2008). Sedimentary Basins of the World, Chapter 15: Depositional Evolution of the
Gulf of Mexico Sedimentary Basin, 505-549.

Hull, D.C. (2011). Stratigraphic Architecture, Depositional Systems, and Reservoir Characteristics of
the Pearsall Shale-Gas System, Lower Cretaceous, South Texas: Thesis for M.S. of Science in
Geology, University of Texas, Austin.

Kirkland, B.L., Lighty, R.G., Rezak, R., and Tieh, T.T. (1987). Lower Cretaceous barrier reef and outer
shelf facies, Sligo Formation, south Texas, United States.

Roberts-Ashby, T.L., Brennan, S.T., Buursink, M.L. et al. (2012). Geologic framework for the national
assessment of carbon dioxide storage resources: U.S. Gulf Coast. USGS.

Swanson, S.M., Enomoto, C.B., Dennen, K.O. et al. (2017). Geologic assessment of undiscovered oil
and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate
rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain
and State Waters: U.S. Geological Survey Open-File Report 2016-1199, 69 p.,
https://doi.org/10.3133/ofr20161199.

Talbert, S.J. and Atchley, S.J. (2000). Sequence Stratigraphy of the Lower Cretaceous (Albian)
Fredericksburg Group, Central and North Texas: Department of Geology, Baylor University,
Waco, Texas 76798.

Yurewicz, D.A., Marler, T.B., Meyerholtz, K.A., and Siroky, F.X. (1993). Early Cretaceous Carbonate
Platform, North Rim of the Gulf of Mexico, Mississippi, and Louisiana.

Subpart RR MRV Plan - O'Neal No. 4

Page 34 of 78

-------
2.7 Description of the Injection Process

2.7.1 Current Operations

The Pawnee Treating Facility and the O'Neal No. 4 are existing operating assets. The O'Neal No. 4
will be recompleted for acid gas injection service under the Class II permit process. Under the Class
II application, the maximum injection rate is 28 MT/yr (1.5 MMscf/d). The TAG is 98.2% CO2, which
equates to 27.5 MT/yr of CO2 each year. The current composition of the TAG stream is displayed in
Table 3.

Table 3 - Gas Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

The facility is designed to treat, dehydrate, and compress the natural gas produced from the
surrounding acreage in Bee County. The facility uses an amine unit to remove the CO2 and other
constituents from the gas stream. The TAG stream is then dehydrated, compressed, and routed
directly to the O'Neal No. 4 for injection. The remaining gas stream is processed to separate the
natural gas liquids from the natural gas. The facility is monitored 24 hours per day, 7 days per week.

2.8 Reservoir Characterization Modeling

The modeling software used to evaluate this project was Computer Modelling Group, Ltd.'s GEM
2023.2 (GEM) simulator, one of the most comprehensive reservoir simulation software packages for
conventional, unconventional, and secondary recovery. The GEM utilizes equation-of-state (EOS)
algorithms in conjunction with some of the most advanced computational methods to evaluate
compositional, chemical, and geochemical processes and characteristics. This results in the creation
of exceedingly precise and dependable simulation models for carbon injection and storage. The
GEM model holds recognition from the EPA for its application in the delineation modeling aspect of
the area of review, as outlined in the Class VI Well Area of Review Evaluation and Corrective Action
Guidance document.

The Sligo Formation serves as the target formation for the O'Neal No. 4 (API No. 42-025-32658).
The Petra software package was utilized to construct the geological model for this target formation.
Within Petra, formation top contours were generated and subsequently brought into GEM to
outline the geological structure.

Porosity and permeability estimates were determined using the porosity log from the O'Neal No. 4.
A petrophysical analysis was then conducted to establish a correlation between porosity values and
permeability, employing the Coates equation. Both the porosity and permeability estimates from

Subpart RR MRV Plan - O'Neal No. 4

Page 35 of 78

-------
the O'Neal No. 4 were incorporated into the model, with the assumption that they exhibit lateral
homogeneity throughout the reservoir.

The reservoir is assumed to be at hydrostatic equilibrium. Given the geological formation in which
this well is located and its previous history as a gas producer, the model is assumed to be primarily
saturated with gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine
saturated, as deduced from the well log data. The modeled injection interval exhibits an average
permeability of 0.23 mD and an average porosity of 5%. All layers within the model have been
perforated. An infinite-acting reservoir has been created to simulate the boundary conditions.

The gas injectate is composed predominantly of CO2 as shown in Table 4. The modeled composition
takes into consideration the carbon dioxide and other constituents of the total stream. As the
facility has been in operation for many years, the gas composition for the proposed injection period
is expected to remain constant.

Table 4- Modeled Injectate Composition

Component

Expected Composition
(mol %)

Modeled
Composition (mol %)

Carbon Dioxide (CO2)

98.2

98.2

Hydrocarbons

1.03

Hydrocarbons

Hydrogen Sulfide

0.4

Hydrogen Sulfide

Nitrogen

0.37

Nitrogen

Core data from the literature review was used to determine residual gas saturation (Keelan and
Pugh, 1975) and relative permeability curves between carbon dioxide and the connate brine within
the Sligo carbonates (Bennion and Bachu, 2010). A maximum residual gas saturation of 35% was
assigned to the model based on core from the literature review. The Corey-Brooks method was
used to create relative permeability curves. The key inputs used to create the relative permeability
curves in the model include a Corey exponent for brine of 1.8, a Corey exponent for gas of 2.5, brine
and gas relative permeability endpoints of 0.8 and 0.5, respectively, and an irreducible brine
saturation of 20%. The relative permeability curves used for the GEM model are shown in Figure
24.

Subpart RR MRV Plan - O'Neal No. 4

Page 36 of 78

-------
1

2-Phase (C02/Brine) Relative Permeability Curves
O'Neal No. 4 Sligo Formation

0.8 ¦

>

S 0.6

CU
(D

E

i—



% 0.4

(D
Ctl





















0.2





















0 ¦
C

) 0.2 0.4 0.6 0.8 ]

Gas Saturation

L







— Krw 	Krg



Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model

The grid contains 81 blocks in the x-direction (east-west) and 81 blocks in the y-direction (north-
south), resulting in a total of 6,561 grid blocks per layer. Each grid block spans dimensions of 250 ft
x 250 ft. This configuration yields a grid size measuring 20,250 ft x 20,250 ft, equating to just under
15 square miles in area. The grid cells in the vicinity of the O'Neal No. 4, within a radius of 0.5 mi,
have been refined to dimensions of 83.333 ft x 83.333 ft in all layers. This refinement is employed
to ensure a more accurate representation of the plume and pressure effects near the wellbore.

In the model, each layer is characterized by homogeneous permeability and porosity values. These
values are derived from the porosity log of the O'Neal No. 4. The model encompasses a total of 61
layers, each featuring a thickness of approximately 3 ft per layer. As previously mentioned, the
model is perforated in each layer, with the top layer being the top of the injection interval and the
bottom layer being the lowest portion of the injection interval. The summarized property values for
each of these packages are displayed in Table 5.

Subpart RR MRV Plan - O'Neal No. 4

Page 37 of 78

-------
Table 5 - GEM Model Layer Package Properties

Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

1

15,874

3

0.004

3.75%

2

15,877

3

0.002

2.98%

3

15,880

3

0.001

1.62%

4

15,883

3

0.001

1.78%

5

15,886

3

0.002

2.32%

6

15,889

3

0.001

1.96%

7

15,892

3

0.002

3.10%

8

15,895

3

0.002

2.99%

9

15,898

3

0.003

3.52%

10

15,901

3

0.006

4.00%

11

15,904

3

0.005

3.93%

12

15,907

3

0.001

2.15%

13

15,910

3

0.001

1.99%

14

15,913

3

0.002

2.97%

15

15,916

3

0.001

2.22%

16

15,919

3

0.002

2.88%

17

15,922

3

0.001

2.38%

18

15,925

3

0.093

6.68%

19

15,928

3

0.005

2.62%

20

15,931

3

0.002

2.58%

21

15,934

3

0.003

3.07%

22

15,937

3

0.006

3.62%

23

15,940

3

0.002

2.68%

24

15,943

3

0.001

1.08%

25

15,946

3

0.002

1.87%

26

15,949

3

0.025

4.70%

27

15,952

3

0.024

4.37%

28

15,955

3

0.001

1.97%

29

15,958

3

0.003

2.27%

30

15,961

3

0.007

3.09%

31

15,964

3

0.110

6.75%

32

15,967

3

0.037

5.62%

33

15,970

3

0.011

4.41%

34

15,973

3

0.022

4.59%

35

15,976

3

0.297

7.88%

36

15,979

3

0.440

9.21%

37

15,982

3

0.060

5.90%

38

15,985

3

0.001

2.22%

39

15,988

3

0.001

2.21%

Subpart RR MRV Plan - O'Neal No. 4

Page 38 of 78

-------
Layer
No.

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

40

15,991

3

0.001

1.12%

41

15,994

3

0.003

2.05%

42

15,997

3

0.014

4.56%

43

16,000

3

0.007

4.15%

44

16,003

3

0.033

5.95%

45

16,006

3

1.233

10.25%

46

16,009

3

1.476

12.04%

47

16,012

3

0.566

10.08%

48

16,015

3

1.679

12.18%

49

16,018

3

2.194

13.08%

50

16,021

3

1.235

12.02%

51

16,024

3

0.788

11.22%

52

16,027

3

0.944

10.48%

53

16,030

3

0.424

9.05%

54

16,033

3

0.378

8.85%

55

16,036

3

0.378

8.81%

56

16,039

3

0.378

8.84%

57

16,042

3

0.736

9.91%

58

16,045

3

0.232

7.94%

59

16,048

3

0.238

7.97%

60

16,051

3

0.012

3.01%

61

16,054

3

0.038

4.30%

2.8.1 Simulation Modeling

The primary objectives of the model simulation were as follows:

1.	Estimate the maximum areal extent and density drift of the injectate plume after injection.

2.	Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone.

3.	Assess the likelihood of the injectate plume migrating into potential leak pathways.

The reservoir is assumed to have an irreducible brine saturation of 20%. The salinity of the brine
within the formation is estimated to be 150,000 ppm (USGS National Produced Waters Geochemical
Database, Ver. 2.3), typical for the region and formation. The injectate stream is primarily composed
of CO2 and H2S as stated previously. Core data from the literature was used to help generate relative
permeability curves. From the literature review, also as previously discussed, cores that most
closely represent the carbonate rock formation of the Sligo seen in this region were identified, and
the Corey-Brooks equations were used to develop the curves (Bennion and Bachu, 2010). A low,
conservative residual gas saturation based on the cores from the literature review was then used to
estimate the size of the plume (Keelan and Pugh, 1975).

Subpart RR MRV Plan - O'Neal No. 4

Page 39 of 78

-------
The model is initialized with a reference pressure of 10,995 psig at a subsea depth of 15,740 ft. This,
when a Kelly Bushing "KB" elevation of 334 ft is considered, correlates to a gradient of 0.684 psi/ft.
This pressure gradient was determined from production data of the O'Neal No. 4. An initial reservoir
pressure of 0.76 psi/ft was calculated before initial production. However, in 1997, after producing
approximately 0.5 billion cubic feet (Bcf) of gas, the well was shut in. The last bottomhole pressure
reading was calculated to be 0.480 psi/ft. This assumes the reservoir repressurizes after production
ceases, but not fully back to in situ conditions. Therefore, a 10% safety factor was given to the initial
reservoir pressure gradient of 0.76 psi/ft, and a gradient of 0.684 psi/ft was implemented into the
model as a conservative estimate. A skin factor of -2 was applied to the well to simulate the
stimulation of the O'Neal No. 4 for gas production from the Sligo Formation, which is based on the
acid fracture report, provided in Appendix A-3.

The fracture gradient of the injection zone was estimated to be 0.954 psi/ft, which was determined
from the acid fracture report. A 10% safety factor was then applied to this number, putting the
maximum bottomhole pressure allowed in the model at 0.86 psi/ft, which is equivalent to 13,652
psig at the top of the Sligo injection interval.

The model, which begins in January 2025, runs for a total of 22 years, comprising 12 years of active
injection, and is then succeeded by 10 years of density drift. Throughout the entire 12-year injection
period, an injection rate of 1.5 MMscf/D is used to model the maximum available rate, yielding the
largest estimate of the plume size. After the 12-year injection period, when the O'Neal No. 4 ceases
injection, the density drift of the plume continues until the plume stabilizes 10 years later. The
maximum plume extent during the 12-year injection period is shown in Figure 25. The final extent
after 10 years of density drift after injection ceases is shown in Figure 26 (page 42).

Subpart RR MRV Plan - O'Neal No. 4

Page 40 of 78

-------
C02 Saturation at End of Injection

283750 -

282500 -

281250

280000 -

0.80- js

0.70

0.60

-0.50

-0.40

-0.30

-0.20

|o.,o

		0.03-1

278750 —	Actual Scale: 1:0

Y/X: 1:1
Axis Units: ft
Total Blocks: 459.26P
Active Blocks: 459.269

	I	I	I	I	I

2316000	2318000	2320000	2322000	2324000	2326000

Figure 25 - Areal View of Saturation Piume at Shut-in (End of injection)

Subpart RR MRV Plan - O'Neal No. 4

Page 41 of 78

-------
CO, Saturation at End of Simulation

1	i	i

283750 -

282500 -

281250 -

280000 -

278750

o 80 H

0.70

-0.60

-0.50

-0.40

-0.30

J™-0.20
0.10

0.03

Actual Scale: 1:0
Y/X: 1:1
Axis Units: ft
Total Blocks: 459,269
Active Blocks: 459.269

I

2320000

I

2324000

2316000

I

2318000

' ' ' I
2322000

' ' ' I
2326000

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal No. 4

Page 42 of 78

-------
The cross-sectional view of the O'Neal No. 4 shows the extent of the plume from a side-view angle,
cutting through the formation at the wellbore. Figure 27 shows the maximum plume extent during
the 12-year injection period. During this time, gas from the injection well is injected into the
permeable layers of the formation and predominantly travels laterally. Figure 28 (page 45) shows
the final extent of the plume after 10 years of migration. Then, the effects of residual gas saturation
and migration due to density drift are clearly shown. At least 35% of injected gas that travels into
each grid cell is trapped, as the gas travels mostly vertically—as it is less dense than the formation
brine—until an impermeable layer is reached. Both figures are shown in an east-to-west view.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 43 of 78

-------
C02 Saturation at End of Injection

15500 -

15563 -

15625 -

15688 -

15750 -

15813 -

0.80-1

-0.70

-0.60

0.50

-0.40

-0.30

-0.20

-0.10

0.03-1

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical Sice: 2 of 3
Total Blocks: 459.269
Active Blocks: 459.269

r

2319000

2321000

West

2323000

East

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 44 of 78

-------
C02 Saturation at End of Simulation

15500

15563 -

15625 -

15688 -

15750

15813 -

0.80-=i

0.70

0.60

-0.50

0.40

0.30

-0.20

1-0.10

0.03

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical 9ce: 2 of 3
Total Bocks: 459,269
Active Blocks: 459.269

2319000

2321000

West

2323000

East

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 45 of 78

-------
Figure 29 shows the surface injection rate, bottom hole pressures, and surface pressures over the
injection period—and the period of density drift after injection ceases. The bottomhole pressure
increases the most as the injection rate ends, reaching a maximum pressure of 13,337 psig, at the
end of injection. This buildup of 2,362 psig keeps the bottomhole pressure below the fracture
pressure of 13,652 psig. The maximum surface pressure associated with the maximum bottomhole
pressure reached is 6,095 psig, well below the maximum allowable 7,937 psig per the TRRC UIC
permit application for this well. Bottomhole and wellhead pressures are provided in Table 6.

2,000,000

1,750,000

_ 1,500,000
¦a

jn 1,250,000
O)

4-»

1,000,000

£
o

y 750,000

.«

'E

— 500,000
250,000
0

10

Time (years)

15

20















































		









	





































16,000

12,000

10,000

8,000 fg

"D

6,000 ~

4,000
2,000
0

• Gas Rate (scf/d)

• BHP (psig)

WHP (psig) — — —BHP Constraint (psig) — — — WHP Constraint (psig)

Figure 29-Well Injection Rate and Bottomhole and Surface Pressures Over Time

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 46 of 78

-------
Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection

Time from Start of Injection
(years)

BHP (psig)

WHP (psig)

0

10,975

-

10

13,311

6,073

12 (End of Inj.)

13,337

6,095

20

11,029

-

22 (End of Model)

11,013

-

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 47 of 78

-------
SECTION 3 - DELINEATION OF MONITORING AREA

This section discusses the delineation of both the maximum monitoring area (MMA) and active
monitoring area (AMA) as described in 40 CFR §98.448(a)(1).

3.1 Maximum Monitoring Area

The MMA is defined as equal to or greater than the area expected to contain the free-phase CO2
plume until the plume has stabilized, plus an all-around buffer zone of at least one half mile.
Numerical simulation was used to predict the size and drift of the plume. With CMG's GEM software
package, reservoir modeling was used to determine the areal extent and density drift of the plume.
The model considers the following:

•	Offset well logs to estimate geologic properties

•	Petrophysical analysis to calculate the heterogeneity of the rock

•	Geological interpretations to determine faulting and geologic structure

•	Offset injection history to predict the density drift of the plume adequately

Ozona's expected gas composition was used in the model. The injectate is estimated at a molar
composition of 98.2% CO2 and 1.8% of other constituents. The StarTex Pawnee Treating Facility has
been in stable operations for many years. Ozona believes the gas analysis provided in Table 1 is an
accurate representation of the injectate. In the future, if the actual gas analysis varies materially
from the injectate composition herein, an update to this MRV plan will be submitted to the GHGRP.
As discussed in Section 2, the gas will be injected into the Sligo Formation. The geomodel was
created based on the rock properties of the Sligo.

The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of
3% gas saturation was used to determine the boundary of the plume. When injection ceases in Year
12, the area expanse of the plume will be approximately 270 acres. The maximum distance between
the wellbore and the edge of the plume is approximately 0.42 mi to the west. After 10 additional
years of density drift, the areal extent of the plume is 303 acres with a maximum distance to the
edge of the plume of approximately 0.45 mi to the west. Since the plume shape is relatively circular,
the maximum distance from the injection well after density drift was used to define the circular
boundary of the MMA. The AMA and the MMA have similar areas of influence, with the AMA being
only marginally smaller than the MMA. Therefore, Ozona will set the AMA equal to the MMA as the
basis for the area extent of the monitoring program.

This is shown in Figure 30 with the plume boundary at the end of injection, the stabilized plume
boundary, and the MMA. The MMA boundary represents the stabilized plume boundary after 10
years of density drift plus an all-around buffer zone of one half mile.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 48 of 78

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Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area
Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 49 of 78

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3.2 Active Monitoring Area

The AMA was initially set equal to the expected total injection period of 12-years. The AMA was
analyzed by superimposing the area based on a one-half mile buffer around the anticipated plume
location after 12 years of injection (2037), with the area of the projected free-phase CO2 plume at
five additional years (2042). In this case, as shown in Figure 31, the plume boundary in 2042 is within
the plume in 2037 plus the one-half mile buffer. Since the AMA boundary is only slightly smaller
than the MMA boundary, Ozona will define the AMA to be equal to the MMA. By 2037, Ozona will
submit a revised MRV plan to provide an updated AMA and MMA.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 50 of 78

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Figure 31 - Active Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 51 of 78

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SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE

This section identifies and discusses the potential pathways within the MMA for CO2 to reach the
surface and is summarized in Table 7. Also included are the likelihood, magnitude, and timing of
such potential leakage. The potential leakage pathways are:

•	Surface equipment

•	Existing wells within the MMA

•	Faults and fractures

•	Upper confining layer

•	Natural or induced seismicity

Table 7 - Potential Leakage Pat

iway Risk Assessment

Potential Leakage
Pathway

Likelihood



Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low

Low. Automated systems
will detect leaks and
execute shut-down
procedures.

During active
injection period.
Thereafter the well
will be plugged.

Existing wells within
the MMA

Unlikely. One artificial
penetration was drilled into
the injection interval. This
well has been properly
plugged and abandoned.

Low

Low. Vertical migration
of CO2 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Faults and fractures

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of CO2 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Upper confining zone

Unlikely. The lateral
continuity of the UCZ
consisting primarily of the
Pearsall Formation which is
over 500 ft thick is
recognized as a very
competent seal.

Low

Low. Vertical migration
of CO2 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

Natural or induced
seismicity

Unlikely. There is over 14,000

ft of impermeable rock
between the injection zone
and the base of the USDW.

Low

Low. Vertical migration
of CO2 would likely enter
a shallower hydrocarbon
production zone.

During active
injection.

1 - UCZ is defined as the upper confining zone.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 52 of 78

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Magnitude Assessment Description

Low - catergorized as little to no impact to safety, health and the environment and the costs to mitigate

are minimal.	

Medium - potential risks to the USDW and for surface releases does exist, but circumstances can be

	easily remediated.	

High - dangerto the USDW and significant surface release may exist, and if occurs this would require
	significant costs to remediate.	

4.1 Leakage from Surface Equipment

The Pawnee Treating Facility and O'Neal No. 4 are designed for separating, transporting, and
injecting TAG, primarily consisting of CO2, in a manner to ensure safety to the public, the employees,
and the environment. The mechanical aspects of this are noted in Table 8 and Figure 32. The
facilities have been designed to minimize leakage and failure points, following applicable National
Association of Corrosion Engineers (NACE) and American Petroleum Institute (API) applicable
standards and practices. As the TAG stream contains H2S, monitors installed for H2S detection will
also indicate the presence of CO2. These monitors will be installed at key locations around the
facility and the O'Neal No. 4 location. These devices will be continuously monitored by the
Supervisory Control and Data Acquisition (SCADA) system and will alarm at set points determined
by the facility's Health, Safety and Environment (HS&E) Director, consistent with Occupational
Safety and Health Administration (OSHA) requirements. The facility will set the detection and alarm
states for personnel at 10 ppm and at 40 ppm for initiating Emergency Shutdown. Key monitoring
points and parameters are also provided in Table 8.

The facilities will incorporate important safety equipment to ensure reliable and safe operations. In
addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-pressure
shutoff settings to isolate the facility, the O'Neal No. 4, and other components, StarTex has a flare
stack to safely handle the TAG when a depressuring event occurs. These facilities will be constructed
in the coming months. The exact location of this equipment is not yet known, but it will be installed
in accordance with applicable engineering and safety standards.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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Table 8 - Summary of TAG Monitors and Equipment

Device

Location

Set Point

H2S Monitors (1-4)

O'Neal No. 4 wellsite

10 ppm High Alarm
40 ppm Emergency Shutdown

H2S Monitors (5-8)

In-Plant Monitors

10 ppm High Alarm
40 ppm Emergency Shutdown

Flare Stack

Plant Site Perimeter

N/A

AGI Flowmeter

In-Plant (downstream of
the Amine Unit)

Calibrated per API specifications

Emergency Shutdown

In-Plant Monitors

40 ppm Facility Shutdown

Emergency Shutdown

O'Neal No. 4 wellsite

40 ppm Facility Shutdown

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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With the continuous air monitoring at the facility and the well site, a release of CO2 would be quickly
identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The CO2 injected into the O'Neal No. 4 is from the amine
unit at the Pawnee Treating Facility. If any leakage were to be detected, the volume of CO2 released
would be quantified based on the operating conditions at the time of release, as stated in Section 7,
in accordance with 40 CFR §98.448(a)(5). Ozona concludes that the leakage of CO2 through the
surface equipment is unlikely.

4.2 Leakage Through Existing Wells Within the MMA

The O'Neal No. 4 is engineered to prevent migration from the injection interval to the surface
through a special casing and cementing design as depicted in the schematic provided in Figure 32.
Mechanical integrity tests (MITs), required under Statewide Rule (SWR) §3.46 [40 CFR §146.23
(b)(3)], will take place every 5 years to verify that the well and wellhead can contain the appropriate
operating pressures. If the MIT were to indicate a leak, the well would be isolated and the leak
mitigated to prevent leakage of the injectate to the atmosphere.

A map of all oil and gas wells within the MMA is shown in Figure 33. Figure 34 is a map of all the oil
and gas wells that penetrate the MMA's gross injection zone. Only one well penetrated the MMA's
gross injection zone. This well was non-productive and has been plugged and abandoned in
accordance with TRRC requirements. A summary table of all oil and gas wells within the MMA is
provided in Appendix B-l.

This table in Appendix B-l provides the total depth (TD) of all wells within the MMA. The wells that
are shallower and do not penetrate the injection zone are separated by the Pearsall Formation with
a gross thickness of 535 ft. The Pine Island Shale comprises approximately 130 ft of this interval as
discussed in Section 2.2.2 and provides a competent regional seal—making vertical migration of
fluids above the injection zone unlikely.

The shallower offset hydrocarbon wells within the MMA will also serve as above zone monitoring
wells. Should any of the sequestered volumes migrate vertically, they would potentially enter the
shallower hydrocarbon reservoir. Regular sampling and analysis is performed on the produced
hydrocarbons. If a material difference in the quantity of CO2 in the sample occurs indicating a
potential migration of injectate from the Sligo Formation, Ozona would investigate and develop a
mitigation plan. This may include reducing the injection rate or shutting in the well. Based on the
investigation, the appropriate equation in Section 7 would be used to make any adjustments to the
reported volumes.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 55 of 78

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* SEQUESTRATION

Ozona CCS

Country: USA

API No: 42-025-32668

C02 Injection Well
Proposed Well Design - O'Neal Gas Unit No. 4

State/Province: Texas

Field: TBD

County/Parish: Bee County

Well Type/Status: Proposed

Texas License F-S652

Location: 28 6031807. -SS.0017091

Project No: LS190

Date: 10/13/2023

12912 HI Coutry &va 5* =-200
Austr "or "8738
Te 512.732-9012
sar 512 732.9816

Drawn: Joseph Lovewel

Reviewed: David Lytie

Approved: David Lytie

Rev No: 0

Notes:

Figure 32 - O'Neal No. 4 Wellbore Schematic

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 56 of 78

-------
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Figure 33 - All Oil and Gas Weils Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 57 of 78

-------
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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 58 of 78

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4.2.1 Future Drilling

Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations have proven to date to be nonproductive in this area, and therefore Ozona does not see
this as a risk. This is supported by a review of the TRRC Rule 13 (Casing, Cementing, Drilling, Well
Control, and Completion Requirements), 16 TAC §3.13. The Sligo is not among the formations listed
for which operators in Bee County and District 2 (where the O'Neal No. 4 is located) are required to
comply with TRCC Rule 13; therefore, the TRRC does not believe there are productive horizons
below the Sligo. The O'Neal No. 4 drilling permit is provided in Appendix A-2.

4.2.2 Groundwater Wells

The results of a groundwater well search found five wells within the MMA, as identified by the Texas
Water Development Board as shown in Figure 35 and in tabular form in Appendix B-2.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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Figure 35 - Groundwater Wells Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 60 of 78

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The surface, intermediate, and production casings of the O'Neal No. 4, as shown in Figure 32, are
designed to protect the shallow freshwater aquifers, consistent with applicable TRRC regulations,
and the GAU letter issued for this location is provided in Appendix A-l. The wellbore casings and
compatible cements prevent CO2 leakage to the surface along the borehole. Ozona concludes that
leakage of the sequestered CO2 to the groundwater wells is unlikely.

4.3	Leakage Through Faults and Fractures

Detailed mapping of openhole logs surrounding the O'Neal No. 4 did not identify any faulting within
either the Pearsall or Sligo sections. However, there is a general lack of deep penetrators within the
area that limits the amount of openhole coverage available.

The majority of the published literature suggests that faulting near the project area is restricted to
the shallower, overlying Cenozoic section, as shown in Figure 9, with shallow faults dying out before
reaching the Pearsall Formation. One source interpreted the potential for faulting to the south
(Swanson et al., 2016). The potential fault is depicted in Figure 8 relative to the location of the
O'Neal No. 4. According to the map, the interpreted fault lies approximately 4.25 mi south-
southeast of the well and approximately 3.9 mi south-southeast of the stabilized plume extent in
the year 2047. In the unlikely scenario in which the injection plume or pressure front reaches the
potential fault, and the potential fault was to act as a transmissive pathway, the upper confining
Pearsall shale contains sufficient thickness and petrophysical properties required to confine and
protect injectates from leaking outside of the permitted injection zone.

Section 2.1.2 discusses regional structure and faulting, and Section 2.3 covers local structure, for
additional material relevant to this topic.

4.4	Leakage Through the Upper Confining Zone

The Sligo injection zone has competent sealing intervals present above and below the targeted
carbonate sequence of the Sligo section. The overlying Pine Island shale member of the Pearsall
Formation is approximately 130 ft thick at the O'Neal No. 4. Above this confining unit, the Cow
Creek Limestone, Cow Creek shale, and Bexar Shale Members of the Pearsall Formation will act as
additional confinement between the injection interval and the USDW. The USDW lies well above
the sealing properties of the formations outlined above, making stratigraphic migration of fluids into
the USDW highly unlikely. The petrophysical properties of the lower Sligo and Hosston Formations
make these ideal for lower confinement. The low porosity and permeability of these underlying
formations minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injectate to the in situ reservoir fluid makes migration below the lower confining layer
unlikely.

4.5	Leakage from Natural or Induced Seismicitv

The O'Neal No. 4 is located in an area of the Gulf of Mexico considered to be active from a seismic
perspective. Therefore, the Bureau of Economic Geology's TexNet (from 2017 to present) and
USGS's Advanced National Seismic System (from 1971 to present) databases were reviewed to

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 61 of 78

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identify any recorded seismic events within 25 kilometer (km) of the O'Neal No. 4.

The investigation identified a multitude of seismic events within the 25 km search radius; however,
the magnitude of most of the events was below 2.5. The nearest seismic event with a recorded
magnitude of 3.0 or greater was measured approximately 5.6 km northwest of the O'Neal No. 4 at
a depth of 5 km. The results of the investigation are plotted on the map provided in Figure 36
relative to the O'Neal No. 4 and the 25-km search radius.

The Facility will have operating procedures and set points programmed into the control and SCADA
systems to ensure operating pressures are maintained below the fracture gradient of the injection
and confining intervals, thus avoiding the potential for inducing seismicity.

Given the seismic activity in the area, Ozona will closely monitor nearby TexNet station EF71 for
activity and any corresponding irregularities in the operating pressures of O'Neal No. 4. If a seismic
event of 3.0 or greater is recorded at Station EF71 or if anomalies are identified in the operating
data, Ozona will review the data and determine if any changes occurred that indicate potential
leakage. Ozona would take appropriate measures based on their findings, including limiting the
injection pressure and reducing the injection rate.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 62 of 78

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within km R*diut

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Figure 36 - 25-km Seismicity Review

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 63 of 78

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SECTION 5 - MONITORING FOR LEAKAGE

This section discusses the strategy that Ozona will employ for detecting and quantifying surface
leakage of CO2 through the pathways identified in Section 4, to meet the requirements of 40 CFR
§98.448(a)(3). As the injectate stream contains both H2S and CO2, the H2S will be a proxy for CO2
leakage and therefore the monitoring systems in place to detect H2S will also indicate a release of
CO2. Table 9 summarizes the monitoring of the following potential leakage pathways to the surface.
Monitoring will occur during the planned 12-year injection period or cessation of injection
operations, plus a proposed 10-year post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults or fractures

•	Leakage through confining seals

•	Leakage through natural or induced seismicity

Table 9 - Summary of Leakage Monitoring Methods

Leakage Pathway

Monitoring Method

Surface equipment

Fixed H2S monitors at the Plant and well site

Visual inspections

Monitor SCADA systems for the Plant and well site

Existing wells within the MMA

Monitor C02 levels in above zone producing wells

Mechanical Integrity Tests (MIT) of the AGI Well every 5 years

Visual inspections

Annual soil gas sampling near well locations that penetrate the
Upper Confining Zone within the AMA

• Leakage through
groundwater wells

Annual groundwater samples from existing water well(s)

• Leakage from future wells

Monitor drilling activity and compliance with TRRC Rule 13
Regulations

Faults and Fractures

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Upper confining zone

SCADA continuous monitoring at the well site (volumes and
pressures)

Monitor C02 levels in Above Zone producing wells

Natural or induced seismicity

Monitor C02 levels in Above Zone producing wells

Monitor existing TexNet station



Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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5.1 Leakage from Surface Equipment

The facility and the O'Neal No. 4 were designed to operate in a safe manner to minimize the risk of
an escape of CO2 and H2S. Leakage from surface equipment is unlikely and would quickly be
detected and addressed. The facility design minimizes leak points through the equipment used, and
key areas are constructed with materials that are NACE and API compliant. A baseline atmospheric
CO2 concentration will be established prior to commencing operation once facility construction has
been completed. Ambient H2S monitors will be located at the facility and near the O'Neal No. 4 site
for local alarm and are connected to the SCADA system for continuous monitoring.

The facility and the O'Neal No. 4 are continuously monitored through automated control systems.
These monitoring points were discussed in Section 4.1. In addition, field personnel conduct routine
visual field inspections of gauges, and gas monitoring equipment. The effectiveness of the internal
and external corrosion control program is monitored through the periodic inspection of the
corrosion coupons and inspection of the cathodic protection system. These inspections and the
automated systems allow Ozona to detect and respond to any leakage situation quickly. The surface
equipment will be monitored for the injection and post-injection period. Should leakage be
detected during active injection operations, the volume of CO2 released will be calculated based on
operating conditions at the time of the event, per 40 CFR §98.448(a)(5) and §98.444(d).

Pressures, temperatures, and flow rates through the surface equipment are continuously monitored
during operations. If a release occurred from surface equipment, the amount of CO2 released would
be quantified based on the operating conditions, including pressure, flow rate, percentage of CO2 in
the injectate, size of the leak-point opening, and duration of the leak. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7.

5.2 Leakage Through Existing and Future Wells Within the MMA

Ozona continuously monitors and collects injection volumes, pressures, and temperatures through
their SCADA systems, for the O'Neal No. 4. This data is reviewed by qualified personnel and will
follow response and reporting procedures when data exceeds acceptable performance limits. A
change of injection or annular pressure would indicate the presence of a possible leak and be
thoroughly investigated. In addition, MITs performed every 5 years, as expected by the TRRC and
UIC, would also indicate the presence of a leak. Upon a negative MIT, the well would be isolated
and investigated to develop a leak mitigation plan.

As discussed previously, TRRC Rule 13 ensures that new wells in the field are constructed with
proper materials and practices to prevent migration from the injection interval.

In addition to the fixed monitors described previously, Ozona will also establish and operate an in-
field monitoring program to detect CO2 leakage within the AMA. This would include H2S monitoring
as a proxy for CO2 at the well site and annual soil gas samples taken near any identified wells that
penetrate the injection interval within the AMA. These samples will be analyzed by a qualified third

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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-------
party. Prior to commencing operation, and through the post-injection monitoring period, Ozona
will have these monitoring systems in place.

Currently, there is only one well in the MMA identified that penetrates the injection interval. This
well was plugged and abandoned in 2007. The TRRC records are provided in Appendix A-4. Ozona
will take an annual soil gas sample from this area, which will be analyzed by a third-party lab.
Additional monitoring will be added as the AMA is updated over time. In the unlikely event a leak
occurs, Ozona will quantify the leak volumes by the methodologies discussed in Section 7 and
present these results and related activities in the annual report.

Ozona will also utilize shallower producing gas wells as proxies for above-zone monitoring wells.
Production data from these wells is analyzed for monthly production statements, and therefore
would be an early indicator of any possible subsurface issues. Should any material change from
historical trends in the CO2 concentration occur, Ozona would investigate and develop a corrective
action plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is
very low, as the producing reservoir provides an ideal containment given the upper confining zone
of this reservoir has proven competent. In the unlikely event a leak occurs, Ozona would quantify
the leak per the strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443
based on the actual circumstances and include these results in the annual report.

5.2.1 Groundwater Quality Monitoring

Ozona will monitor the groundwater quality above the confining interval by sampling from
groundwater wells near the O'Neal No. 4 and analyzing the samples with a third-party laboratory
on an annual basis. In the case of the O'Neal No. 4, 5 existing groundwater wells have been
identified within the AMA (Figure 38). Initial groundwater quality tests will be performed to
establish a baseline prior to commencing operations.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 66 of 78

-------
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Figure 37 - Groundwater Wells

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 67 of 78

-------
5.3 Leakage Through Faults. Fractures, or Confining Seals

Ozona will continuously monitorthe operations of the O'Neal No. 4 through the automated controls
and SCADA systems. Any deviation from normal operating volume and corresponding injection
pressure could indicate movement into a potential leak pathway, such as a fault or breakthrough of
the confining seal and would trigger an alert due to a change in the injection pressure. Any such
alert would be reviewed by field personnel and appropriate action would be taken, including
shutting in the well, if necessary.

Ozona will also utilize shallower producing wells as proxies for above-zone monitoring wells.
Production data is analyzed regularly for monthly production statements and therefore would be
an early indicator of any possible subsurface issues. Should any material change from historical
trends in the CO2 concentration occur, Ozona would investigate and develop a corrective action
plan. Should any CO2 migrate vertically from the Sligo Formation, the magnitude risk of this event
is very low, as the producing reservoir provides an ideal containment given the upper confining zone
has proven competent. In the unlikely event a leak occurs, Ozona would quantify the leak per the
strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443 based on the
actual circumstances.

5.4 Leakage Through Natural or Induced Seismicitv

While the likelihood of a natural or induced seismicity event is low, Ozona plans to use the nearest
TexNet seismic monitoring station, EF71, to monitor the area around the O'Neal No. 4. This station
is approximately 3 mi to the northwest, as shown in Figure 38. This is sufficient distance to allow
for accurate and detailed monitoring of the seismic activity in the area. Ozona will monitor this
station for any seismic activity, and if a seismic event of 3.0 magnitude or greater is detected, Ozona
will review the injection volumes and pressures of the O'Neal No. 4 to determine if any significant
changes have occurred that would indicate potential leakage.

Ozona will also continuously monitor operations through the SCADA system. Any deviation from
normal operating pressure and volume set points would trigger an alarm for investigation by
operations staff. Such a variance could indicate movement into a potential leak pathway, such as a
fault or breakthrough of the confining seal. Any such alert would be reviewed by field personnel
and appropriate action would be taken, including shutting in the well, if necessary

These are the two primary strategies for mitigating risks for induced seismicity. In the unlikely event
a leak occurs, Ozona will quantify the leak per the strategies discussed in Section 7, or as may be
applicable provided in 40 CFR §98.443 based on the actual circumstances.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 68 of 78

-------
2T.EFS2

o*** l» /H.'iOt

2TEF68

O^G«Un« #4

TexNet Scrwnc Stations

2T.EF75

25 km Ra6ut

2T.EF71

Seism* Events within 25-Km

M2.0-2.49 (66)
O M2.S-2.99 (23)
O MJ.0-3.49 (7)
O M3.S* 3.99(1)
O M4XM.«(0)

o M4.5-4.99 (0)

O'Neal Gas Unit #4
28.602915, -98.001428

MS.0* (0)

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Figure 38 - Seismic Events and Monitoring Station

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 69 of 78

-------
SECTION 6 - BASELINE DETERMINATIONS

This section identifies the strategies Ozona will undertake to establish the expected baselines for
monitoring CO2 surface leakage per 40 CFR §98.448(a)(4). Ozona will use the existing SCADA
monitoring systems to identify changes from the expected performance that may indicate leakage
of injectate and calculate a corresponding amount of CO2.

6.1	Visual Inspections

Regular inspections will be conducted by field personnel at the facility and O'Neal No. 4 site. These
inspections will aid in identifying and addressing possible issues to minimize the risk of leakage. If
any issues are identified, such as vapor clouds or ice formations, corrective actions will be taken
prudently and safely to address such issues.

6.2	H2S/ CO2 Monitoring

In addition to the fixed monitors in the facility and at the wellsite, Ozona will establish and perform
an annual in-field sampling program to monitor and detect any CO2 leakage within the AMA. This
will consist of soil gas sampling near any artificial penetrations of the injection zone and sampling of
water wells. These probes have special membrane inserts that collect the gas samples over a 21-
day period. These will be analyzed by a third-party lab to be analyzed for CO2, H2S, and trace
contaminants typically found in a hydrocarbon gas stream. The lab results will be provided in the
annual report should they indicate a material variance from the baseline. Initial samples will be
taken and analyzed before the commencement of operations and will establish the baseline
reference levels.

6.3	Operational Data

Upon starting injection operations, baseline measurements of injection volumes and pressures will
be recorded. Any significant deviations over time will be analyzed for indication of leakage of
injectate and the corresponding component of CO2.

6.4	Continuous Monitoring

The total mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly,
as the injection stream for this project is near the OSHA Permissible Exposure Limit (PEL) 8-hour
Time Weighted Average (TWA) of 5,000 ppm. Direct leak surveys present a hazard to personnel due
to the presence of H2S in the gas stream. Continuous monitoring systems will trigger alarms if there
is a release. The mass of the CO2 released would be calculated based on the operating conditions,
including pressure, flow rate, percentage of CO2, size of the leak-point opening, and duration. This
method is consistent with 40 CFR §98.448(a)(5) and §98.444(d), allowing the operator to calculate
site-specific variables used in the mass balance equation.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 70 of 78

-------
In the case of a depressuring event, the acid gas stream will be sent to a flare stack to be safely
processed and will be reported under reporting requirements for the facility. Any such events will
be accounted for in the sequestered reporting volumes consistent with Section 7.

6.5 Groundwater Monitoring

Initial samples will be taken from groundwater wells in the area of the O'Neal No. 4 upon approval
of the MRV plan, and before commencement of CO2 injection. These samples will be analyzed and
reports prepared by a third-party laboratory testing for pH, total dissolved solids (TDS), CO2, and
volatile organic compounds (VOC). Initial samples will be taken and analyzed before the
commencement of operations and will establish the baseline reference levels. Sampling select wells
will be performed annually. In the event a material deviation in the sample analysis occurs, the
results will be provided in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 71 of 78

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SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS

BALANCE EQUATION

This section identifies how Ozona will calculate the mass of CO2 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the CO2 emissions from equipment leaks and
vented emissions of CO2 between the injection flow meter and the injection well, per 40 CFR
§98.448(a)(5).

7.1	Mass of CO2 Received

Per 40 CFR §98.443, the mass of CO2 received must be calculated using the specified CO2 received
equations "unless you follow the procedures in 40 CFR §98.444(a)(4)." The 40 CFR §98.444(a)(4)
states that "if the CO2 you receive is wholly injected and is not mixed with any other supply of CO2,
you may report the annual mass of CO2 injected that you determined following the requirements
under paragraph (b) of this section as the total annual mass of CO2 received instead of using
Equation RR-1 or RR-2 of this subpart to calculate CO2 received." The CO2 received for this injection
well is injected and not mixed with any other supply; the annual mass of CO2 injected will equal the
amount received less any amounts calculated in accordance with the equations of this section. Any
future streams would be metered separately before being combined into the calculated stream.

7.2	Mass of CO2 Injected

Per 40 CFR §98.444(b), since the flow rate of CO2 injected will be measured with a volumetric flow
meter, the total annual mass of CO2, in metric tons, will be calculated by multiplying the mass flow
by the CO2 concentration in the flow according to Equation RR-5:

CC>2,u = Annual CO2 mass injected (metric tons) as measured by flow meter u

Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard
conditions (standard cubic meters per quarter)

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682

Cco2,P,u = Quarterly CO2 concentration measurement in flow for flow meter u in quarter p
(vol. percent CO2, expressed as a decimal fraction)

p = Quarter of the year

u = Flow meter

4

p=1

Where:

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 72 of 78

-------
7.3	Mass of CO2 Produced

The O'Neal No. 4 is not part of an enhanced oil recovery project; therefore, no CO2 will be produced.

7.4	Mass of CO2 Emitted by Surface Leakage

The mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly due
to the H2S concentration in the injection stream. Direct leak surveys are dangerous and present a
hazard to personnel. Because no venting is expected to occur, the calculations would be based on
the unusual event that a blowdown is required and those emissions would be sent to a flare stack
and reported as a part of the required GHG reporting for the facility. Any leakage would be detected
and managed as an upset event. Continuous monitoring systems should trigger an alarm upon a
release of H2S and CO2. The mass of the CO2 released would be calculated for the operating
conditions, including pressure, flow rate, size of the leak-point opening, and duration of the leak.
This method is consistent with 40 CFR §98.448(a)(5), allowing the operator to calculate site-specific
variables used in the mass balance equation.

In the unlikely event that CO2 was released because of surface leakage, the mass emitted would be
calculated for each surface pathway according to methods outlined in the plan and totaled using
Equation RR-10 as follows:

CO2E = Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year
CC>2,x= Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting year
X = Leakage pathway

Calculation methods using equations from Subpart W will be used to calculate CO2 emissions due to
any surface leakage between the flow meter used to measure injection quantity and the injection
wellhead.

As discussed previously, the potential for pathways for all previously mentioned forms of leakage is
unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, Ozona believes the most appropriate method to quantify the mass of CO2
released will be determined on a case-by-case basis. Any mass of CO2 detected leaking to the
surface will be quantified by using industry proven engineering methods including, but not limited
to, engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling,
and history-matching of the sequestering reservoir performance, among others. In the unlikely
Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 73 of 78

X

x=l

Where:

-------
event that a leak occurs, it will be addressed, quantified, and documented within the appropriate
timeline. Any records of leakage events will be kept and stored as provided in Section 10.

7.5 Mass of CO2 Sequestered

The mass of CO2 sequestered in subsurface geologic formations will be calculated based on Equation
RR-12. Data collection for calculating the amount of CO2 sequestered in the O'Neal No. 4 will begin
once the subsurface recompletion work, and the surface facilities construction has been completed,
and subject to approval of the MRV plan. The calculation of sequestered volumes utilizes the
following equation as the O'Neal No. 4 will not actively produce oil, natural gas, or any other fluids:

C02 — CO21 — C02e ~ CO2F1

Where:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year

CO21 = Total annual CO2 mass injected (metric tons) in the well or group of wells covered by
this source category in the reporting year

CO2E = Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year

CO2F1 = Total annual CO2 mass emitted (metric tons) from equipment leaks and vented
emissions of CO2 from equipment located on the surface, between the flow meter used to
measure injection quantity and the injection wellhead, for which a calculation procedure is
provided in subpart W of this part.

CO2F1 will be calculated in accordance with Subpart W for reporting of GHGs. Because no venting is
expected to occur, the calculations would be based on the unusual event that a system blowdown
event occurs. Those emissions would be sent to a flare stack and reported as part of the GHG
reporting for the facility.

• Calculation methods from Subpart W will be used to calculate (Remissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 74 of 78

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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN

The O'Neal Gas Unit No. 4 is an existing natural gas well that will be recompleted as a Class II well
with corrosion-resistant materials. The Class II permit is still in process with the TRRC. Until this
permit is issued, Ozona cannot specify a date to acquire the baseline testing data. Ozona is
submitting this MRV application to the GHGRP to comply with the requirements of Subpart RR. The
MRV plan, including acquisition of baseline data, will be implemented upon receiving EPA approval.
The Annual Subpart RR Report will be filed on March 31 of the year following the reporting year.

Table 10- Baseline Sampling Schedule

Sampling Location

Estimated Date

Comments

Fixed H2S/CO2 Monitors

Oct. 1, 2024

Baseline readings will be
established during
commissioning activities.

Soil gas sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Water well sampling

Oct. 1, 2024

Baseline samples will be taken
prior to commencement of
injection.

Notes:

•	Above dates are estimates subject to adjustment based on actual regulatory
approval dates and facilities construction timelines.

•	All baseline sampling will be performed prior to the start of recording data for
reporting under this MRV.

•	Commissioning activities include installation of surface facilities, including flowline,
compressors, manifolds, etc.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 75 of 78

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SECTION 9 - QUALITY ASSURANCE

This section identifies how Ozona plans to manage quality assurance and control to meet the

requirements of 40 CFR §98.444.

9.1	Monitoring QA/QC

CO2 Injected

•	The flow rate of the CO2 being injected will be measured with a volumetric flow meter,
consistent with API standards. These flow rates will be compiled quarterly.

•	The composition of the injectate stream will be measured upstream of the volumetric flow
meter with a continuous gas composition analyzer or representative sampling consistent
with API standards.

•	The gas composition measurements of the injected stream will be averaged quarterly.

•	The CO2 measurement equipment will be calibrated per the requirements of 40 CFR
§98.444(e) and §98.3(i).

CO2 Emissions from Leaks and Vented Emissions

•	Gas monitors at the facility and O'Neal No. 4 will be operated continuously, except for
maintenance and calibration.

•	Gas monitors will be calibrated according to the requirements of 40 CFR §98.444(e) and
§98.3(i).

•	Calculation methods from Subpart W will be used to calculate CChemissionsfrom equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Measurement Devices

•	Flow meters will be continuously operated except for maintenance and calibration.

•	Flow meters will be calibrated according to 40 CFR §98.3(i).

•	Flow meters will be operated and maintained in accordance with applicable standards as
published by a consensus-based standards organization.

All measured volumes of CO2 will be converted to standard cubic meters at a temperature of 60°F

and an absolute pressure of 1 atmosphere.

9.2	Missing Data

In accordance with 40 CFR §98.445, Ozona will use the following procedures to estimate missing

data if unable to collect the data needed for the mass balance calculations:

•	If a quarterly quantity of CO2 injected is missing, the amount will be estimated using a
representative quantity of CO2 injected from the nearest previous period at a similar
injection pressure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 76 of 78

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• Fugitive CO2 emissions from equipment leaks from facility surface equipment will be
estimated and reported per the procedures specified in Subpart W of 40 CFR §98.

9.3 MRV Plan Revisions

If any changes outlined in 40 CFR §98.448(d) occur, Ozona will revise and submit an amended MRV
plan within 180 days to the Administrator for approval.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 77 of 78

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SECTION 10 - RECORDS RETENTION

Ozona will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
3 years and include the following:

•	Quarterly records of the CO2 injected

o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the CO2 stream

•	Annual records of the information used to calculate the CO2 emitted by surface leakage from
leakage pathways.

•	Annual records of the information used to calculate CO2 emitted from equipment leaks and
vented emissions of CO2 from equipment located on the surface, between the flow meter
used to measure injection quantity and the injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 78 of 78

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APPENDICES
APPENDIX A - O'Neal No. 4 TRRC FORMS

APPENDIX A-l: GAU GROUNDWATER PROTECTION DETERMINATION

APPENDIX A-2: DRILLING PERMIT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

APPENDIX A-3: COMPLETION REPORT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

•	MINI FRACTURE REPORT

APPENDIX A-4: API 42-025-30388 CHARLIE C. OVERBY GU PLUGGING RECORDS

-------
APPENDIX B - AREA OF REVIEW

APPENDIX B-l: OIL AND GAS WELLS WITHIN THE MMA LIST

APPENDIX B-2: WATER WELLS WITHIN THE MMA LIST

-------
APPENDIX A-l

GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit

Form GW-2

Date Issued:

26 May 2023

GAU Number:

367912

Attention:

OZONA CCS LLC

API Number:

02532658



19026 RIDGEWOOD

County:

BEE



SAN ANTONIO, TX 78259

Lease Name:

O'Neal Gas Unit









Lease Number:

162214

Operator No.:

100116







Well Number:

4





Total Vertical

16101





Latitude:

28.602914





Longitude:

-98.001428





Datum:

NAD27

Purpose:
Location:

Injection into Producing Zone (H1)
Survey-EL&RR RR CO; Abstract-452; Section-1



To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:

The base of usable-quality water-bearing strata is estimated to occur at a depth of 250 feet at the site of the referenced
well.

The BASE OF UNDERGROUND SOURCES OF DRINKING WATER (USDW) is estimated to occur at a depth of 950
feet at the site of the referenced well.

Note: Unless stated otherwise, this recommendation is intended to apply to all wells drilled within 200 feet of the subject well.
Unless stated otherwise, this recommendation is for normal drilling, production, and plugging operations only.

This determination is based on information provided when the application was submitted on 05/26/2023. If the location
information has changed, you must contact the Groundwater Advisory Unit, and submit a new application if necessary.

If you have questions, please contact us at 512-463-2741 orgau@rrc.texas.gov.

Groundwater Advisory Unit, Oil and Gas Division

Form GW-2 P.O. Box 12967 Austin Texas 78771-2967 512-463-2741 Internet address: www.rrc.texas.
Rev. 02/2014

-------
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Drilling Permit (W-1) Query Results

APPENDIX A-2

Search Criteria:
API No.: 02532658

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2 results Page: 1 of 1 Page Size: view ah v

API NO.

District

Lease

Well
Number

Permitted
O iterator

Countv

Status
Date

Status
Number

Wellbore
Profiles

Filina
PurDose

Amend

Total
Death

Stacked
Lateral
Parent
Well DP

#

Status

02532658 Links v

02

CHARLIE
C.

OVERBY
GAS
UNIT

2

PARKER &
PARSLEY
DEVELOPMENT
CO.(640889)

BEE

Submitted:
11/30/1992
Approved:
11/30/1992

406655

Vertical

New Drill

N

16700



APPROVED

02532658 Links v

02

O'NEAL
GAS
UNIT
Q622141

4

PARKER &
PARSLEY
DEVELOPMENT
L.P(640886)

BEE

Submitted:
11/20/1996
Approved:
12/16/1996

455434

Vertical

Re completion

N

14040



APPROVED

Download

Return



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NOTE: THE CHARLIE C. OVERBY GU AND THE O'NEAL GU ARE THE SAME WELL. THE OVERBY WELL WAS DRILLED IN 1993 INTO THE SLIGO.
IN 1997 THE WELL WAS RECOMPLETED IN THE EDWARDS FORMATION. THIS WAS DONE UNDER A NEW LEASE, AS THE O'NEAL GU NO. 4.

-------
Form W-1: Field List

Log In

Status # 406655
API # 025-32658

OP # 640889 - PARKER & PARSLEY DEVELOPMENT CO.

Approved ,Issued: 11/30/1992 ,Filed: Hardcopy

CHARLIE C. OVERBY GAS UNIT - Well # 2

02 - BEE County

New Drill

Vertical

NEAREST WELL COMMENT: 1607.8 ( 11/30/1992 12:00:00 AM )

Status:

Back to Public Query Search Results

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

01/01/1993

02/11/1993

01/01/1993

Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (SLIGO)

Gas

02/11/1993

06/18/1993

General / Location Information

Basic Information:

Filing
Purpose

Welbore
Profiles

Lease Name

Well

#

SWR

Total
Depth

Horizontal
Wellbore

Stacked Lateral Parent
Well DP #

New Drill

Vertical

CHARLIE C. OVERBY
GAS UNIT

2

SWR
36

16700





Surface Location Information:

API #

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658

4.0 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





EL&RR RR CO

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Survey Lines

2784.0 feet

from the S line and

1045.5 feet

from the W line

Permit Restrictions:

Code

Description

30

REGULAR PROVIDED THAT UPON SUCCESSFUL COMPLETION OF THIS WELL IN THE SAME RESERVOIR AS ANY OTHER WELL
PREVIOUSLY ASSIGNED THIS ACREAGE, A P-15 AND REVISED PRORATION PLATS MUST BE SUBMITTED WITH NO

30

DOUBLE ASSIGNMENT OF ACREAGE.

30

REGULAR PROVIDED THIS WELL IS NEVER COMPLETED IN THE SAME RESERVOIR AS ANY OTHER WELL CLOSER THAN 2640
FEET ON THIS SAME LEASE.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

https://webapps.rrc.texas.gov/DP/drillDownQuery Action, do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362... 1/2

-------
11/28/23, 4:52 PM

Form W-1: Field List

30 O'NEAL GU #3, O'NEAL #1, OVERBY #120 & NEAL #1.

Fields

District

Field
Name

Field #

Completion
Depth

Lease
Name

Well

#

Well
Type

Acres

Distance to

Nearest

Well

Distance to
Nearest
Lease Line

SWR

Pooled/
Unitized

02

PAWNEE
(SLIGO)

Primary
Field

69845800

16700

CHARLIE C.
OVERBY GAS
UNIT

2

Oil or

Gas

Well

704.0





SWR
36

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 2390.0 feet from the E line and 3446.0 feet from the N line



I

Comments

Remark

Date Entered

Entered By

NEAREST WELL COMMENT: 1607.8

11/30/1992 12:00:00 AM

SYSTEM

Attachments

Attachment Type

File Path

Associated Fields and/or Plats

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https://webapps.rrc.texas.gov/DP/drillDownQuery Action.do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362.

2/2

-------
***** Online System

Log in

Form W-1: Review

Status# 455434
API # 025-32658

OP #640886 - PARKER & PARSLEY DEVELOPMENT L.P

Approved ,Issued: 12/16/1996 ,Filed: Hardcopy

O'NEAL GAS UNIT - Well # 4

02 - BEE County

Recompletion

Vertical

NEARESTWELL COMMENT: 1787 ( 11/20/1996 12:00:00 AM )

Status:

Back to Pui?iig Query Search Resets

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

02/04/1997

02/13/1997



Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (EDWARDS)

Gas

02/13/1997

02/26/1997

General / Location Information

Bask Information:

Filing Purpose

Wei bore Profiles

Lease Name

Well #

SWR

Total Depth

Horizontal Wellbore

Stacked Lateral Parent Well DP #

Recompletion

Vertical

O'NEAL GAS UNIT

4

SWR 36, SWR37H

14040





Surface Location Information:

API#

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658 lil

3.5 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





E.L.&R.R. RR CO. #1

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Sirvey Lines

825.0 feet

from the W line and

2784.0 feet

from the S line

Permit Restrictions:

Code

Description

30

WILDCAT ABOVE 14040 FEET

30

ANY WELLBORE DRILLED UNDER THIS PERMIT MUST BE COMPLETED, OPERATED, AND PRODUCED IN COMPLIANCE WITH STATEWIDE RULE 32.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

Fields

District

Field Name

Field #

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

WILDCAT
Primary Field

00004001

14040

O'NEAL GAS UNIT

4

Oil or Gas Well

704.0





37H

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the S line





District

Field Name

Field#

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

PAWNEE CEDWARDS)

69845200

14040

O'NEAL GAS UNIT

4

Gas Well

704.0





SWR 36, 37H

Y



Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the S line







Exceptions

Field

Exception

Case Docket Number

Resolution

WILDCAT

SWR 37 [Historical]

0214349



PAWNEE CEDWARDS)

SWR 37 [Historical]

0214349



Comments

Remark

Date Entered

Entered By

NEARESTWELL COMMENT: 1787

11/20/1996 12:00:00 AM

SYSTEM

Attachments

Attachment Type	File Path	Associated Fields and/or Plats

Disdaimer | RRC Online Home | RRC Home | Contact

-------
APPENDIX A-3

Ozona CCS

Well Name: ONeal Gas Unit 4 (current)
Formation: Edwards
County, State: Bee County, TX
API #: 42-025-32658
Permit #:

Rig
GL
RKB
TD (MD)
TP (TVD)

Lat, Long 28.6031807,-98.0017091 (NAD83)
GAU Depth:

MD/TVD

10.75" Surface Casing

Cook Mountai n

3657

Sparta

4259

Weches Sandstone

4326

Queen City

4655

Reklaw

5244

Carrizo

5864

Wilcox

5922

Midway

9026

Austin Chalk

13266

Eagle Ford

13344

Buda

13494

Edwards

13500

CIBP w/ 20' Cement on Top

14000

5" Liner Top

14088

Pearsall

15339

1 5/8" Intermediate Casing

15340

zd





C02 Resistant Permanent Packer

Sligo



L



Tubular Detail

String

Hole Size

OD

Weight

Grade

MD



(in)

(in)

(#/ft)



(ft)

Conductor











Surface

14 3/4"

10 3/4"

55.5

S-95

3,610'

Intermediate

9 1/2"

7 5/8"

39

CY-95

15,340'

Liner

6 1/2"

5"

18

Q-125

14,088'-16,101'

Prod Tbg



2 3/8"

4.7

L-80

13453'

Cement Detail

String

Vol

Type

TOC

%XS



(sks)



(MD)



Surf Lead

1125

HLC

0'



Surf Tail

350

H





Int Lead

575

50:50 Poz:H

7359'



Int Tail

400

H





Liner

200

Premium

14088'



Edwards perfs production zone, 13,529*-13,841*	

Cumulative 6,555,750 MCF gas, 168,888 BBLs water produced

Initial production zone, 15,874'-16,056*

Cumulative 511,964 MCF gas, 22,026 BBLs water produced

Well History

#

Date

Description

1

12/30/1992

First spud as gas well, targeting the Sligo formation

2

2/13/1997

Plugged back to 14,000' and recompleted

-------
,i st ome r ;
«\lell Desc :
For mati on;

PARKER.. & PARSLEY DEV. CO.
CHARLI/•— OVERBV #2
BLIQO

Date:
Ti^-ty^t #:
Job Type:

4—^:2—93

30841600

THERMAGEL 80/70

«=: VfcElNlT

«S=.. F-" O R: 1





Event

Tirie









staqe

¦neua

HH:HH:SS

Event Desc nation





e

1

stgad

1G:lb:26

Operator Stage Advance

--> TREATED HATER «/ 70I/H6AL HLC-4



e

2

stgad

10:27:30

Operator Stage Advance

--> SHUTDOWN - MONITOR FOR LEAK OFF



e

2

NOTES

10:28:59

Operator's Notes

*** IS1P = 8068 PS1



e

3

stgad

10:49:59

Operator Stage Advance

—> TREATED MATER W/ 70#/H6AL blLC-4



e

4

stgad

11:02:45

Operator Stage Advance

--> FLUSH MINIFRAC - TREATED HATER



e

5

stgad

11:09:59

Operator Stage Advance

-> SHUTDOWN - MONITOR PRESSURE DECLINE



e

5

NOTES

11:24:51

Operator's Notes

*** ISIP = 8312 PSI F6 = .954

e

5

NOTES

13:04:21

Operator's Notes

«** CLOSURE = 8000 CORRECTED F EFF. = 26X



e

6

stgad

13:09:20

Operator Stage Advance

--) PAD 70# LINEAR 6EL



e

6

NOTES

13:33:40

Operator's Notes

**» START SAND AT .251/6

/

e

6

NOTES

13:59:34

Operator's Notes

*i* START XLINKER AT .2 6/H

v/

e

6

NOTES

14:14:13

Operator's Notes

**» SHUT OFF SAND



e

6

NOTES

17:01:53

Operator's Notes

*** START METHANOL



e

7

stgad

17:04:11

Operator Stage Advance

--> PAD 80# THERMA6EL



e

8

stgad

18:07:24

Operator Stage Advance

--> 1# - 4# 30/60 CAR6Q-PR0P



e

9

stgad

18:37:54

Operator Stage Advance

-> 4# 30/60 CARBO-PROP



e

9

NOTES

19:07:37

Operator's Notes

*** INCREASED SAND TO 4.5 #/6



e

9

NOTES

19:29:08

Operator's Notes

*** SAND OFF BY APPRO*. .51/6



e

10

stgad

19:30:03

Operator Stage Advance

—> FLUSH - TREATED HATER



e

11

stgad

19:35:52

Operator Stage Advance

--> SHUTDOWN - MONITOR PRESSURE



e

11

NOTES

19:37:13

Operator's Notes

*** 1SIP=9169



e

11

NOTES

19:37:22

Operator's Notes

«* STARTED FLOH BACK



-------
APPENDIX A-4

Plugging Record

RAILROAD COMMISSION OF TEXAS
OIL AND GAS DIVISION

FORM W-3
Rev, 12/92

EAG0S97

API NO

(if available) 42-025-30388

FILE IN DUPLICATE WITH DISTRICT OFFICE OF DISTRICT IN WHICH
WELL IS LOCATED WEtfffif"THIRTY DAYS AFTER PLUGGING

1. RRC District
02

4. RRC Lease or Id.
Number
064112

2 FIELD NAME (as per RRC Records)
Pawnee	

( Sliqo )

3. Lease Name

Oveitoy, Charlie C. Gas Unit

5. Well Number
	1

OPERATOR
Pioneer Natural

6a. Original Form W-l Filed in Name of

10. County

purees USA, Inc.

Bee

7. ADDRESS
5205 N. O1

for Blvd. , Ste.

75039-3736
900 Irving, TX

6b. Any Subsequent W-l's Filed in Name of.

11. Date Drilling
Permit Issued

Location of^/ell, Relative to Nearest Lease Boundaries
of Leasg>eBwhich this Well is Located

' /	Feet From "W

Line and /7-S^ Feet From

12 Permit Number

>S Line of the

ron

Lease

9a SECTION, BLOCK, AND SURVEY
Marcelo Alcarte

A-70

9b. Djstance and Direction Fi'om Nearest Town in this
Co '

-ounty

3.5 miles South of Pawnee

13. Date Drilling
Commenced

16. Tvpe Well

(Oil, Gas, Diy)
	Gas	

Total Depth
16.300

18. If Gas, Amt. of Cond. on
Hand at time of Plugging

17. If Multiple Completion List All Field Names and Oil Lease or Gas ID No's

GAS ID or
OIL LEASE #

Oil-O
Gas-G

WELL
#

14. Date Drilling
Completed

^

15. Date Well Plugged

3-S-P7

CEMENTING TO PLUG AND ABANDON DATA:

PLUG #1

PLUG #2

PLUG #3

PLUG #4

PLUG #5

PLUG #6

PLUG #7

PLUG #8

*19. Cementing Date

2-27

2-27

3-2

3-5

3-6

3-6





20. Size of Hole or Pipe in which Plug Placqd^ippjie^,-,,^

3 1/2

3 1/2

7

7

7

7





21. Depth to Bottom of Tubing or Drill-Pipe-(fc»),c

9310

9200

3800

3563

300

15





*22. Sacks of Cement Used (each plug)

1

1

35

55

55

6





*23 Slurry Volume Pumped (cu ft) ~

1.06

1.06

37.10

58.30

58.30

6.36





*24- Calculated Top of Plug (ft.)

9280

9180

3650

3428

200

5





25. Measured Top of Plug (if tagged) (ft.)









187







*26. Slurry Wt. #/Gal. „

16.4

16.4

16.4

16.4

16.4

16.4





*27. Type Cement

H

H

H

H

H

H





28. CASING AND TUBING RECORD AFTER PLUGGING

29. Was any Non-Drillable Material (Other rav l—l xt
than Casing) Left in This Well ^ Yes U No

SIZE

WT.#/FT.

PUT IN WELL (ft.)

LEFT IN WELL (ft.)

HOLE SIZE (IN.)

29a. If answer to above is "Yes" state depth to top of "junk" left m hole
and briefly describe non-drillable material. (Use Reverse Side of
Form if more space is needed)

Left 3 1/2 tubing in well from 3800' to 15,055'. An

existing fish of 1 1/4" tubing from 9340' to 16,143'

also left in well.

16

49.50

61

61

UNK.

10 3/4

45.50

3513

3508

15"

7

49.50

15.529

15 r 524

8 3/4

4"

UNK

15055-16290

14247



30. LIST ALL OPEN HOLE AND/OR PERFORATED INTERVALS

FROM

15,911 T0 16.072



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

I have knowledge that the cemep
-------
• •

!L5SS?^a!S,* a Yes 32. How was Mud Applied? 33. Mud Weight

Railroad Commission I | No Cirnnl ated 12 5 I RS/fiAT

34, Total Depth
16,300

Other Fresh Water Zones by T.D.W.R.
TOP BOTTOM

35. Have all Abandoned Wells on this Lease been Plugged 1 I v»,
according to RRC Rules? Yes

~ No

Depth of Deepest
Fresh Water

250



36. If NO, Explain

37.	Name and Address of Cementing or Service company who mixed and pumped cement plugs in this well i Date RRC District Office
Bat's P & A, Inc. P.O. Box 0126. Biahr.r. IX 78343 	I notified of plugging 2-23-07

38.	Name(s) and Addresse(s) of Surface Owners of Well Site

39. Was Notice Given Before Plugging to the Above?

FILL IN BELOW FOR DRY HOLES ONLY

40. For Diy Holes, this Form must be accompanied by either a Driller's, Electric, Radioactivity or Acoustical/Sonic Log or such Log must be
released to a Commercial Log Service.

~ Log Attached	~ Log released to 			 Date	

Type Logs:

I—I Driller's	I	I Electric	I I Radioactivity	I I Acoustical/Sonic

41. Date FORM P-8 (Special Clearance) Filed?

42. Amount of Oil produced prior to Plugging

* Field FORM P-l (Oil Production Report) for month this oil was produced	

RRC USE ONLY

Nearest Field

REMARKS Unable to recover 3 1/2" tbg. as anticipated above existing 1 1/4" fish @ 9340'. Jet cut 3 1/2"	

	@ 9302' & 9243'. Unable to pull or establish calculation up 3 1/2 x 7" @ 3500 P.S.I.. Freepoint on 3 1/2

gsq-	at 4750 — . Notified and received approval from Kevin Shamette W/RRC to spt rrmp'g + 20' cmt below and

above cut's made on 3 1/2. Plug #1 & #2 - CIBP + 20' cmt. in 3 1/2" 12.95#. Cut 3 1/2 a 47fi9'anri perforated
3 1/2" 6 4765' but unable to pull or circulate. Re-cut @ 3800'. Received verbal approval from Kevin Shamo-H-p
W/RRC to set plug from 3800' tp 3650' Cut & perforated 7" casing 6 3563'. Casing not	TTnaKio i-r,	

establish circulation but established injection into 7" x 8 3/4" @ 2000 P.S.I.
Notified Ke.vin W/RRC to squeeze plug. Squeezed 5 5 sks. cmt. leaving 23 sks.
inside 7" 49.50# and 32 sks. outside in 7" x 8 3/4". Cut 7" csg. @ 300' but
unable to circulate. Received verbal approval to squeeze 55 sks. Squeezed
38 sks. out into 7" x 9 5/8" and left 17 sks inside 7" casing.

J

-------
O'Neal Gas Unit No. 4

APPENDIX B-l

Area of Review: Oil & Gas Wells List

API

WELL NAME

WELL NO.

CURRENT OPERATOR

ABSTRACT

LATITUDE
(WGS84)

LONGITUDE
(WGS84)

WELL STATUS

TOTAL DEPTH
(TVD FT.)

PERFORATED INTERVAL
(MD FT.)

DATE DRILLED

4202500002

ONEAL, A.

1

ROWAN & HOPE

126

28.603017

-98.000911

DRILLED

7010

NO RECORD

8/9/1949

4202500005

RUSSELL, S.

1

PAN AMERICAN PETROLEUM CORP.

308

28.594587

-97.999841

DRILLED

7515

NO RECORD

5/12/1947

4202530346

HENRY BUES

1

PIONEER NATURAL RES. USA, INC.

70

28.5986210

-98.0118480

INACTIVE PRODUCER

13842

7554-7558; 7612-7624;
13526-13760

11/10/1974

4202530359

ONEAL GAS UNIT

2

BB-SOUTHTEX, LLC

127

28.61178

-98.000661

PRODUCING

13961

13349-15821

4/5/1975

4202530388

OVERBY, CHARLIE C. GAS UNIT

1

PIONEER NATURAL RES. USA, INC.

70

28.601086

-98.005037

P &A

16300

15911-16072

6/6/1975

4202532342

DE LEON

1

T D EXPLORATION, INC.

126

28.6006330

-97.9917520

P &A

6512

NO RECORD

12/31/1985

4202532501

HENRY BUES GAS UNIT

2

BB-SOUTHTEX, LLC

70

28.599863

-98.009994

PRODUCING

13896

13504-15637

11/15/1988

4202532638

ONEAL GAS UNIT

3

BB-SOUTHTEX, LLC

70

28.604583

-98.007079

PRODUCING

13834

13508-13668

3/12/1992

4202532842

OVERBY, CHARLIE C.

1E

PIONEER NATURAL RES. USA, INC.

70

28.5998760

-98.0053330

P &A

14000

13514-13838

10/9/1995

4202532967

TOMASEK GAS UNIT

5

BB-SOUTHTEX, LLC

126

28.609862

-97.991519

PRODUCING

13875

13434-15693

6/12/1999

4202533006

ONEAL GAS UNIT

5

BB-SOUTHTEX, LLC

70

28.6067950

-98.0042210

PRODUCING

13772

13463-13764

7/15/2000

4202533035

ONEAL GAS UNIT

6

BB-SOUTHTEX, LLC

127

28.61091

-97.999073

PRODUCING

13835

13310-13833

9/14/2000

4202533085

ONEAL GAS UNIT

7

BB-SOUTHTEX, LLC

127

28.609397

-98.001471

PRODUCING

13868

13314-16072

5/4/2001

4202533114

HENRY BUES GAS UNIT

8

BB-SOUTHTEX, LLC

70

28.5984810

-98.0090260

PRODUCING

13732

13348-13732

6/11/2001

4202533197

ONEAL GAS UNIT

8

BB-SOUTHTEX, LLC

452

28.6075430

-98.0037990

PRODUCING

15638

13565-13820

2/5/2003

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

~

LONQUIST

SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

4202533272

HENRY BUES GAS UNIT

11

BB-SOUTHTEX, LLC

70

28.598737

-98.008615

PRODUCING

13856

13291-15853

6/23/2004

4202533273

ONEAL GAS UNIT

9

BB-SOUTHTEX, LLC

452

28.6029540

-98.0025090

PRODUCING

13872

13311-16585

6/3/2004

4202533328

ONEAL GAS UNIT

11

BB-SOUTHTEX, LLC

126

28.6036340

-97.9982100

PRODUCING

13787

13318-15928

4/19/2005

4202533345

TOMASEK GAS UNIT

8

BB-SOUTHTEX, LLC

126

28.608282

-97.991595

PRODUCING

13692

13293-16378

8/14/2004

4202533371

ONEAL GAS UNIT

12

BB-SOUTHTEX, LLC

452

28.6097460

-98.0027040

PRODUCING

13819

13313-16635

8/15/2006

4202533383

HENRY BUES GAS UNIT

15

BB-SOUTHTEX, LLC

70

28.600322

-98.00874

PRODUCING

13811

13302-15768

10/8/2006

4202533492

ONEAL GAS UNIT

13

BB-SOUTHTEX, LLC

70

28.605326

-98.012928

PRODUCING

13859

13382-14761

7/7/2007

4202533553

ONEAL GAS UNIT

14

BB-SOUTHTEX, LLC

127

28.613869

-98.000504

PRODUCING

13674

13450-15424

2/11/2008

4202533559

OVERBY GAS UNIT

2E

BB-SOUTHTEX, LLC

452

28.6011410

-98.0028580

PRODUCING

13734

13372-13734

3/23/2008

42025E2114

NO RECORD

NR

NO RECORD

126

28.608457

-97.995683

NO RECORD

NR

NO RECORD

NR

*Note: Well entries in red penetrate the upper confining layer.

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

APPENDIX B-2

Area of Review: Freshwater Wells List

WELL REPORT/ID NO.

OWNER'S NAME

OWNER ADDRESS

CITY/STATE/ZIP

LAT. WGS 84

LONG. WGS 84

WELL USE

WATER LEVEL (FT.)

TOTAL DEPTH (FT.)

DATE DRILLED

128936

JOHN DAVIDSON

12761 FM 673

KENEDY, TX 78119

28.606667

-98.011667

DOMESTIC

48

114

11/19/2007

7832308

HENRY BUES

NO RECORD

NO RECORD

28.598334

-98.012223

STOCK

-

150

1960

7925105

T. M. PLUMER

NO RECORD

NO RECORD

28.595556

-97.997778

STOCK

77

275

1931

7832309

W. A. MUELLER

NO RECORD

NO RECORD

28.608612

-98.005834

UNUSED

63

90

1925

7925106

R.C. HUNT ESTATE

NO RECORD

NO RECORD

28.593889

-97.997222

UNUSED

137

172

1925

~

O'Neal Gas Unit No. 4
Area of Review: Freshwater Wells List - Texas Water Development Board
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------
Request for Additional Information: O'Neal Gas Unit Well No. 4

May 16, 2024

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





1.

N/A

N/A

Please clarify whether the referenced Startex Pawnee Gas Plant has
previously reported any data under the GHGRP (e.g., subparts W,
UU, PP). If so, please include the related facility ID number in the
MRV plan.

The Pawnee Treating Facility is part of Startex's gas gathering
and boosting assets, which are currently reporting under
subpart W; (Facility ID No. 568661). Section 1.3 has been
revised to include this Facility ID No., with references to the
Pawnee Treating Facility and additional reporting
information.

2.

2.2.3

22

"The permeability curve was generated utilizing the Coates
permeability equation, incorporated with a 20% irreducible to
match analysis provided by Nutech."

Please clarify what "irreducible" means in this context.

Section 2.2.3 has been edited to clarify and now reads "20%
irreducible brine saturation".

3.

Table 7

52

"The lateral continuity of the UCZ is recognized as a very
competent seal."

This statement appears in the likelihood section of most potential
leakage pathways shown in Table 7. Please specify how the UCZ
being a competent seal relates to the likelihood of leakage for each
of these pathways. Also, please ensure that potential leakage
pathways are consistent between Table 7 and Table 9.

Table 7 has been updated to better characterize the
Likelihood of certain Leakage Pathways.

Table 9 has been updated to ensure the pathways discussed
are consistent between Tables 7 and 9. Leakage through
groundwater/future wells are subsets of the existing wells
discussion.

4.

4.5

61

Please include additional characterization related specifically to
induced seismicity in this section. Additionally, please clarify
whether the facility will take steps (such as limiting injection
pressures) to avoid inducing seismicity.

Section 4.5 has been updated to address potential induced
seismicity and clarify the steps to be taken to avoid inducing
seismicity.

1

-------
No.

MRV Plan

EPA Questions

Responses

Section

Page

5.

7.5

74

"C02F| = Total annual C02 mass emitted (metric tons) from
equipment leaks and vented emissions from equipment located on
the surface between the flow meter used to measure injection
quantity and the injection wellhead"

Per 40 CFR 98.443(F)(2), this variable should be "C02fi = Total annual
C02 mass emitted (metric tons) from equipment leaks and vented
emissions from equipment located on the surface between the flow
meter used to measure injection quantity and the injection
wellhead, for which a calculation procedure is provided in subpart
W of this part." Equations and variables cannot be modified from
the regulations. Please revise this section and ensure that all
equations listed are consistent with the text in 40 CFR 98.443.

The definitions of variables for the equation in Sections 7.2 and 7.5
has been updated to reflect the precise language used in 40 CFR
98.443.

6.

8

75

"The MRV plan will be implemented upon receiving EPA approval."

Per 40 CFR 98.448(a)(7). the DroDosed MRV Dlan must include a
"proposed date to begin collecting data for calculating total
amount sequestered according to equation RR-11 or RR-12 of this
subpart. This date must be after expected baselines as required by
paragraph (a)(4) of this section are established and the leakage
detection and auantification strategy as reauired bv paragraph (a)
(3) of this section is implemented in the initial AMA."

Please clarify in the MRV plan when baselines would be
established and when data would start to be collected for
calculating C02 sequestered. If this timeline is dependent on the
status of the Class II permit, we recommend specifying this in the
MRV plan. In the response to our previous request for additional
information, you provided additional context that would be
relevant in Section 8 of the MRV plan.

Section 8 has been updated with a table to formalize the
baseline sampling activities described in Section 6.

2

-------
No.

MRV Plan

EPA Questions

Responses

Section

Page

7.







The term "plant" was changed to "facility" through the
proposed MRV plan to better represent the activities of the
StarTex assets.

8.

2.2.5





An internal review of the MRV plan identified that the
fracture pressure gradient discussion included information
from an earlier test. The values have been updated and now
match the values used in the plume model.

9.

2.8





Additional language was added to clarify how the relative
permeability was determined.

10.

Table 8





Table 8 has been updated for consistent use of monitors.

3

-------
@)zona

Carbon Capture & Sequestration

Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
O'Neal Gas Unit Well No. 4

Bee County, TX

Prepared for Ozona CCS, LLC
San Antonio, TX

By

Lonquist Sequestration, LLC
Austin, TX

Version 2.0
January 2024

LONQUIST

SEQUESTRATION LLC

H

-------
INTRODUCTION

Ozona CCS, LLC (Ozona) has a pending Class II acid gas injection (AGI) permit application with the
Texas Railroad Commission (TRRC), which was submitted in September of 2023 for its O'Neal Gas
Unit Well No. 4 (O'Neal No. 4), API No. 42-025-32658. Granting of this application would
authorize Ozona to inject up to 1.5 million standard cubic feet per day (MMscf/D) of treated acid
gas (TAG) into the Sligo Formation at a depth of 15,874 feet (ft) to 16,056 ft, with a maximum
allowable surface pressure of 7,920 pounds per square inch gauge (psig). The TAG for this AGI
well is associated with StarTex's Pawnee Gas Plant, located in a rural area of Bee County, Texas,
approximately 2.0 miles (mi) south of Pawnee, Texas, as shown in Figure 1.



CM UaU »4

1 1

Rr«lnlul Ov»l vi*W

1

V*. I IW. 11,1 Wl [ MP



Pt\ MAD S IIA M l



irfllONQUIST



| V|J MOIKSTUDMiit



¦+" CTNul GmUtx *4

\/~

% Plant

\J y •



"^O'Neal Gas UnK #4



28.602915, -98.001428



1:50.000



0 12 3 4

Exrtm «•

	 MIIIS



Figure 1 - Location of Star l ex Gas Plant and the O'Neal No. 4

Subpart RR MRV Plan - O'Neal No. 4

Page 2 of 78

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Ozona is submitting this Monitoring, Reporting, and Verification (MRV) plan to the EPA for
approval under Title 40, U.S. Code of Federal Regulations (40 CFR) §98.440(a), Subpart RR, of the
Greenhouse Gas Reporting Program (GHGRP). In addition to submitting this MRV plan to the
EPA, Ozona has applied to the TRRC for the O'Neal GU No. 4's Class II permit. Ozona plans to
inject TAG for approximately 12 years. Table 1 shows the expected composition of the gas stream
to be sequestered from the nearby plant.

Table 1 - Expected TAG Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

Subpart RR MRV Plan - O'Neal No. 4

Page 3 of 78

-------
ACRONYMS AND ABBREVIATIONS

AMA
BCF
CH4
CMG

C02
E

EOS

EPA

ESD

FG

ft

GAPI

GAU

GEM

GHG

GHGRP

GL

H2S

JPHIE

mD

mi

MIT

MM

MMA

MCF

MMcf

MMscf

Subpart RR MRV Plan - O'Neal No. 4

Active Monitoring Area
Billion Cubic Feet
Methane

Computer Modelling Group, Ltd.

Carbon Dioxide (may also refer to other carbon

oxides)

East

Equation of State
Environmental Protection Agency
Emergency Shutdown
Fracture Gradient
Foot (Feet)

Gamma Units of the American Petroleum Institute
Groundwater Advisory Unit
Computer Modelling Group's GEM 2023.2
Greenhouse Gas

Greenhouse Gas Reporting Program
Ground Level Elevation
Hydrogen Sulfide

Effective Porosity (corrected for clay content)

Millidarcy

Mile(s)

Mechanical Integrity Test
Million

Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet

Page 4 of 78

-------
Mscf/D	Thousand Standard Cubic Feet per Day

MMscf/D	Million Standard Cubic Feet per Day

MRV	Monitoring, Reporting, and Verification

v	Poisson's Ratio

N	North

NW	Northwest

OBG	Overburden Gradient

PG	Pore Gradient

pH	Scale of Acidity

ppm	Parts per Million

psi	Pounds per Square Inch

psig	Pounds per Square Inch Gauge

S	South

SE	Southeast

SF	Safety Factor

SWD	Saltwater Disposal

TAC	Texas Administrative Code

TAG	Treated Acid Gas

TOC	Total Organic Carbon

TRRC	Texas Railroad Commission

UIC	Underground Injection Control

USDW	Underground Source of Drinking Water

W	West

Subpart RR MRV Plan - O'Neal No. 4

Page 5 of 78

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TABLE OF CONTENTS

INTRODUCTION	2

ACRONYMS AND ABBREVIATIONS	4

SECTION 1 - UIC INFORMATION	10

1.1	Underground Injection Control Permit Class: Class II	10

1.2	UIC Well Identification Number	10

1.3	Facility Address	10

SECTION 2 - PROJECT DESCRIPTION	11

2.1	Regional Geology	11

2.1.1	Geologic Setting and Depositional Environment	13

2.1.2	Regional Structure and Faulting	15

2.2	Site Characterization	17

2.2.1	Stratigraphy and Lithologic Characteristics	17

2.2.2	Upper Confining Interval - Pearsall Formation	19

2.2.3	Injection Interval - Upper Sligo Formation	20

2.2.4	Formation Fluid	23

2.2.5	Fracture Pressure Gradient	24

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations	25

2.3	Local Structure	25

2.4	Injection and Confinement Summary	30

2.5	Groundwater Hydrology	30

2.6	References	34

2.7	Description of the Injection Process	34

2.7.1 Current Operations	35

2.8	Reservoir Characterization Modeling	35

2.8.1 Simulation Modeling	39

SECTION 3 - DELINEATION OF MONITORING AREA	48

3.1	Maximum Monitoring Area	48

3.2	Active Monitoring Area	50

SECTION 4- POTENTIAL PATHWAYS FOR LEAKAGE	52

4.1	Leakage from Surface Equipment	53

4.2	Leakage Through Existing Wells Within the MMA	56

4.2.1	Future Drilling	59

4.2.2	Groundwater Wells	59

4.3	Leakage Through Faults and Fractures	61

4.4	Leakage Through the Confining Layer	61

4.5	Leakage from Natural or Induced Seismicity	61

SECTION 5 - MONITORING FOR LEAKAGE	64

5.1	Leakage from Surface Equipment	65

5.2	Leakage Through Existing and Future Wells Within the MMA	65

5.3	Leakage Through Faults, Fractures, or Confining Seals	68

5.4	Leakage Through Natural or Induced Seismicity	68

Subpart RR MRV Plan - O'Neal No. 4

Page 6 of 78

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SECTION 6 - BASELINE DETERMINATIONS	70

6.1	Visual Inspections	70

6.2	CO2/H2S Detection	70

6.3	Operational Data	70

6.4	Continuous Monitoring	70

6.5	Groundwater Monitoring	71

SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION	72

7.1	Mass of CO2 Received	72

7.2	Mass of CO2 Injected	72

7.3	Mass of CO2 Produced	73

7.4	Mass of CO2 Emitted by Surface Leakage	73

7.5	Mass of CO2 Sequestered	74

SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN	75

SECTION 9 - QUALITY ASSURANCE	76

9.1	Monitoring QA/QC	76

9.2	Missing Data	76

9.3	MRV Plan Revisions	77

SECTION 10 - RECORDS RETENTION	78

Figures

Figure 1 - Location of StarTex Gas Plant and the O'Neal No. 4	2

Figure 2 - Structural Features of the Gulf of Mexico and Locator Map (modified from Roberts-

Ashby etal., 2012)	11

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby

etal., 2012)	12

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The
proposed injection interval is shaded light blue and proposed confining intervals are shaded light

yellow (modified from Bebout et al., 1981)	13

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981)	14

Figure 6-Generalized northwest to southeast schematic cross section of the Trinity Group, south
Texas (the line of section depicted in Figure 5). The red star and line represent the approximate

location of the O'Neal No. 4 (modified from Kirkland et al., 1987)	 15

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated
porosity and permeability values of typical facies (modified from Talbert and Atchley, 2000).. 15
Figure 8 - Structural features and fault zones near the proposed injection site. The red star
represents the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

	16

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through
Word field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).. 17
Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted	18

Subpart RR MRV Plan - O'Neal No. 4

Page 7 of 78

-------
Figure 11 - Porosity-Permeability Crossplot of Pearsall Formation Crushed Rock Core Data

(Swanson et al., 2016)	20

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map. The
red star represents the approximate location of the O'Neal No. 4 (modified from Bebout et al.,

1981)	20

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)	21

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded

green >0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms	22

Figure 15 - Offset Wells Used for Formation Fluid Characterization	24

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)

	25

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the

location of the O'Neal No. 4	27

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the

locator map	28

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.
The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on

the locator map	29

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of

the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	31

Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006)	32

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	32

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun et al., 2016)	33

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model	37

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection)	41

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)	42

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

	44

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End

of Simulation)	45

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time	46

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum

Monitoring Area	49

Figure 31 - Active Monitoring Area	51

Figure 32 - O'Neal No. 4 Wellbore Schematic	55

Figure 33 - All Oil and Gas Wells Within the MMA	57

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA	58

Figure 35 - Groundwater Wells Within the MMA	60

Figure 36 - 25-km Seismicity Review	63

Figure 37 - Groundwater Wells	67

Figure 38 - Seismic Events and Monitoring Station	69

Subpart RR MRV Plan - O'Neal No. 4

Page 8 of 78

-------
Tables

Table 1 - Expected TAG Composition	3

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo

oil-field brine samples	24

Table 3 - Gas Composition	35

Table 5 - Modeled Injectate Composition	36

Table 6 - GEM Model Layer Package Properties	38

Table 7 - Bottomhole and Wellhead Pressures from the Start of Injection	47

Table 8 - Potential Leakage Pathway Risk Assessment	52

Table 9 - Summary of TAG Detectors and Equipment	53

Table 10 - Summary of Leakage Monitoring Methods	64

Appendices

Appendix A - TRRC O'Neal Gas Unit Well No. 4 Forms

Appendix A-l - GAU Groundwater Protection Determination
Appendix A-2 - Drilling Permit
Appendix A-3 - Completion Report
Appendix A-4 - Plugging Records

Appendix B - Area of Review

Appendix B-l - Oil and Gas Wells Within the MMA List
Appendix B-2 - Water Wells Within the MMA List

Subpart RR MRV Plan - O'Neal No. 4

Page 9 of 78

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SECTION 1 - UIC INFORMATION

This section contains key information regarding the Underground Injection Control (UIC) Permit.

1.1	Underground Injection Control Permit Class: Class II

The TRRC regulates oil and gas activities in Texas and has primacy to implement the Underground
Injection Control (UIC) Class II program. The TRRC classifies the O'Neal No. 4 as a UIC Class II well.
Ozona has applied for a Class II permit for the O'Neal No. 4 under TRRC Rules 36 (Oil, Gas, or
Geothermal Resource Operation in Hydrogen Sulfide Areas) and 46 (Fluid Injection into Productive
Reservoirs).

1.2	UIC Well Identification Number

•	O'Neal No. 4, API No. 42-025-32658, UIC No. 56819

1.3	Facility Address

•	Gas Plant Facility Name: StarTex Pawnee Gas Plant

•	Operator: StarTex Field Services, LLC

•	Coordinates in North American Datum for 1983 (NAD 83) for this facility:

o Latitude: 28.622211
o Longitude: -97.992772

Subpart RR MRV Plan - O'Neal No. 4

Page 10 of 78

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SECTION 2 - PROJECT DESCRIPTION

This section discusses the geologic setting, planned injection process and volumes, and reservoir
and plume modeling performed for the O'Neal No. 4 well.

The O'Neal No. 4 will inject the TAG stream into the Sligo Formation at a depth of 15,874 ft to
16,056 ft, and approximately 14,924 ft below the base of the Underground Source of Drinking
Water (USDW). Therefore, the well and the facility are designed to protect against the leakage
out of the injection interval, to protect against contaminating other subsurface formations, and—
most critically—to prevent surface releases.

2.1 Regional Geology

The O'Neal No. 4 (API No. 42-025-32658) is located in south Texas within the Gulf of Mexico
Basin. The onshore portion of the Gulf of Mexico basin spans approximately 148,049,000 acres
and encompasses portions of Texas, Louisiana, Mississippi, Alabama, Arkansas, Missouri,
Kentucky, Tennessee, Florida, and Georgia to the state-waters boundary of the United States
(Roberts-Ashby et al., 2012). The location of the O'Neal No. 4 is designated by the red star in
Figure 2, relative to the present coastal extent and major structural features of the basin.

Figure 2 - Structural Features of the Guif of Mexico and Locator Map (modified from Roberts-Ashby et

al., 2012)

Subpart RR MRV Plan - O'Neal No. 4

Page 11 of 78

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Figure 3 depicts a generalized stratigraphic column of the U.S. Gulf Coast, with light blue shading
signifying the proposed injection interval and green stars indicating productive formations
identified within 5 miles of the O'Neal No. 4. The injection interval is found within the Sligo
Formation, with confinement provided by the overlying Pearsall Formation and tight underlying
fades of the Lower Sligo and Hosston Formations.

System /
Series

Global
Chronostratigraphic
Units

Calabrian

Piacenzian
Zanclean

Messinian
Tortonian
Serravallian

Langhian
Burdigalian
Aquitanian

Chattian

Rupelian

Priabonian

Bartonian
Lutetian

Ypresian

Thanetian
Selandian
Danian

Maastrichtian

Campanian

Santonian
Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian
Hauterivian

Valanginian
Berriasian

North American
Chronostratigraphic
Units

Middle Mioc. Fleming Fm

Chickasawhayan

Vicksburgian

Jacksonian

Claibornian

Sabinian

Midwayan

Navarroan

Tayloran

Austinian

Eaglefordian

Woodbinian

Washitan-
Fredericksburgian

Trinitian

Nuevoleonian

Durangoan

Stratigraphic Unit

Undifferentiated

Undifferentiated

Upper Mioc.

Anahuac

Fm / Ss " i	-7 Fm

Frio Formation

^X-Catahoula
^ Fm / Rq

Vicksburg Formation

Jackson Group

Sparta Sand

Claiborne Group Cane River Fm

	Carrizo Sand

Wilcox Group

Midway Group

Navarro Group

Taylor Group

Austin Group /
Tokio Formation /
Eutaw Formation

Eagle Ford Shale

Woodbine / Tuscaloosa Fms

Washita Group
(Buda Ls)

Fredericksburg Group i
(Edwards Ls / Paluxy Fm)^

Glen Rose Ls
(Rusk/ Rodessa Fms)

Pearsall Formation |

Sligo^f

Hosston
Formation

Fm

UPPER CONFINING INTERVAL
INJECTION INTERVAL

LOWER CONFINING
INTERVAL

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roherts-Ashby et al.,

2012).

Subpart RR MRV Plan - O'Neal No. 4

Page 12 of 78

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The targeted formations of this study are located entirely within the Trinity Group, as clarified by
the detailed stratigraphic column provided in Figure 4. During this time the area of interest was
located along a broad, shallow marine carbonate platform that extended along the northern rim
of the ancestral Gulf of Mexico. The Lower Cretaceous platform spanned approximately 870 mi
from western Florida to northeastern Mexico, with a shoreline-to-basin margin that ranged
between 45 to 125 mi wide (Yurewicz et al., 1993).

-------
rock found within Cretaceous reef deposits. Deeper, basinward deposits tend to result in tighter
petrophysical properties due to a relative increase in the amount of entrained clay associated
with the heightening of the water column while moving downslope. Backreef deposits have the
potential for porosity development but tend to have low permeability due to a general lack of
wave action caused by restricted access to open water by the platform margin. Facies and
petrophysical properties of the Lower Cretaceous section are anticipated to be relatively
homogenous moving southwest-northwest along reef trend, with increased heterogeneity
moving northwest-southeast due to the orientation of the carbonate rim and its effect on
deposition and facies distributions (Yurewicz et al., 1993).

Figure 5 displays the paleogeography during deposition of the Lower Cretaceous section to
visually demonstrate the position of the O'Neal No. 4 relative to the Sligo shelf margin and updip
extents of Sligo deposition. A generalized schematic cross section of the Trinity Group is provided
in Figure 6, which nearly intersects the project area from the northwest. The schematic illustrates
the gross section thickening basinward, with primary reservoir development improving with
proximity to the reef margin. Figure 7 displays a depositional model of the Lower Cretaceous
carbonate platform to visually conceptualize depositional environments and anticipated
petrophysical properties of facies introduced above.

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the
approximate location of the O'Neal No. 4 (modified from Bebout et al., 1981).

Subpart RR MRV Plan - O'Neal No. 4

Page 14 of 78

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Figure 6 - Generalized northwest to southeast schematic cross section of the Trinity Group, south Texas
(the line of section depicted in Figure 5). The red star and line represent the approximate location of the

O'Neal No. 4 (modified from Kirkland et al., 1987)

0=15-25
K>200

0=10-15
K=20-100

SHOAL

=2-12
K<1

BACKREEF

Windward Fairweather Wave Base

FOREREEF
W CLAY

CLAY-RICH

LEGEND

Sedimentary Structures Grains

Current Ripple
—— Flaser/Wavy Bedding

mm Laminations
—v— Mud Cracks

— Planar and Festoon Bedding
{J Burrow Clay Seam

e Ooid Q) Oyster undiff
• Peloid Bivalve imdiff.
t>Rudist undiff. § Gastropod
(g> Solitary Coral ® Echinoderm
CZ Dictyconus @ Ammonite

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform with estimated porosity and
permeability values of typical facies (modified from Talbert and Atchley, 2000).

2.1.2 Regional Structure and Faulting

The Gulf of Mexico basin was formed by crustal extension and sea-floor spreading associated
with the Mesozoic breakup of Pangea. Rifting of northwest to southeast trending transfer faults
during the Middle Jurassic lasted approximately 25 million years and resulted in variable
thickness of the transcontinental crust underlying the region. By the Lower Cretaceous time, the
general outline and morphology of the Gulf were similar to that of present-day (Galloway, 2008;

Subpart RR MRV Plan - O'Neal No. 4

Page 15 of 78

-------
Yurewicz et al., 1993). Lower Cretaceous tectonic activity was limited to regional subsidence
associated with areas of variable crustal thickness and local structuring caused by movement of
Louann Salt (Yurewicz et al., 1993). The combination of these processes resulted in the structural
development of regional arches, grabens, uplifts, embayments, salt domes, and salt basins
around the northern edge of the basin (Dennen and Hackley, 2012; Galloway, 2008). The location
of these structural features can be referenced in Figures 2 and 8 relative to the location of the
O'Neal No. 4.

The schematic dip-oriented cross section displayed in Figure 9 presents a common interpretation
of the current structural setting. Most of the published literature suggests that faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as displayed in Figure 9,
with shallow faulting dying out before reaching the Pearsall Formation. However, one source did
interpret the potential for faulting to the south (Swanson et al., 2016). The closest potential fault
is depicted in Figure 8 relative to the location of the O'Neal No. 4. According to the map, the
interpreted fault lies approximately 4.25 miles south-southeast of the well and approximately 3.9
miles south-southeast of the stabilized plume extent in the year 2047.

EXPLANATION

I

50

50
_J	

I—r

100 Kilometers

100 Miles
J	I

Uplift

Plateau

Basin

TPS boundary
Fault zone

Lower Cretaceous shelf margin
County line

Field in Edwards Limestone
associated with fault zones

O Salt structure
GOM Gulf of Mexico

Anticlinal axis; large arrow indicates
direction of plunge

Figure 8 - Structural features and fault zones near the proposed injection site. The red star represents
the approximate location of the O'Neal No. 4 (modified from Swanson et al., 2016).

Edwards plateau

Rio Grande
embayment

Subpart RR MRV Plan - O'Neal No. 4

Page 16 of 78

-------
NW

Published
Edwards Ls.
shelf margin

SE

Word field

1 Kilometer

I Edwards Limestone, potential reservoir
facies (shallow-water facies)

~	Pearsall Fm.

~	Sligo Formation, wedges of downslope
debris



Fault

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through Word
field, northeast of the O'Neal No. 4 project area (modified from Swanson et al., 2016).

2.2 Site Characterization

The following section discusses site-specific geological characteristics of the O'Neal No. 4 well.
2.2.1 Stratigraphy and Lithologic Characteristics

Figure 10 depicts openhole logs from two offset wells (API No. 42-025-00473 and API No. 42-025-
31892) to the O'Neal No. 4, indicating the injection and primary upper confining zones. The
Tomasek No. 1 (API No. 42-025-00473) is located approximately 1 mi northeast of the O'Neal No.
4 and displays the shallow section from 0-8,200 ft. The Gordon No. 3 (API No. 42-025-31892) is
located approximately 1.6 mil northeast of the O'Neal No. 4 and displays a shallow section from
8,200-16,400 ft.

Subpart RR MRV Plan - O'Neal No. 4

Page 17 of 78

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AUSTIN
EAGLE_FORD

EDWARDS

COOK_MOUNTAIN

PRSL

SLGO

BB-SOUTHTEX, LLC

TOMASEK GAS UNIT 1

42025004730000

BUQW

BASE_USDW

SPARTA
WECHES_SS

QUEEN_CITY

CARRIZO
WILCOX

PIONEER NATURAL RESOURCES

A. GORDON GAS UNIT 3

42025318920000

MIDWAY

Figure 10 - Type Log with Tops, Confining, and Injection Intervals Depicted

Subpart RR MRV Plan - O'Neal No. 4	Page 18 of 78

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2.2.2 Upper Confining Interval - Pearsall Formation

Following the deposition of the Sligo Formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
Formation throughout the region (Roberts-Ashby et al., 2012). The Pine Island Shale consists of
alternating beds of pelagic mudstone, hemipelagic mudstone, and Fe-rich dolomitic mudstone
interpreted to have been deposited along the outer ramp. This is in agreement with core data
published by Bebout and others (1981), and later by Swanson and others (2016), who identified
the presence of C. Margerelli, a nannofossil indicative of anoxic conditions. The core-derived
porosity-permeability relationship displayed in Figure 11 suggests that the permeability of the
Pine Island Shale is incredibly low and stays below 0.0001 mD, regardless of porosity (Figure 11;
Hull, 2011). This is further supported by the 2012 U.S. Geological Survey (USGS) CO2 Storage
Resource Assessment, which suggests that the Pine Island Shale contains the physical properties
required to act as a regional seal and was chosen as the upward confining interval for their
C50490108 Storage Assessment Unit (SAU) assessment of the Gulf Coast. The 2012 USGS report
also noted that the Pine Island Shale is a sufficient regional seal with as little as 50 feet of
contiguous shale development. The top of the Pearsall is encountered at a depth of 15,339 ft in
the O'Neal No. 4, with a gross thickness of 535 ft (Figure 14). The Pine Island Shale member is
approximately 130 ft thick at the O'Neal No. 4 location, with deposition of additional members
of the overlying Pearsall Formation, which include the Cow Creek Limestone, Cow Creek shale,
and Bexar Shale Members (Roberts-Ashby et al., 2012; Swanson et al., 2016).

The seismic line displayed in Figure 12 runs northwest to southeast across the Stuart City reef
trend southwest of the project area. The top of the Buda, Pearsall, and Sligo Formation markers
are depicted in color to demonstrate the lateral continuity of the section near the O'Neal No. 4.
Seismic reflectors within the Pearsall Formation appear to lack deformation, suggesting
consistent deposition over the reef margin. This is in agreement with reviewed published
literature, which suggests deposition of the Pine Island Shale occurred during widespread marine
transgression (Bebout et al., 1981; Hull, 2011.; Roberts-Ashby et al., 2012, Swanson et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 19 of 78

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Permeability and Porosity-
Crushed Rock Data

0.0001
(100 nd;

~o
E

~ 0.00001
TO (10 nd)

 Top of Pearsall
i TopofSligo

i 5 mi
¦ 10 km

HORIZONTAL SCALE

SliGO
TRENO

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map. The red
star represents the approximate location of the O'Neai No. 4 (modified from Bebout et al., 1981).

2.2.3 Injection Interval - Upper Sligo Formation

Subpart RR MRV Plan - O'Neal No. 4

Page 20 of 78

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The Sligo Formation underlies the Pearsall Formation and is predominately composed of shelf-
edge limestones that were deposited along the Lower Cretaceous platform (Roberts-Ashby et al.,
2012). However, the Cretaceous also experienced episodic changes in sea level that resulted in
the deposition of cyclic Sligo facies that vary both spatially and within the geologic section. The
overall Sligo interval is interpreted to be a transgressive sequence occasionally interrupted by
progradational cycles that consists of porous shoaling-upward sequences that represent primary
reservoir potential within the system (Bebout et al., 1981). Facies distributions of these reef
complexes are heavily impacted by positioning relative to the margin, the height of the water
column at any given time, and the degree of energy or wave action within the system (Galloway,
2008). Figure 13 depicts an idealized environmental setting of the Lower Cretaceous platform
during deposition. Primary porosity and permeability of the upper Sligo Formation tends to
develop in high-energy sequences with normal marine conditions that are dominated by the
deposition of oolitic and skeletal grainstones.

Figure 13 - Environmental Setting of Lower Cretaceous Platform (Bebout et al., 1981)

According to the 2012 USGS CO2 Storage Resource Assessment, "the average porosity in the
porous intervals of the storage reservoir decreases with depth from 9 to 16 percent" for their
C50490108 DEEP SAU assessment of the Gulf Coast (>13,000 feet). The study also reported that
"the average permeability in the storage reservoirs decreases with depth from 0.05 to 200 mD,
with a most-likely value of 8 mD" for their C50490108 DEEP SAU assessment of the Gulf Coast
(Roberts-Ashby et al., 2012).

The top of the upper Sligo is encountered at a depth of 15,874 ft in the O'Neal No. 4 with a gross
thickness of 183 ft (Figure 14). The type log displayed in Figure 14 plots effective porosity for the
confining interval and the total porosity of the injection interval, to account for the increased
volume of shale (Vshale) seen in the Pearsall Formation. The porosity data was compared to the

Subpart RR MRV Plan - O'Neal No. 4

Page 21 of 78

-------
analysis performed by Nutech to generate a permeability curve with a reasonable porosity-
permeability relationship. The permeability curve was generated utilizing the Coates
permeability equation, incorporated with a 20% irreducible to match analysis provided by
Nutech. Petrophysical analysis of the O'Neal No. 4 indicates an average porosity of 4.6%, a
maximum porosity of 15%, an average permeability of 0.16 mD, and a maximum permeability of
3.3 mD. These curves have been extrapolated to the injection site and used to establish reservoir
characteristics in the plume model.

BB-SOUTHTEX, LLC

ONEAL GAS UNIT 4

o

42025326580000

K_COATES2Q
10	0

PHIE

0.3 >0 %	0

DPHI

0.3 > 0 %

Pearsall

Very Low Perm:
Pine Island Shale

Very Low Perm:
Lower Sligo
Formation

Figure 14 - Openhole log from O'Neal No. 4 (API No. 42-025-32658), with porosity curves shaded green
>0%, permeability curve in blue >0 mD, and resistivity in red >5 ohms.

Subpart RR MRV Plan - O'Neal No. 4

Page 22 of 78

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2.2.4 Formation Fluid

The USGS National Produced Waters Geochemical Database version 3.0 was reviewed for
chemical analyses of Sligo oil-field brines within the state of Texas (Blondes et al., 2023). Only
two samples were identified from the Sligo Formation: one located approximately 29 mi north-
northeast in Karnes County and one located approximately 72 mi northeast in Gonzales County.
The locations of these wells are shown in Figure 15 relative to the O'Neal No. 4. A summary of
water chemistry analyses conducted on the two Texas Sligo oil-field brine samples is provided in
Table 2 (page 25).

Averages from the samples were utilized for model assumptions due to the minimal Sligo sample
availability and wide geographic spread of Sligo analysis. Total Dissolved Solids (TDS) of the
samples contain a wide range of reported values but averaged 176,470 parts per million (ppm).
Model sensitivities were established by running iterations with varying TDS values to understand
the effect of brine concentrations on plume extents. The results suggested higher density brine
values lead to smaller plumes; therefore, a value of 150,000 ppm was established in the model
for a conservative approach. If the actual formation fluid sample that will be tested during the
recompletion work produces a material difference in the plume, Ozona will submit an updated
MRV plan.

Based on the results of the investigation, in situ Sligo reservoir fluid is anticipated to contain
greater than 20,000 ppm TDS near the O'Neal No. 4, qualifying the aquifer as saline. These
analyses indicate the in situ reservoir fluid of the Sligo Formation is compatible with the proposed
injection fluids.

Subpart RR MRV Plan - O'Neal No. 4

Page 23 of 78

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Figure 15 - Offset Wells Used for Formation Fluid Characterization

Table 2 - Analysis of Lower Cretaceous (Aptian) age formation fluids from the closest offset Sligo oil-field

brine samples.

Measurement

Karnes County
Sample

Gonzales
County Sample

Average

Total Dissolved Solids (mg/L)

234,646

117,470

176,058

Sodium (mg/L)

51,168

27,909

39,539

Calcium (mg/L)

34,335

8,684

21,510

Chloride (mg/L)

146,500

57,811

102,156

Sample Depth (ft)

13,580 to 13,660

8,290-8,305

-

pH

5.9

8.2

7.05

2.2,5 Fracture Pressure Gradient

The fracture pressure gradient was obtained from an acid fracture report taken during the April
1993 completion of the Sligo interval in the O'Neal No. 4. The Sligo was perforated between the
depths of 15,874 ft and 16,056 ft, with continuous monitoring during pumping of the acid job.
The report noted a pressure break experienced at approximately 9,000 pounds per square inch

Subpart RR MRV Plan - O'Neal No. 4

Page 24 of 78

-------
(psi) arid calculated a fracture gradient of 0.889 psi/ft based on an initial shut-in pressure (ISIP)
of 7,275 psi. A 10% safety factor was then applied to the calculated gradient, resulting in a
maximum allowed bottomhole pressure of 0.8 psi/ft. This was done to ensure that the injection
pressure would never exceed the fracture pressure of the injection zone.

2.2.6 Lower Confining Interval - Lower Sligo and Hosston Formations

The O'Neal No. 4 reaches its total depth in the lower Sligo Formation, directly below the upper
Sligo proposed injection interval. The lower Sligo is interpreted by Bebout and others (1981) to
represent the seaward extension of the low-energy lagoon and tidal-flat system of the underlying
Hosston Formation, a sequence of siliciclastics, evaporites, and dolomitic mudstone (Figure 16).
The Hosston to lower Sligo "contact" represents a gradational package with a decrease in
terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the lower Sligo. The lower Sligo consists of numerous cycles
of subtidal to supratidal carbonates deposited in a low-energy lagoon and tidal-flat system
(Bebout et al1981). These low permeability facies of the lower Sligo and underlying Hosston
Formation will provide lower confinement to the upper Sligo injection interval. Figure 16
illustrates the typical environmental setting forthe deposition of tidal flat facies along the Lower
Cretaceous margin. The type log displayed in Figure 14 (Section 2.2.3) illustrates that the
porosity of the lower Sligo ranges between 0-2% with permeability staying close to 0 mD.
Therefore, the petrophysicall characteristics of the lower Sligo and Hosston are ideal for
prohibiting the migration of the injection stream outside of the injection interval.

Figure 16 - Environmental Setting of Lower Cretaceous Tidal Flat Deposits (Bebout et al., 1981)
2.3 Local Structure

Structures surrounding the proposed sequestration site were influenced by regional arches,
grabens, uplifts, embayments, movement of Louann Salt, and the development of carbonate reef
complexes around the northern edge of the basin. However, one potential fault was identified

Subpart RR MRV Plan - O'Neal No. 4

Page 25 of 78

-------
in the literature within proximity and lies approximately 4.25 mi south-southeast of the well and
approximately 3.9 mi south-southeast of the stabilized plume extent in the year 2062 (Swanson
et al., 2016). The location of these structural features can be referenced in Figures 2 and 8
relative to the location of the O'Neal No. 4.

A subsea true vertical depth (SSTVD) structure map on the top of the Sligo Formation is provided
in Figure 17. The map illustrates the gentle basinward dip of the Sligo from the northwest to the
southeast. The structural cross sections provided in Figures 18 and 19 (pages 28 and 29,
respectively) illustrate the structural changes encountered in moving away from the O'Neal No.
4 site. The figures also demonstrate the laterally continuous nature of the Pearsall Formation
that overlies the injection interval, with sufficient thickness and modeled petrophysical
properties to alleviate the risk of upward migration of injected fluids. Section 2.1.2, discussing
regional structure and faulting, presents a regional discussion pertinent to this topic.

Subpart RR MRV Plan - O'Neal No. 4

Page 26 of 78

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Legend
^ SHL C.I, = 200'

idwards Reef Trend
Sligo Reef Trend

1M00

o Sligo Penetration

-12M0

_

-12200

—

-12400

—

-12600

—

-12800

—

-130W

—

-13200

—

-13400

—

-moo

—

-13800

_



—

-14200

—

-14400

—

-14603

—

-14S00

—

-15000

_

-13200

—

-15400

—

-156M

—

-15SOO

-

-19000

—

-16200

—

-16400

—

-iwoo

—

-16800

—

-17000

—

Figure 17 - Subsea Structure Map: Top of Sligo (injection interval). The red star signifies the location of the O'Neal No. 4.
Subpart RR MRV Plan - O'Neal No. 4	Page 27 of 78

-------
13300
13400
13500
13600
13700
13800
13900
14000
14100
14200
14300
14400

"TOW

14600
14700
14800

15000
15100
15200

15400
15500
15600
15700
15800
15900
16000

16100
16200
16300
16400
16500

16600
16700
16800

| | Injection Reservoir
Color Fill

ASTN

LEGFD

EDRD

PRSL

SLGO

SLGOJNJ
BASE

PRSL

Jpper Confining Zone
(Pearsall Formation)

Injection Reservoir SLGO
(Sligo Formation)

SLGOJNJ
BASE

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200

"WW

13400

13600
13700
13800
13900
TioTO"
14100
14200
14300
14400
14500
14600
14700
14800

w

15000
15100
15200
XM.
15400
15500
15600
15700
15800

imr

16000

16100
16200
16300
16400
16500
16600
16700

13700
13800
13900
14000
14100
14200
14300
14400
14500
14600
14700
14800
14900
15000
15100
15200
15300
15400
I J3BI!I
15600
15700
15800
15900

16100
16200
16300

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200
13300
13400

13600

Logged
cased
hole in
EDRD, „
DPHI
Over-
estimated

CLRS

Figure 18 - Northwest to southeast structural cross section: A-A' Oriented along regional dip.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in red on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 28 of 78

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422973335t00
MCMORAN EX PL CO
DUUAHA N JOSE PHI NE

422973332700
SPARTAN RETRO CORP
STRIDDE OSCAR

14250
14300
14350
14400
14450
14500
14550

14300
14350
14400
14450
14500
14550
14600

14600

"14650'
14700
14750
14800
14850
14900
14950
15000
15050

14650

14700

14750
14800

14350
14900
14950
15000

15050

15100
15150
15200

15100

15150
15200
15250
15300
15350

15250
15300
15350
15400
15450
15500
15550
15600
15650

15400
15450
15500
15550
15600
i^n

15700
15750
15800
15850

15700
15750
15800
15850
15900
15950
16000
ifiren

15900

15950
16000

16050

16100
16150
16200
16250
16300
16350

16100
16150

16200

16250

16300
16350

16400
16450
16500
16550
16600
16650

16400
16450
16500
16550
16600
16650
16700
16750
16800
16850

16700
16750
16800
16850
16900
16950
17000
17050
17100

420253285800
BB-SOUiHTEX LLC
OVERB Y CMftRLI E C GA

14400
14450
14500
14550
14600
14650
14700
14750
14800
14850
14900
14950
15000
15050
15100
15150
15200
15250
15300

14450
14500
14550
14600
14650
14700
14750

14850
14900
14950
15000
15050
15100

estimated

15150
15200
15250
15300
15350
15400
15450

"T535TT
15400
15450
15500
15550
15600

15500

15550
15600
15650
15700
15750
15800
15850
15900
15950

15700

15750
15800
15850

15900
15950
16000
16050
16100
16150
16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750
16800
16850
16900
16950
17000
17050
17100
17150
17200
17250

16000
16050
16100
16150

16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750
16800
16850
16900
16950
17000
17050
17100
17150
17200
17250

KARNES

ATASCOSA

~ Injection Reservoir
Color Fill

GLRS

GLRS

PRSL

SLGO

SLGOJN
BASE

PRSL

Upper Confining Zone
(Pearsall Formation)

SLGO

Injection Reservoir
(Sligo Formation)

ASTN
LEGFD

BUDA

DLRO
EDRD

SLGO_INJ
BASE

Logged

cased

hole in

EDRD,

DPHI

Over-

16900
16950
17000
17050
171Q0

Figure 19 - Southwest to northeast structural cross section: B-B' oriented along regional strike.

The red star signifies the location of the O'Neal No. 4, with the section line depicted in blue on the locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 29 of 78

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2.4 Injection and Confinement Summary

The lithologic and petrophysical characteristics of the Sligo Formation at the O'Neal No. 4 well
location indicate that the reservoir contains the necessary thickness, porosity, and permeability to
receive the proposed injection stream. The overlying Pearsall Formation is regionally extensive at
the O'Neal No. 4 with low permeability and sufficient thickness to serve as the upper confining
interval. Beneath the injection interval, the low permeability, low porosity facies tidal flat, and
lagoonal facies of the lower Sligo and underlying Hosston Formation are unsuitable for fluid
migration and serve as the lower confining interval.

2.5 Groundwater Hydrology

Bee County falls within the boundary of the Bee Groundwater Conservation District. Only one
aquifer is identified by the Texas Water Development Board's Texas Aquifers Study near the O'Neal
No. 4 well location, the unconfined to semi-confined Gulf Coast aquifer. The Gulf Coast aquifer
parallels the Gulf of Mexico and extends across the state of Texas from the Mexican border to the
border of Louisiana (Bruun et al., 2016). The extents of the Gulf Coast aquifer are provided in Figure
20 for reference.

The Gulf Coast aquifer is a major aquifer system comprised of several individual aquifers: the Jasper,
Evangeline, and Chicot. These aquifers are composed of discontinuous clay, silt, sand, and gravel
beds that range from Miocene to Holocene in age (Figure 21, page 32). Numerous interbedded
lenses and layers of silt and clay are present within the aquifers, which can confine individual aquifers
locally. The underlying Oligocene Catahoula tuff represents the lower confining interval, but it
should be noted that the formation is prone to leaking along the base of the aquifer. However, the
Burkeville confining interval provides isolation between Jasper and Evangeline aquifers which helps
protect the shallower Evangeline and Chicot Aquifers (Bruun et al., 2016).

The schematic cross section provided in Figure 22 (page 32) runs south of the O'Neal No. 4,
illustrating the structure and stratigraphy of the aquifer system. The thickness of individual
sedimentary units within the Cenozoic section tends to thicken towards the Gulf of Mexico due to
the presence of growth faults that allow additional loading of unconsolidated sediment. The total
net sand thickness of the aquifer system ranges between 700 ft of sand in the south, to over 1,300
ft in the north, with the saturated freshwater thickness averaging 1,000 ft.

The water quality of the aquifer system varies with depth and locality but water quality generally
improves towards the central to northeastern portions of the aquifer where TDS values are less than
500 milligrams per liter (mg/L). The salinity of the Gulf Coast aquifer increases to the south, where
TDS ranges between 1,000 mg/L to more than 10,000 mg/L. The Texas Water Development Board's
Texas Aquifers Study (2016) suggests that areas associated with higher salinities are possibly
associated with saltwater intrusion likely "resulting from groundwater pumping or to brine migration
in response to oil field operations and natural flows from salt domes intruding into the aquifer"
(Bruun et al., 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 30 of 78

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According to the IDS map of the Gulf Coast aquifer (Figure 23), the TDS in northern Bee County
range between 500-3,000 mg/L near the O'Neal No. 4, categorizing the aquifer as fresh to slightly
saline.

The TRRC's Groundwater Advisory Unit (GAU) identified the Base of Useable Quality water (BUQW)
at a depth of 250 ft and the base of the USDW at a depth of 950 ft at the location of the O'Neal No.
4. Approximately 14,924 ft is therefore separating the base of the USDW and the injection interval.
(A copy of the GAU's Groundwater Protection Determination letter issued by the TRRC as part of the
Class II permitting process for the O'Neal No. 4 is provided in Exhibit A-l.) The base of the deepest
aquifer is separated from the injection interval by more than 14,924 ft of rock, including 4,200 feet
of Midway shale. Though unlikely for reasons outlined in the sections here on confinement and
potential leaks, if the migration of injected fluid did occur above the Pearsall Formation, thousands
of feet of tight sandstone, limestone, shale, and anhydrite beds occur between the injection interval
and the lowest water-bearing aquifer.

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of the
O'Neal No. 4 (modified from Bruun, B., et al., 2016)

Subpart RR MRV Plan - O'Neal No. 4

Page 31 of 78

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Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury and Turco, 2006)

s



•1,000-



2,000

		.



0)

-3,000

c



o

CO
>
Q)
UU

-4,000

-5,000-
-6,000-
-7,000-

Figure 22 - Cross Section S-S' Across the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No, 4 (modified from Bruun et al., 2016)

S'

25 Miles

Chicot Aquifer

Evangeline Aquifer

Subpart RR MRV Plan - O'Neal No. 4

Page 32 of 78

-------
Freestone1

,nderson

Brown

Hamilton

lacogdoche]

McLennan Limestoro

Coryell

Houston

Angelina

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Hardin

Travis

Montgomery

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Austin

Harris

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Brazoria

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¦ Miles

Total dissolved solids (milligrams per liter)

1-1,000 Fresh	1,000-3,000 Slighty saline	3.000-10,000 Moderately saline	10,000-35,000 Very saline

^ State boundary | | County boundary | j Aquifer boundary

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No, 4 (modified from Bruun et al,, 2016).

Subpart RR MRV Plan - O'Neal No. 4

Page 33 of 78

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2.6 References

Bebout, D.G., Budd, D.A., and Schatzinger, R.A. (1981). Depositional and Diagenetic History of the
Sligo and Hosston Formations (Lower Cretaceous) in South Texas: The University of Texas at
Austin, Bureau of Economic Geology, Report of Investigations No. 109.

Blondes, M.S., Gans, K.D., Engle, M.A. et al. (2018). U.S. Geological Survey National Produced Waters
Geochemical Database (Ver. 2.3, January 2018): U.S. Geological Survey data release,
https://doi.org/10.5066/F7J964W8.

Bruun, B., Anaya, R., Boghici, R. et al. (2016). Texas Aquifers Study: Chapter 6, Gulf Coast Aquifers.

Chowdhury, A.H. and Turco, M.J. (2006). Geology of the Gulf Coast Aquifer, Texas. In: Mace, R.E., et
al., Eds., Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report.

Dennen, K.O. and Hackley, P.C. (2012). Definition of Greater Gulf Basin Lower Cretaceous and Upper
Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico
basin onshore and state waters: https://pubs.usgs.gov/publication/70176229.

Galloway, W.E. (2008). Sedimentary Basins of the World, Chapter 15: Depositional Evolution of the
Gulf of Mexico Sedimentary Basin, 505-549.

Hull, D.C. (2011). Stratigraphic Architecture, Depositional Systems, and Reservoir Characteristics of
the Pearsall Shale-Gas System, Lower Cretaceous, South Texas: Thesis for M.S. of Science in
Geology, University of Texas, Austin.

Kirkland, B.L., Lighty, R.G., Rezak, R., and Tieh, T.T. (1987). Lower Cretaceous barrier reef and outer
shelf facies, Sligo Formation, south Texas, United States.

Roberts-Ashby, T.L., Brennan, S.T., Buursink, M.L. et al. (2012). Geologic framework for the national
assessment of carbon dioxide storage resources: U.S. Gulf Coast. USGS.

Swanson, S.M., Enomoto, C.B., Dennen, K.O. et al. (2017). Geologic assessment of undiscovered oil
and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate
rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain
and State Waters: U.S. Geological Survey Open-File Report 2016-1199, 69 p.,
https://doi.org/10.3133/ofr20161199.

Talbert, S.J. and Atchley, S.J. (2000). Sequence Stratigraphy of the Lower Cretaceous (Albian)
Fredericksburg Group, Central and North Texas: Department of Geology, Baylor University,
Waco, Texas 76798.

Yurewicz, D.A., Marler, T.B., Meyerholtz, K.A., and Siroky, F.X. (1993). Early Cretaceous Carbonate
Platform, North Rim of the Gulf of Mexico, Mississippi, and Louisiana.

2.7 Description of the Injection Process

Subpart RR MRV Plan - O'Neal No. 4

Page 34 of 78

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2.7.1 Current Operations

The Pawnee Gas Plant and the O'Neal No. 4 are existing operating assets. The O'Neal No. 4 will be
recompleted for acid gas injection service under the Class II permit process. Under the Class II
application, the maximum injection rate is 28 MT/yr (1.5 MMscf/d). The TAG is 98.2% CO2, which
equates to 27.5 MT/yr of CO2 each year. The current composition of the TAG stream is displayed in
Table 3:

Table 3 - Gas Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

The plant is designed to treat, dehydrate, and compress the natural gas produced from the
surrounding acreage in Bee County. The plant uses an amine unit to remove the CO2 and other
constituents from the gas stream. The TAG stream is then dehydrated, compressed, and routed
directly to the O'Neal No. 4 for injection. The remaining gas stream is processed to separate the
natural gas liquids from the natural gas. The plant is monitored 24 hours per day, 7 days per week.

2.8 Reservoir Characterization Modeling

The modeling software used to evaluate this project was Computer Modelling Group, Ltd.'s GEM
2023.2 (GEM) simulator, one of the most comprehensive reservoir simulation software packages for
conventional, unconventional, and secondary recovery. The GEM utilizes equation-of-state (EOS)
algorithms in conjunction with some of the most advanced computational methods to evaluate
compositional, chemical, and geochemical processes and characteristics. This results in the creation
of exceedingly precise and dependable simulation models for carbon injection and storage. The
GEM model holds recognition from the EPA for its application in the delineation modeling aspect of
the area of review, as outlined in the Class VI Well Area of Review Evaluation and Corrective Action
Guidance document.

The Sligo Formation serves as the target formation for the O'Neal No. 4 (API No. 42-025-32658).
The Petra software package was utilized to construct the geological model for this target formation.
Within Petra, formation top contours were generated and subsequently brought into GEM to
outline the geological structure.

Porosity and permeability estimates were determined using the porosity log from the O'Neal No. 4.
A petrophysical analysis was then conducted to establish a correlation between porosity values and
permeability, employing the Coates equation. Both the porosity and permeability estimates from
the O'Neal No. 4 were incorporated into the model, with the assumption that they exhibit lateral
homogeneity throughout the reservoir.

Subpart RR MRV Plan - O'Neal No. 4

Page 35 of 78

-------
The reservoir is assumed to be at hydrostatic equilibrium. Given the geological formation in which
this well is located and its previous history as a gas producer, the model is assumed to be primarily
saturated with gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine
saturated, as deduced from the well log data. The modeled injection interval exhibits an average
permeability of 0.23 mD and an average porosity of 5%. All layers within the model have been
perforated. An infinite-acting reservoir has been created to simulate the boundary conditions.

The gas injectate is composed predominantly of CO2 as shown in Table 4. The modeled composition
takes into consideration the carbon dioxide and other constituents of the total stream. As the plant
has been in operation for many years, the gas composition for the proposed injection period is
expected to remain constant.

Table 4- Modeled Injectate Composition

Component

Expected Composition
(mol %)

Modeled
Composition (mol %)

Carbon Dioxide (CO2)

98.2

98.2

Hydrocarbons

1.03%

Hydrocarbons

Hydrogen Sulfide

0.4%

Hydrogen Sulfide

Nitrogen

0.37%

Nitrogen

Core data from the literature review was used to determine residual gas saturation (Keelan and
Pugh, 1975) and relative permeability curves between carbon dioxide and the connate brine within
the Sligo carbonates (Bennion and Bachu, 2010). The Corey-Brooks method was used to create
relative permeability curves. The key inputs used in the model include a Corey exponent for brine
of 1.8, a Corey exponent for gas of 2.5, gas permeability at irreducible brine saturation of 50%,
irreducible water saturation of 20%, and a maximum residual gas saturation of 35%. The relative
permeability curves used for the GEM model are shown in Figure 24.

Subpart RR MRV Plan - O'Neal No. 4

Page 36 of 78

-------
Two-Phase (C02/Brine) Relative Permeability Curves
O'Neal No. 4 Sligo Formation

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model

The grid contains 81 blocks in the x-direction (east-west) and 81 blocks in the y-direction (north-
south), resulting in a total of 6,561 grid blocks per layer. Each grid block spans dimensions of 250 ft
x 250 ft. This configuration yields a grid size measuring 20,250 ft x 20,250 ft, equating to just under
15 square miles in area. The grid cells in the vicinity of the O'Neal No. 4, within a radius of 0.5 mi,
have been refined to dimensions of 83.333 ft x 83.333 ft in all layers. This refinement is employed
to ensure a more accurate representation of the plume and pressure effects near the wellbore.

In the model, each layer is characterized by homogeneous permeability and porosity values. These
values are derived from the porosity log of the O'Neal No. 4. The model encompasses a total of 61
layers, each featuring a thickness of approximately 3 ft per layer. As previously mentioned, the
model is perforated in each layer, with the top layer being the top of the injection interval and the
bottom layer being the lowest portion of the injection interval. The summarized property values for
each of these packages are displayed in Table 5.

Subpart RR MRV Plan - O'Neal No. 4

Page 37 of 78

-------
Table 5 - GEM Model Layer Package Properties

Layer #

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

1

15,874

3

0.004

3.75%

2

15,877

3

0.002

2.98%

3

15,880

3

0.001

1.62%

4

15,883

3

0.001

1.78%

5

15,886

3

0.002

2.32%

6

15,889

3

0.001

1.96%

7

15,892

3

0.002

3.10%

8

15,895

3

0.002

2.99%

9

15,898

3

0.003

3.52%

10

15,901

3

0.006

4.00%

11

15,904

3

0.005

3.93%

12

15,907

3

0.001

2.15%

13

15,910

3

0.001

1.99%

14

15,913

3

0.002

2.97%

15

15,916

3

0.001

2.22%

16

15,919

3

0.002

2.88%

17

15,922

3

0.001

2.38%

18

15,925

3

0.093

6.68%

19

15,928

3

0.005

2.62%

20

15,931

3

0.002

2.58%

21

15,934

3

0.003

3.07%

22

15,937

3

0.006

3.62%

23

15,940

3

0.002

2.68%

24

15,943

3

0.001

1.08%

25

15,946

3

0.002

1.87%

26

15,949

3

0.025

4.70%

27

15,952

3

0.024

4.37%

28

15,955

3

0.001

1.97%

29

15,958

3

0.003

2.27%

30

15,961

3

0.007

3.09%

31

15,964

3

0.110

6.75%

32

15,967

3

0.037

5.62%

33

15,970

3

0.011

4.41%

34

15,973

3

0.022

4.59%

35

15,976

3

0.297

7.88%

36

15,979

3

0.440

9.21%

37

15,982

3

0.060

5.90%

38

15,985

3

0.001

2.22%

Subpart RR MRV Plan - O'Neal No. 4

Page 38 of 78

-------
39

15,988

3

0.001

2.21%

40

15,991

3

0.001

1.12%

41

15,994

3

0.003

2.05%

42

15,997

3

0.014

4.56%

43

16,000

3

0.007

4.15%

44

16,003

3

0.033

5.95%

45

16,006

3

1.233

10.25%

46

16,009

3

1.476

12.04%

47

16,012

3

0.566

10.08%

48

16,015

3

1.679

12.18%

49

16,018

3

2.194

13.08%

50

16,021

3

1.235

12.02%

51

16,024

3

0.788

11.22%

52

16,027

3

0.944

10.48%

53

16,030

3

0.424

9.05%

54

16,033

3

0.378

8.85%

55

16,036

3

0.378

8.81%

56

16,039

3

0.378

8.84%

57

16,042

3

0.736

9.91%

58

16,045

3

0.232

7.94%

59

16,048

3

0.238

7.97%

60

16,051

3

0.012

3.01%

61

16,054

3

0.038

4.30%

2.8.1 Simulation Modeling

The primary objectives of the model simulation were as follows:

1.	Estimate the maximum areal extent and density drift of the injectate plume after injection.

2.	Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone.

3.	Assess the likelihood of the injectate plume migrating into potential leak pathways.

The reservoir is assumed to have an irreducible brine saturation of 20%. The salinity of the brine
within the formation is estimated to be 150,000 ppm (USGS National Produced Waters Geochemical
Database, Ver. 2.3), typical for the region and formation. The injectate stream is primarily composed
of CO2 and H2S as stated previously. Core data from the literature was used to help generate relative
permeability curves. From the literature review, also as previously discussed, cores that most
closely represent the carbonate rock formation of the Sligo seen in this region were identified, and
the Corey-Brooks equations were used to develop the curves (Bennion and Bachu, 2010). A low,
conservative residual gas saturation based on the cores from the literature review was then used to
estimate the size of the plume (Keelan and Pugh, 1975).

Subpart RR MRV Plan - O'Neal No. 4

Page 39 of 78

-------
The model is initialized with a reference pressure of 10,995 psig at a subsea depth of 15,740 ft. This,
when a Kelly Bushing "KB" elevation of 334 ft is considered, correlates to a gradient of 0.684 psi/ft.
This pressure gradient was determined from production data of the O'Neal No. 4. An initial reservoir
pressure of 0.76 psi/ft was calculated before initial production. However, in 1997, after producing
approximately 0.5 billion cubic feet (Bcf) of gas, the well was shut in. The last bottomhole pressure
reading was calculated to be 0.480 psi/ft. This assumes the reservoir repressurizes after production
ceases, but not fully back to in situ conditions. Therefore, a 10% safety factor was given to the initial
reservoir pressure gradient of 0.76 psi/ft, and a gradient of 0.684 psi/ft was implemented into the
model as a conservative estimate. A skin factor of -2 was applied to the well to simulate the
stimulation of the O'Neal No. 4 for gas production from the Sligo Formation, which is based on the
acid fracture report, provided in Appendix A-3.

The fracture gradient of the injection zone was estimated to be 0.954 psi/ft, which was determined
from the acid fracture report. A 10% safety factor was then applied to this number, putting the
maximum bottomhole pressure allowed in the model at 0.86 psi/ft, which is equivalent to 13,652
psig at the top of the Sligo injection interval.

The model, which begins in January 2025, runs for a total of 22 years, comprising 12 years of active
injection, and is then succeeded by 10 years of density drift. Throughout the entire 12-year injection
period, an injection rate of 1.5 MMscf/D is used to model the maximum available rate, yielding the
largest estimate of the plume size. After the 12-year injection period, when the O'Neal No. 4 ceases
injection, the density drift of the plume continues until the plume stabilizes 10 years later. The
maximum plume extent during the 12-year injection period is shown in Figure 25. The final extent
after 10 years of density drift after injection ceases is shown in Figure 26 (page 42).

Subpart RR MRV Plan - O'Neal No. 4

Page 40 of 78

-------
C02 Saturation at End of Injection

283750 -

282500 -

281250

280000 -

0.80- js

0.70

0.60

-0.50

-0.40

-0.30

-0.20

|o.,o

		0.03-1

278750 —	Actual Scale: 1:0

Y/X: 1:1
Axis Units: ft
Total Blocks: 459.26P
Active Blocks: 459.269

	I	I	I	I	I

2316000	2318000	2320000	2322000	2324000	2326000

Figure 25 - Areal View of Saturation Piume at Shut-in (End of injection)

Subpart RR MRV Plan - O'Neal No. 4

Page 41 of 78

-------
CO, Saturation at End of Simulation

1	i	i

283750 -

282500 -

281250 -

280000 -

278750

o 80 H

0.70

-0.60

-0.50

-0.40

-0.30

J™-0.20
0.10

0.03

Actual Scale: 1:0
Y/X: 1:1
Axis Units: ft
Total Blocks: 459,269
Active Blocks: 459.269

I

2320000

I

2324000

2316000

I

2318000

' ' ' I
2322000

' ' ' I
2326000

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal No. 4

Page 42 of 78

-------
The cross-sectional view of the O'Neal No. 4 shows the extent of the plume from a side-view angle,
cutting through the formation at the wellbore. Figure 27 shows the maximum plume extent during
the 12-year injection period. During this time, gas from the injection well is injected into the
permeable layers of the formation and predominantly travels laterally. Figure 28 (page 45) shows
the final extent of the plume after 10 years of migration. Then, the effects of residual gas saturation
and migration due to density drift are clearly shown. At least 35% of injected gas that travels into
each grid cell is trapped, as the gas travels mostly vertically—as it is less dense than the formation
brine—until an impermeable layer is reached. Both figures are shown in an east-to-west view.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 43 of 78

-------
C02 Saturation at End of Injection

15500 -

15563 -

15625 -

15688 -

15750 -

15813 -

0.80-1

-0.70

-0.60

0.50

-0.40

-0.30

-0.20

-0.10

0.03-1

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical Sice: 2 of 3
Total Blocks: 459.269
Active Blocks: 459.269

r

2319000

2321000

West

2323000

East

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 44 of 78

-------
C02 Saturation at End of Simulation

15500

15563 -

15625 -

15688 -

15750

15813 -

0.80-=i

0.70

0.60

-0.50

0.40

0.30

-0.20

1-0.10

0.03

Actual Scale: 1:0
Z/X: 7.9:1
Axis Units: ft
Logical 9ce: 2 of 3
Total Bocks: 459,269
Active Blocks: 459.269

2319000

2321000

West

2323000

East

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 45 of 78

-------
Figure 29 shows the surface injection rate, bottom hole pressures, and surface pressures over the
injection period—and the period of density drift after injection ceases. The bottomhole pressure
increases the most as the injection rate ends, reaching a maximum pressure of 13,337 psig, at the
end of injection. This buildup of 2,362 psig keeps the bottomhole pressure below the fracture
pressure of 13,652 psig. The maximum surface pressure associated with the maximum bottomhole
pressure reached is 6,095 psig, well below the maximum allowable 7,937 psig per the TRRC UIC
permit application for this well. Bottomhole and wellhead pressures are provided in Table 6.

2,000,000

1,750,000

_ 1,500,000
¦a

jn 1,250,000
O)

4-»

1,000,000

£
o

y 750,000

.«

'E

— 500,000
250,000
0

10

Time (years)

15

20















































		









	





































16,000

12,000

10,000

8,000 fg

"D

6,000 ~

4,000
2,000
0

• Gas Rate (scf/d)

• BHP (psig)

WHP (psig) — — —BHP Constraint (psig) — — — WHP Constraint (psig)

Figure 29-Well Injection Rate and Bottomhole and Surface Pressures Over Time

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 46 of 78

-------
Table 6 - Bottomhole and Wellhead Pressures from the Start of Injection

Time from Start of Injection
(years)

BHP (psig)

WHP (psig)

0

10,975

-

10

13,311

6,073

12 (End of Inj.)

13,337

6,095

20

11,029

-

22 (End of Model)

11,013

-

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 47 of 78

-------
SECTION 3 - DELINEATION OF MONITORING AREA

This section discusses the delineation of both the maximum monitoring area (MMA) and active
monitoring area (AMA) as described in 40 CFR §98.448(a)(1).

3.1 Maximum Monitoring Area

The MMA is defined as equal to or greater than the area expected to contain the free-phase CO2
plume until the plume has stabilized, plus an all-around buffer zone of at least one half mile.
Numerical simulation was used to predict the size and drift of the plume. With CMG's GEM software
package, reservoir modeling was used to determine the areal extent and density drift of the plume.
The model considers the following:

•	Offset well logs to estimate geologic properties

•	Petrophysical analysis to calculate the heterogeneity of the rock

•	Geological interpretations to determine faulting and geologic structure

•	Offset injection history to predict the density drift of the plume adequately

Ozona's expected gas composition was used in the model. The injectate is estimated at a molar
composition of 98.2% CO2 and 1.8% of other constituents. The StarTex Plant has been in stable
operations for many years. Ozona believes the gas analysis provided in Table 1 is an accurate
representation of the injectate. In the future, if the actual gas analysis varies materially from the
injectate composition herein, an update to this MRV plan will be submitted to the GHGRP. As
discussed in Section 2, the gas will be injected into the Sligo Formation. The geomodel was created
based on the rock properties of the Sligo.

The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of
3% gas saturation was used to determine the boundary of the plume. When injection ceases in Year
12, the area expanse of the plume will be approximately 270 acres. The maximum distance between
the wellbore and the edge of the plume is approximately 0.42 mi to the west. After 10 additional
years of density drift, the areal extent of the plume is 303 acres with a maximum distance to the
edge of the plume of approximately 0.45 mi to the west. Since the plume shape is relatively circular,
the maximum distance from the injection well after density drift was used to define the circular
boundary of the MMA. The AMA and the MMA have similar areas of influence, with the AMA being
only marginally smaller than the MMA. Therefore, Ozona will set the AMA equal to the MMA as the
basis for the area extent of the monitoring program.

This is shown in Figure 30 with the plume boundary at the end of injection, the stabilized plume
boundary, and the MMA. The MMA boundary represents the stabilized plume boundary after 10
years of density drift plus an all-around buffer zone of one half mile.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 48 of 78

-------
OaN#dl Git Unit MA
UtiimuM Moniloiinq Airj

O/on CCS UC
*#~ CMnly, I*
t»*w>brVt |lUf	| Aptxcvtdby H?

ft* HAD IW7 St«<» TX V C^erfijl »IT» 4 AM (US ft i

LONQUIST
y Que sir ah w ;

Hi

+ CTNmI GasUr* *4

FVjme Extent (StaWittd. 2047)

Maximum Morueonng Arco (1/2-Hie
1 "11 Buffer from Plume Extent 9
StsWiXJbon)

Abstracts

1:12,500
0

MVExma

1 1 Rume Extent (End of Injection, 2037)

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 49 of 78

-------
3.2 Active Monitoring Area

The AMA was initially set equal to the expected total injection period of 12-years. The AMA was
analyzed by superimposing the area based on a one-half mile buffer around the anticipated plume
location after 12 years of injection (2037), with the area of the projected free-phase CO2 plume at
five additional years (2042). In this case, as shown in Figure 31, the plume boundary in 2042 is within
the plume in 2037 plus the one-half mile buffer. Since the AMA boundary is only slightly smaller
than the MMA boundary, Ozona will define the AMA to be equal to the MMA. By 2037, Ozona will
submit a revised MRV plan to provide an updated AMA and MMA.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 50 of 78

-------
Figure 31 - Active Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 51 of 78

-------
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE

This section identifies and discusses the potential pathways within the MMA for CO2 to reach the
surface and is summarized in Table 7. Also included are the likelihood, magnitude, and timing of
such potential leakage. The potential leakage pathways are:

•	Surface equipment

•	Existing wells within the MMA

•	Faults and fractures

•	Upper confining layer

•	Natural or induced seismicity

Table 7 - Potential Leakage Pathway Risk Assessment

Potential Leakage Pathway

Likelihood

Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low. Automated systems
will detect leaks and
execute shut-down
procedures.

During active injection
period. Thereafter the
well will be plugged.

Existing wells within the MMA

Unlikely. One artificial
penetration was drilled
into the injection interval.
This well has been plugged
and abandoned.

Low. Vertical migration of
C02 would likely entera
shallower hydrocarbon
production zone.

During active injection
and post Injection site
care2 period.

Faults and fractures

Possible. The lateral
continuity of UCZ1 is
recognized as a very
competent seal.

Low. Vertical migration of
C02 would likely entera
shallower hydrocarbon
production zone.

During active injection
and post Injection site
care2 period.

Upperconfining layer

Unlikely. The lateral
continuity of the UCZ is
recognized as a very
competent seal.

Low. Vertical migration of
C02 would likely enter a
shallower hydrocarbon
production zone.

During active injection
and post Injection site
care2 period.

Natural or induced seismicity

Possible. The lateral
continuity of the UCZ is
recognized as a very
competent seal.

Low. Vertical migration of
C02 would likely entera
shallower hydrocarbon
production zone.

During active injection
and post Injection site
care2 period.

1	- UCZ is defined as the upper confining zone.

2	- Post injection site care is the period of time from the end of injection throught plume stabilization and

site closure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 52 of 78

-------
Magnitude Assessment Description

Low - catergorized as little to no impact to safety, health and the environment and the costs to mitigate

are minimal.	

Medium - potential risks to the USDW and for surface releases does exist, but circumstances can be

	easily remediated.	

High - dangerto the USDW and significant surface release may exist, and if occurs this would require
	significant costs to remediate.	

4.1 Leakage from Surface Equipment

The Pawnee Gas Plant and O'Neal No. 4 are designed for separating, transporting, and injecting TAG,
primarily consisting of CO2, in a manner to ensure safety to the public, the employees, and the
environment. The mechanical aspects of this are noted in Table 8 and Figure 32. The facilities have
been designed to minimize leakage and failure points, following applicable National Association of
Corrosion Engineers (NACE) and American Petroleum Institute (API) applicable standards and
practices. As the TAG stream contains H2S, monitors installed for H2S detection will also indicate
the presence of CO2. These monitors will be installed at key locations around the Plant and the
O'Neal No. 4 location. These devices will be continuously monitored by the Supervisory Control and
Data Acquisition (SCADA) system and will alarm at set points determined by the plant's Health,
Safety and Environment (HS&E) Director, consistent with Occupational Safety and Health
Administration (OSHA) requirements. The plant will set the detection and alarm states for personnel
at 10 ppm and at 40 ppm for initiating Emergency Shutdown. Key monitoring points and parameters
are also provided in Table 8.

The facilities will incorporate important safety equipment to ensure reliable and safe operations. In
addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-pressure
shutoff settings to isolate the plant, the O'Neal No. 4, and other components, StarTex has a flare
stack to safely handle the TAG when a depressuring event occurs. These facilities will be constructed
in the coming months. The exact location of this equipment is not yet known, but it will be installed
in accordance with applicable engineering and safety standards.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 53 of 78

-------
Table 8 - Summary of TAG Detectors arid Equipment

Device

Location

Set Point

H2S Detectors (1-4)

O'Neal No. 4 wellsite

10 ppm High Alarm

40 ppm Emergency Shutdown

H2S Detectors (5-8)

In-Plant Detectors

10 ppm High Alarm

40 ppm Emergency Shutdown

Flare Stack

Plant Site Perimeter

N/A

AGI Flowmeter

In-Plant (downstream of the
Amine Unit)

Calibrated per API specifications

Emergency Shutdown

In-Plant Detectors

40 ppm Emergency Shutdown

Emergency Shutdown

O'Neal No. 4 wellsite

40 ppm Emergency Shutdown

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 54 of 78

-------
Wf

flBL





SH:

sssv

Casing/Tubing Information

La 0*1

1

2

S

4

6

Type

Ccn&Mfc*



ntwrmdtfa

ProtfucSon Uw

TuMng

oo



10-3M-

7-5.-T

5* (new)

5" («d)

2-3,8*

©



9.760*

6 625*

4.276*

4-276"

1-867"

ortnio



9 SO**

6 50C*

4.151*

4.151*

1.773*

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11.750*

8.500*

5 563*

5 563*

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55 5 M

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18.0 Alt

18 0 felt

5 8 Mt

Grade



S-95

CY-95

P-110

Q-125

L-80

Hole
Size

N'A

M-3M"

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Ozona CCS

Country: USA

API No: 42-025-32668

C02 Injection Well
Proposed Well Design - O'Neal Gas Unit No. 4

State/Province: Texas

Field: TBD

County/Parish: Bee County

Well Type/Status: Proposed

Texas License F-S652

Location: 28 6031807. -SS.0017091

Project No: LS190

Date: 10/13/2023

12912 HI Coutry &va 5* =-200
Austr "or "8738
Te 512.732-9012
sar 512 732.9816

Drawn: Joseph Lovewel

Reviewed: David Lytie

Approved: David Lytie

Rev No: 0

Notes:

Figure 32 - O'Neal No. 4 Wellbore Schematic

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 55 of 78

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With the continuous air monitoring at the plant and the well site, a release of CO2 would be quickly
identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The CO2 injected into the O'Neal No. 4 is from the amine
unit at the Pawnee Gas Plant. If any leakage were to be detected, the volume of CO2 released would
be quantified based on the operating conditions at the time of release, as stated in Section 7, in
accordance with 40 CFR §98.448(a)(5). Ozona concludes that the leakage of CO2 through the surface
equipment is unlikely.

4.2 Leakage Through Existing Wells Within the MMA

The O'Neal No. 4 is engineered to prevent migration from the injection interval to the surface
through a special casing and cementing design as depicted in the schematic provided in Figure 32.
Mechanical integrity tests (MITs), required under Statewide Rule (SWR) §3.46 [40 CFR §146.23
(b)(3)], will take place every 5 years to verify that the well and wellhead can contain the appropriate
operating pressures. If the MIT were to indicate a leak, the well would be isolated and the leak
mitigated to prevent leakage of the injectate to the atmosphere.

A map of all oil and gas wells within the MMA is shown in Figure 33. Figure 34 is a map of all the oil
and gas wells that penetrate the MMA's gross injection zone. Only one well penetrated the MMA's
gross injection zone. This well was non-productive and has been plugged and abandoned in
accordance with TRRC requirements. A summary table of all oil and gas wells within the MMA is
provided in Appendix B-l.

This table in Appendix B-l provides the total depth (TD) of all wells within the MMA. The wells that
are shallower and do not penetrate the injection zone are separated by the Pearsall Formation with
a gross thickness of 535 ft. The Pine Island Shale comprises approximately 130 ft of this interval as
discussed in Section 2.2.2, and provides a competent regional seal—making vertical migration of
fluids above the injection zone unlikely.

The shallower offset hydrocarbon wells within the MMA will also serve as above zone monitoring
wells. Should any of the sequestered volumes migrate vertically, they would potentially enter the
shallower hydrocarbon reservoir. Regular sampling and analysis is performed on the produced
hydrocarbons. If a material difference in the quantity of CO2 in the sample occurs indicating a
potential migration of injectate from the Sligo Formation, Ozona would investigate and develop a
mitigation plan. This may include reducing the injection rate or shutting in the well. Based on the
investigation, the appropriate equation in Section 7 would be used to make any adjustments to the
reported volumes.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 56 of 78

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Figure 33 - All Oil and Gas Weils Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 57 of 78

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 58 of 78

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4.2.1 Future Drilling

Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations have proven to date to be nonproductive in this area, and therefore Ozona does not see
this as a risk. This is supported by a review of the TRRC Rule 13 (Casing, Cementing, Drilling, Well
Control, and Completion Requirements), 16 TAC §3.13. The Sligo is not among the formations listed
for which operators in Bee County and District 2 (where the O'Neal No. 4 is located) are required to
comply with TRCC Rule 13; therefore, the TRRC does not believe there are productive horizons
below the Sligo. The O'Neal No. 4 drilling permit is provided in Appendix A-2.

4.2.2 Groundwater Wells

The results of a groundwater well search found five wells within the MMA, as identified by the Texas
Water Development Board as shown in Figure 35 and in tabular form in Appendix B-2.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4
Page 59 of 78

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Figure 35 - Groundwater Wells Within the MMA

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 60 of 78

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The surface, intermediate, and production casings of the O'Neal No. 4, as shown in Figure 32, are
designed to protect the shallow freshwater aquifers, consistent with applicable TRRC regulations,
and the GAU letter issued for this location is provided in Appendix A-l. The wellbore casings and
compatible cements prevent CO2 leakage to the surface along the borehole. Ozona concludes that
leakage of the sequestered CO2 to the groundwater wells is unlikely.

4.3	Leakage Through Faults and Fractures

Detailed mapping of openhole logs surrounding the O'Neal No. 4 did not identify any faulting within
either the Pearsall or Sligo sections. However, there is a general lack of deep penetrators within the
area that limits the amount of openhole coverage available.

The majority of the published literature suggests that faulting near the project area is restricted to
the shallower, overlying Cenozoic section, as shown in Figure 9, with shallow faults dying out before
reaching the Pearsall Formation. One source interpreted the potential for faulting to the south
(Swanson et al., 2016). The potential fault is depicted in Figure 8 relative to the location of the
O'Neal No. 4. According to the map, the interpreted fault lies approximately 4.25 mi south-
southeast of the well and approximately 3.9 mi south-southeast of the stabilized plume extent in
the year 2047. In the unlikely scenario in which the injection plume or pressure front reaches the
potential fault, and the potential fault was to act as a transmissive pathway, the upper confining
Pearsall shale contains sufficient thickness and petrophysical properties required to confine and
protect injectates from leaking outside of the permitted injection zone.

Section 2.1.2 discusses regional structure and faulting, and Section 2.3 covers local structure, for
additional material relevant to this topic.

4.4	Leakage Through the Confining Layer

The Sligo injection zone has competent sealing intervals present above and below the targeted
carbonate sequence of the Sligo section. The overlying Pine Island shale member of the Pearsall
Formation is approximately 130 ft thick at the O'Neal No. 4. Above this confining unit, the Cow
Creek Limestone, Cow Creek shale, and Bexar Shale Members of the Pearsall Formation will act as
additional confinement between the injection interval and the USDW. The USDW lies well above
the sealing properties of the formations outlined above, making stratigraphic migration of fluids into
the USDW highly unlikely. The petrophysical properties of the lower Sligo and Hosston Formations
make these ideal for lower confinement. The low porosity and permeability of these underlying
formations minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injectate to the in situ reservoir fluid makes migration below the lower confining layer
unlikely.

4.5	Leakage from Natural or Induced Seismicitv

The O'Neal No. 4 is located in an area of the Gulf of Mexico considered to be active from a seismic
perspective. Therefore, the Bureau of Economic Geology's TexNet (from 2017 to present) and
USGS's Advanced National Seismic System (from 1971 to present) databases were reviewed to

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 61 of 78

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identify any recorded seismic events within 25 km of the O'Neal No. 4.

The investigation identified a multitude of seismic events within the 25 kilometer (km) search radius;
however, the magnitude of most of the events was below 2.5. The nearest seismic event with a
recorded magnitude of 3.0 or greater was measured approximately 5.6 km northwest of the O'Neal
No. 4 at a depth of 5 km. The results of the investigation are plotted on the map provided in Figure
36 relative to the O'Neal No. 4 and the 25-km search radius.

The plant will have operating procedures and set points programmed into the control and SCADA
systems to ensure operating pressures are maintained within the injection and confining intervals'
approved fracture gradients. Given the seismic activity in the area, Ozona will closely monitor
nearby TexNet station EF71 for activity and any corresponding irregularities in the operating
pressures of O'Neal No. 4.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 62 of 78

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Figure 36 - 25-km Seismicity Review

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 63 of 78

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SECTION 5 - MONITORING FOR LEAKAGE

This section discusses the strategy that Ozona will employ for detecting and quantifying surface
leakage of CO2 through the pathways identified in Section 4, to meet the requirements of 40 CFR
§98.448(a)(3). As the injectate stream contains both H2S and CO2, the H2S will be a proxy for CO2
leakage and therefore the monitoring systems in place to detect H2S will also indicate a release of
CO2. Table 9 summarizes the monitoring of the following potential leakage pathways to the surface.
Monitoring will occur during the planned 12-year injection period or cessation of injection
operations, plus a proposed 10-year post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults, fractures, or confining seals

•	Leakage through natural or induced seismicity

Table 9 - Summary of Leakage Monitoring Methods

Leakage Pathway

Monitoring Method

Leakage from surface equipment

Fixed H2S monitors at the Plant and well site

Visual inspections

Monitor SCADA systems for the Plant and well site

Leakage through existing wells

Monitor C02 levels in above zone producing wells

Mechanical Integrity Tests (MIT) of O'Neal No. 4 every 5 years

Visual inspections

Annual soil gas sampling near well locations that penetrate the Upper
Confining Zone within the AMA

Leakage through groundwater wells

Annual groundwater samples from existing water well(s)

Leakage from future wells

Monitor drilling activity and compliance with TRRC Rule 13 Regulations

Leakage through faults, fractures, or confining
seals

SCADA continuous monitoring at the well site (volumes and pressures)

Monitor C02 levels in above zone producing wells

Leakage from natural or induced seismicity

Monitor C02 levels in above zone producing wells

Monitor existing TexNet station

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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5.1 Leakage from Surface Equipment

The Plant and the O'Neal No. 4 were designed to operate in a safe manner to minimize the risk of
an escape of CO2 and H2S. Leakage from surface equipment is unlikely and would quickly be
detected and addressed. The facility design minimizes leak points through the equipment used, and
key areas are constructed with materials that are NACE and API compliant. A baseline atmospheric
CO2 concentration will be established prior to commencing operation once facility construction has
been completed. Ambient H2S monitors will be located at the plant and near the O'Neal No. 4 site
for local alarm and are connected to the SCADA system for continuous monitoring.

The plant and the O'Neal No. 4 are continuously monitored through automated control systems.
These monitoring points were discussed in Section 4.1. In addition, field personnel conduct routine
visual field inspections of gauges, and gas monitoring equipment. The effectiveness of the internal
and external corrosion control program is monitored through the periodic inspection of the
corrosion coupons and inspection of the cathodic protection system. These inspections and the
automated systems allow Ozona to detect and respond to any leakage situation quickly. The surface
equipment will be monitored for the injection and post-injection period. Should leakage be
detected during active injection operations, the volume of CO2 released will be calculated based on
operating conditions at the time of the event, per 40 CFR §98.448(a)(5) and §98.444(d).

Pressures, temperatures, and flow rates through the surface equipment are continuously monitored
during operations. If a release occurred from surface equipment, the amount of CO2 released would
be quantified based on the operating conditions, including pressure, flow rate, percentage of CO2 in
the injectate, size of the leak-point opening, and duration of the leak. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7.

5.2 Leakage Through Existing and Future Wells Within the MMA

Ozona continuously monitors and collects injection volumes, pressures, and temperatures through
their SCADA systems, for the O'Neal No. 4. This data is reviewed by qualified personnel and will
follow response and reporting procedures when data exceeds acceptable performance limits. A
change of injection or annular pressure would indicate the presence of a possible leak and be
thoroughly investigated. In addition, MITs performed every 5 years, as expected by the TRRC and
UIC, would also indicate the presence of a leak. Upon a negative MIT, the well would be isolated
and investigated to develop a leak mitigation plan.

As discussed previously, TRRC Rule 13 ensures that new wells in the field are constructed with
proper materials and practices to prevent migration from the injection interval.

In addition to the fixed monitors described previously, Ozona will also establish and operate an in-
field monitoring program to detect CO2 leakage within the AMA. This would include H2S monitoring
as a proxy for CO2 at the well site and annual soil gas samples taken near any identified wells that
penetrate the injection interval within the AMA. These samples will be analyzed by a qualified third
party. Prior to commencing operation, and through the post-injection monitoring period, Ozona
will have these monitoring systems in place.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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Currently, there is only one well in the MMA identified that penetrates the injection interval. This
well was plugged and abandoned in 2007. The TRRC records are provided in Appendix A-4. Ozona
will take an annual soil gas sample from this area, which will be analyzed by a third-party lab.
Additional monitoring will be added as the AMA is updated over time. In the unlikely event a leak
occurs, Ozona will quantify the leak volumes by the methodologies discussed in Section 7 and
present these results and related activities in the annual report.

Ozona will also utilize shallower producing gas wells as proxies for above-zone monitoring wells.
Production data from these wells is analyzed for monthly production statements, and therefore
would be an early indicator of any possible subsurface issues. Should any material change from
historical trends in the CO2 concentration occur, Ozona would investigate and develop a corrective
action plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is
very low, as the producing reservoir provides an ideal containment given the upper confining zone
of this reservoir has proven competent. In the unlikely event a leak occurs, Ozona would quantify
the leak per the strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443
based on the actual circumstances, and include these results in the annual report.

5.2.1 Groundwater Quality Monitoring

Ozona will monitor the groundwater quality above the confining interval by sampling from
groundwater wells near the O'Neal No. 4 and analyzing the samples with a third-party laboratory
on an annual basis. In the case of the O'Neal No. 4, 5 existing groundwater wells have been
identified within the AMA (Figure 38). Initial groundwater quality tests will be performed to
establish a baseline prior to commencing operations.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 66 of 78

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 67 of 78

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5.3 Leakage Through Faults. Fractures, or Confining Seals

Ozona will continuously monitorthe operations of the O'Neal No. 4 through the automated controls
and SCADA systems. Any deviation from normal operating volume and corresponding injection
pressure could indicate movement into a potential leak pathway, such as a fault or breakthrough of
the confining seal, and would trigger an alert due to a change in the injection pressure. Any such
alert would be reviewed by field personnel and appropriate action would be taken, including
shutting in the well, if necessary.

Ozona will also utilize shallower producing wells as proxies for above-zone monitoring wells.
Production data is analyzed regularly for monthly production statements and therefore would be
an early indicator of any possible subsurface issues. Should any material change from historical
trends in the CO2 concentration occur, Ozona would investigate and develop a corrective action
plan. Should any CO2 migrate vertically from the Sligo Formation, the magnitude risk of this event
is very low, as the producing reservoir provides an ideal containment given the upper confining zone
has proven competent. In the unlikely event a leak occurs, Ozona would quantify the leak per the
strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443 based on the
actual circumstances.

5.4 Leakage Through Natural or Induced Seismicitv

While the likelihood of a natural or induced seismicity event is low, Ozona plans to use the nearest
TexNet seismic monitoring station, EF71, to monitor the area around the O'Neal No. 4. This station
is approximately 3 mi to the northwest, as shown in Figure 38. This is sufficient distance to allow
for accurate and detailed monitoring of the seismic activity in the area. Ozona will monitor this
station for any seismic activity, and if a seismic event of 3.0 magnitude or greater is detected, Ozona
will review the injection volumes and pressures of the O'Neal No. 4 to determine if any significant
changes have occurred that would indicate potential leakage.

Ozona will also continuously monitor operations through the SCADA system. Any deviation from
normal operating pressure and volume set points would trigger an alarm for investigation by
operations staff. Such a variance could indicate movement into a potential leak pathway, such as a
fault or breakthrough of the confining seal. Any such alert would be reviewed by field personnel
and appropriate action would be taken, including shutting in the well, if necessary

These are the two primary strategies for mitigating risks for induced seismicity. In the unlikely event
a leak occurs, Ozona will quantify the leak per the strategies discussed in Section 7, or as may be
applicable provided in 40 CFR §98.443 based on the actual circumstances.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 68 of 78

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 69 of 78

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SECTION 6 - BASELINE DETERMINATIONS

This section identifies the strategies Ozona will undertake to establish the expected baselines for
monitoring CO2 surface leakage per 40 CFR §98.448(a)(4). Ozona will use the existing SCADA
monitoring systems to identify changes from the expected performance that may indicate leakage
of injectate and calculate a corresponding amount of CO2.

6.1	Visual Inspections

Regular inspections will be conducted by field personnel at the plant and O'Neal No. 4 site. These
inspections will aid in identifying and addressing possible issues to minimize the risk of leakage. If
any issues are identified, such as vapor clouds or ice formations, corrective actions will be taken
prudently and safely to address such issues.

6.2	CO2/H2S Detection

In addition to the fixed monitors in the Plant and at the wellsite, Ozona will establish and perform
an annual in-field sampling program to monitor and detect any CO2 leakage within the AMA. This
will consist of soil gas sampling near any artificial penetrations of the injection zone and sampling of
water wells. These probes have special membrane inserts that collect the gas samples over a 21-
day period. These will be analyzed by a third-party lab to be analyzed for CO2, H2S, and trace
contaminants typically found in a hydrocarbon gas stream. The lab results will be provided in the
annual report should they indicate a material variance from the baseline. Initial samples will be
taken and analyzed before the commencement of operations and will establish the baseline
reference levels.

6.3	Operational Data

Upon starting injection operations, baseline measurements of injection volumes and pressures will
be recorded. Any significant deviations over time will be analyzed for indication of leakage of
injectate and the corresponding component of CO2.

6.4	Continuous Monitoring

The total mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly,
as the injection stream for this project is near the OSHA Permissible Exposure Limit (PEL) 8-hour
Time Weighted Average (TWA) of 5,000 ppm. Direct leak surveys present a hazard to personnel due
to the presence of H2S in the gas stream. Continuous monitoring systems will trigger alarms if there
is a release. The mass of the CO2 released would be calculated based on the operating conditions,
including pressure, flow rate, percentage of CO2, size of the leak-point opening, and duration. This
method is consistent with 40 CFR §98.448(a)(5) and §98.444(d), allowing the operator to calculate
site-specific variables used in the mass balance equation.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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In the case of a depressuring event, the acid gas stream will be sent to a flare stack to be safely
processed and will be reported under reporting requirements for the plant. Any such events will be
accounted for in the sequestered reporting volumes consistent with Section 7.

6.5 Groundwater Monitoring

Initial samples will be taken from groundwater wells in the area of the O'Neal No. 4 upon approval
of the MRV plan, and before commencement of CO2 injection. These samples will be analyzed and
reports prepared by a third-party laboratory testing for pH, total dissolved solids (TDS), CO2, and
volatile organic compounds (VOC). Initial samples will be taken and analyzed before the
commencement of operations and will establish the baseline reference levels. Sampling select wells
will be performed annually. In the event a material deviation in the sample analysis occurs, the
results will be provided in the annual report.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS

BALANCE EQUATION

This section identifies how Ozona will calculate the mass of CO2 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the CO2 emissions from equipment leaks and
vented emissions of CO2 between the injection flow meter and the injection well, per 40 CFR
§98.448(a)(5).

7.1	Mass of CO2 Received

Per 40 CFR §98.443, the mass of CO2 received must be calculated using the specified CO2 received
equations "unless you follow the procedures in 40 CFR §98.444(a)(4)." The 40 CFR §98.444(a)(4)
states that "if the CO2 you receive is wholly injected and is not mixed with any other supply of CO2,
you may report the annual mass of CO2 injected that you determined following the requirements
under paragraph (b) of this section as the total annual mass of CO2 received instead of using
Equation RR-1 or RR-2 of this subpart to calculate CO2 received." The CO2 received for this injection
well is injected and not mixed with any other supply; the annual mass of CO2 injected will equal the
amount received less any amounts calculated in accordance with the equations of this section. Any
future streams would be metered separately before being combined into the calculated stream.

7.2	Mass of CO2 Injected

Per 40 CFR §98.444(b), since the flow rate of CO2 injected will be measured with a volumetric flow
meter, the total annual mass of CO2, in metric tons, will be calculated by multiplying the mass flow
by the CO2 concentration in the flow according to Equation RR-5:

CC>2,u = Annual CO2 mass injected (metric tons) as measured by flow meter u

Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p (standard
cubic meters per quarter)

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682

Cco2,P,u = Quarterly CO2 concentration measurement in flow for flow meter u in quarter p
(volume percent CO2, expressed as a decimal fraction)

p = Quarter of the year

u = Flow meter

4

p=1

Where:

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 72 of 78

-------
7.3 Mass of CO2 Produced

The O'Neal No. 4 is not part of an enhanced oil recovery project; therefore, no CO2 will be produced.
7.4 Mass of CO2 Emitted by Surface Leakage

The mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly due
to the H2S concentration in the injection stream. Direct leak surveys are dangerous and present a
hazard to personnel. Because no venting is expected to occur, the calculations would be based on
the unusual event that a blowdown is required and those emissions would be sent to a flare stack
and reported as a part of the required GHG reporting for the plant. Any leakage would be detected
and managed as an upset event. Continuous monitoring systems should trigger an alarm upon a
release of H2S and CO2. The mass of the CO2 released would be calculated for the operating
conditions, including pressure, flow rate, size of the leak-point opening, and duration of the leak.
This method is consistent with 40 CFR §98.448(a)(5), allowing the operator to calculate site-specific
variables used in the mass balance equation.

In the unlikely event that CO2 was released because of surface leakage, the mass emitted would be
calculated for each surface pathway according to methods outlined in the plan and totaled using
Equation RR-10 as follows:

CO2E = Total annual CO2 mass emitted by surface leakage (metric tons) in the reporting year
CC>2,x= Annual CO2 mass emitted (metric tons) at leakage pathway x in the reporting year
X = Leakage pathway

Calculation methods using equations from Subpart W will be used to calculate CO2 emissions due to
any surface leakage between the flow meter used to measure injection quantity and the injection
wellhead.

As discussed previously, the potential for pathways for all previously mentioned forms of leakage is
unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, Ozona believes the most appropriate method to quantify the mass of CO2
released will be determined on a case-by-case basis. Any mass of CO2 detected leaking to the
surface will be quantified by using industry proven engineering methods including, but not limited
to, engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling,
and history-matching of the sequestering reservoir performance, among others. In the unlikely

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 73 of 78

X

x=l

Where:

-------
event that a leak occurs, it will be addressed, quantified, and documented within the appropriate
timeline. Any records of leakage events will be kept and stored as provided in Section 10.

7.5 Mass of CO2 Sequestered

The mass of CO2 sequestered in subsurface geologic formations will be calculated based on Equation
RR-12. Data collection for calculating the amount of CO2 sequestered in the O'Neal No. 4 will begin
once the subsurface recompletion work, and the surface facilities construction has been completed,
and subject to approval of the MRV plan. The calculation of sequestered volumes utilizes the
following equation as the O'Neal No. 4 will not actively produce oil, natural gas, or any other fluids:

C02 — CO21 — C02e ~ CO2F1

Where:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year

CO21 = Total annual CO2 mass injected (metric tons) in the well covered by this source
category in the reporting year

CO2E = Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year

CO2F1 = Total annual CO2 mass emitted (metric tons) from equipment leaks and vented
emissions of CO2 from equipment located on the surface, between the flow meter used to
measure injection quantity and the injection wellhead

CO2F1 will be calculated in accordance with Subpart W for reporting of GHGs. Because no venting is
expected to occur, the calculations would be based on the unusual event that a system blowdown
event occurs. Those emissions would be sent to a flare stack and reported as part of the GHG
reporting for the plant.

• Calculation methods from Subpart W will be used to calculate (Remissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 74 of 78

-------
SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN

The O'Neal Gas Unit No. 4 is an existing natural gas well that will be recompleted as a Class II well
with corrosion-resistant materials. Ozona is submitting this MRV application to the GHGRP to
comply with the requirements of Subpart RR. The MRV plan will be implemented upon receiving
EPA approval. The Annual Subpart RR Report will be filed on March 31 of the year following the
reporting year.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 75 of 78

-------
SECTION 9 - QUALITY ASSURANCE

This section identifies how Ozona plans to manage quality assurance and control to meet the

requirements of 40 CFR §98.444.

9.1	Monitoring QA/QC

CO2 Injected

•	The flow rate of the CO2 being injected will be measured with a volumetric flow meter,
consistent with API standards. These flow rates will be compiled quarterly.

•	The composition of the injectate stream will be measured upstream of the volumetric flow
meter with a continuous gas composition analyzer or representative sampling consistent
with API standards.

•	The gas composition measurements of the injected stream will be averaged quarterly.

•	The CO2 measurement equipment will be calibrated per the requirements of 40 CFR
§98.444(e) and §98.3(i).

CO2 Emissions from Leaks and Vented Emissions

•	Gas monitors at the plant and O'Neal No. 4 will be operated continuously, except for
maintenance and calibration.

•	Gas monitors will be calibrated according to the requirements of 40 CFR §98.444(e) and
§98.3(i).

•	Calculation methods from Subpart W will be used to calculate CChemissionsfrom equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Measurement Devices

•	Flow meters will be continuously operated except for maintenance and calibration.

•	Flow meters will be calibrated according to 40 CFR §98.3(i).

•	Flow meters will be operated and maintained in accordance with applicable standards as
published by a consensus-based standards organization.

All measured volumes of CO2 will be converted to standard cubic meters at a temperature of 60°F

and an absolute pressure of 1 atmosphere.

9.2	Missing Data

In accordance with 40 CFR §98.445, Ozona will use the following procedures to estimate missing

data if unable to collect the data needed for the mass balance calculations:

•	If a quarterly quantity of CO2 injected is missing, the amount will be estimated using a
representative quantity of CO2 injected from the nearest previous period at a similar
injection pressure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 76 of 78

-------
• Fugitive CO2 emissions from equipment leaks from facility surface equipment will be
estimated and reported per the procedures specified in Subpart W of 40 CFR §98.

9.3 MRV Plan Revisions

If any changes outlined in 40 CFR §98.448(d) occur, Ozona will revise and submit an amended MRV
plan within 180 days to the Administrator for approval.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 77 of 78

-------
SECTION 10 - RECORDS RETENTION

Ozona will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
3 years and include the following:

•	Quarterly records of the CO2 injected

o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the CO2 stream

•	Annual records of the information used to calculate the CO2 emitted by surface leakage from
leakage pathways.

•	Annual records of the information used to calculate CO2 emitted from equipment leaks and
vented emissions of CO2 from equipment located on the surface, between the flow meter
used to measure injection quantity and the injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 78 of 78

-------
APPENDICES
APPENDIX A - O'Neal No. 4 TRRC FORMS

APPENDIX A-l: GAU GROUNDWATER PROTECTION DETERMINATION

APPENDIX A-2: DRILLING PERMIT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

APPENDIX A-3: COMPLETION REPORT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

•	ACID FRACTURE REPORT

APPENDIX A-4: API 42-025-30388 CHARLIE C. OVERBY GU PLUGGING RECORDS

-------
APPENDIX B - AREA OF REVIEW

APPENDIX B-l: OIL AND GAS WELLS WITHIN THE MMA LIST

APPENDIX B-2: WATER WELLS WITHIN THE MMA LIST

-------
APPENDIX A-l

GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit

Form GW-2

Date Issued:

26 May 2023

GAU Number:

367912

Attention:

OZONA CCS LLC

API Number:

02532658



19026 RIDGEWOOD

County:

BEE



SAN ANTONIO, TX 78259

Lease Name:

O'Neal Gas Unit









Lease Number:

162214

Operator No.:

100116







Well Number:

4





Total Vertical

16101





Latitude:

28.602914





Longitude:

-98.001428





Datum:

NAD27

Purpose:
Location:

Injection into Producing Zone (H1)
Survey-EL&RR RR CO; Abstract-452; Section-1



To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:

The base of usable-quality water-bearing strata is estimated to occur at a depth of 250 feet at the site of the referenced
well.

The BASE OF UNDERGROUND SOURCES OF DRINKING WATER (USDW) is estimated to occur at a depth of 950
feet at the site of the referenced well.

Note: Unless stated otherwise, this recommendation is intended to apply to all wells drilled within 200 feet of the subject well.
Unless stated otherwise, this recommendation is for normal drilling, production, and plugging operations only.

This determination is based on information provided when the application was submitted on 05/26/2023. If the location
information has changed, you must contact the Groundwater Advisory Unit, and submit a new application if necessary.

If you have questions, please contact us at 512-463-2741 orgau@rrc.texas.gov.

Groundwater Advisory Unit, Oil and Gas Division

Form GW-2 P.O. Box 12967 Austin Texas 78771-2967 512-463-2741 Internet address: www.rrc.texas.
Rev. 02/2014

-------
Online System

Oil & Gas Data Query

Query Menu

Drilling Permit (W-1) Query Results

APPENDIX A-2

Search Criteria:
API No.: 02532658

Return



2 results Page: 1 of 1 Page Size: view ah v

API NO.

District

Lease

Well
Number

Permitted
O iterator

Countv

Status
Date

Status
Number

Wellbore
Profiles

Filina
PurDose

Amend

Total
Death

Stacked
Lateral
Parent
Well DP

#

Status

02532658 Links v

02

CHARLIE
C.

OVERBY
GAS
UNIT

2

PARKER &
PARSLEY
DEVELOPMENT
CO.(640889)

BEE

Submitted:
11/30/1992
Approved:
11/30/1992

406655

Vertical

New Drill

N

16700



APPROVED

02532658 Links v

02

O'NEAL
GAS
UNIT
Q622141

4

PARKER &
PARSLEY
DEVELOPMENT
L.P(640886)

BEE

Submitted:
11/20/1996
Approved:
12/16/1996

455434

Vertical

Re completion

N

14040



APPROVED

Download

Return



Disclaimer | RRC Home | Contact

NOTE: THE CHARLIE C. OVERBY GU AND THE O'NEAL GU ARE THE SAME WELL. THE OVERBY WELL WAS DRILLED IN 1993 INTO THE SLIGO.
IN 1997 THE WELL WAS RECOMPLETED IN THE EDWARDS FORMATION. THIS WAS DONE UNDER A NEW LEASE, AS THE O'NEAL GU NO. 4.

-------
Form W-1: Field List

Log In

Status # 406655
API # 025-32658

OP # 640889 - PARKER & PARSLEY DEVELOPMENT CO.

Approved ,Issued: 11/30/1992 ,Filed: Hardcopy

CHARLIE C. OVERBY GAS UNIT - Well # 2

02 - BEE County

New Drill

Vertical

NEAREST WELL COMMENT: 1607.8 ( 11/30/1992 12:00:00 AM )

Status:

Back to Public Query Search Results

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

01/01/1993

02/11/1993

01/01/1993

Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (SLIGO)

Gas

02/11/1993

06/18/1993

General / Location Information

Basic Information:

Filing
Purpose

Welbore
Profiles

Lease Name

Well

#

SWR

Total
Depth

Horizontal
Wellbore

Stacked Lateral Parent
Well DP #

New Drill

Vertical

CHARLIE C. OVERBY
GAS UNIT

2

SWR
36

16700





Surface Location Information:

API #

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658

4.0 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





EL&RR RR CO

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Survey Lines

2784.0 feet

from the S line and

1045.5 feet

from the W line

Permit Restrictions:

Code

Description

30

REGULAR PROVIDED THAT UPON SUCCESSFUL COMPLETION OF THIS WELL IN THE SAME RESERVOIR AS ANY OTHER WELL
PREVIOUSLY ASSIGNED THIS ACREAGE, A P-15 AND REVISED PRORATION PLATS MUST BE SUBMITTED WITH NO

30

DOUBLE ASSIGNMENT OF ACREAGE.

30

REGULAR PROVIDED THIS WELL IS NEVER COMPLETED IN THE SAME RESERVOIR AS ANY OTHER WELL CLOSER THAN 2640
FEET ON THIS SAME LEASE.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

https://webapps.rrc.texas.gov/DP/drillDownQuery Action, do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362... 1/2

-------
11/28/23, 4:52 PM

Form W-1: Field List

30 O'NEAL GU #3, O'NEAL #1, OVERBY #120 & NEAL #1.

Fields

District

Field
Name

Field #

Completion
Depth

Lease
Name

Well

#

Well
Type

Acres

Distance to

Nearest

Well

Distance to
Nearest
Lease Line

SWR

Pooled/
Unitized

02

PAWNEE
(SLIGO)

Primary
Field

69845800

16700

CHARLIE C.
OVERBY GAS
UNIT

2

Oil or

Gas

Well

704.0





SWR
36

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 2390.0 feet from the E line and 3446.0 feet from the N line



I

Comments

Remark

Date Entered

Entered By

NEAREST WELL COMMENT: 1607.8

11/30/1992 12:00:00 AM

SYSTEM

Attachments

Attachment Type

File Path

Associated Fields and/or Plats

Disclaimer | RRC Online Home | RRC Home | Contact

https://webapps.rrc.texas.gov/DP/drillDownQuery Action.do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362.

2/2

-------
***** Online System

Log in

Form W-1: Review

Status# 455434
API # 025-32658

OP #640886 - PARKER & PARSLEY DEVELOPMENT L.P

Approved ,Issued: 12/16/1996 ,Filed: Hardcopy

O'NEAL GAS UNIT - Well # 4

02 - BEE County

Recompletion

Vertical

NEARESTWELL COMMENT: 1787 ( 11/20/1996 12:00:00 AM )

Status:

Back to Pui?iig Query Search Resets

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

02/04/1997

02/13/1997



Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (EDWARDS)

Gas

02/13/1997

02/26/1997

General / Location Information

Bask Information:

Filing Purpose

Wei bore Profiles

Lease Name

Well #

SWR

Total Depth

Horizontal Wellbore

Stacked Lateral Parent Well DP #

Recompletion

Vertical

O'NEAL GAS UNIT

4

SWR 36, SWR37H

14040





Surface Location Information:

API#

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658 lil

3.5 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





E.L.&R.R. RR CO. #1

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Sirvey Lines

825.0 feet

from the W line and

2784.0 feet

from the S line

Permit Restrictions:

Code

Description

30

WILDCAT ABOVE 14040 FEET

30

ANY WELLBORE DRILLED UNDER THIS PERMIT MUST BE COMPLETED, OPERATED, AND PRODUCED IN COMPLIANCE WITH STATEWIDE RULE 32.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

Fields

District

Field Name

Field #

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

WILDCAT
Primary Field

00004001

14040

O'NEAL GAS UNIT

4

Oil or Gas Well

704.0





37H

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the Sline





District

Field Name

Field#

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

PAWNEE CEDWARDS)

69845200

14040

O'NEAL GAS UNIT

4

Gas Well

704.0





SWR 36, 37H

Y



Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the S line







Exceptions

Field

Exception

Case Docket Number

Resolution

WILDCAT

SWR 37 [Historical]

0214349



PAWNEE CEDWARDS)

SWR 37 [Historical]

0214349



Comments

Remark

Date Entered

Entered By

NEARESTWELL COMMENT: 1787

11/20/1996 12:00:00 AM

SYSTEM

Attachments

Attachment Type	File Path	Associated Fields and/or Plats

Disdaimer | RRC Online Home | RRC Home | Contact

-------
APPENDIX A-3

Ozona CCS

Well Name: ONeal Gas Unit 4 (current)
Formation: Edwards
County, State: Bee County, TX
API #: 42-025-32658
Permit #:

Rig
GL
RKB
TD (MD)
TP (TVD)

Lat, Long 28.6031807,-98.0017091 (NAD83)
GAU Depth:

MD/TVD

10.75" Surface Casing

Cook Mountai n

3657

Sparta

4259

Weches Sandstone

4326

Queen City

4655

Reklaw

5244

Carrizo

5864

Wilcox

5922

Midway

9026

Austin Chalk

13266

Eagle Ford

13344

Buda

13494

Edwards

13500

CIBP w/ 20' Cement on Top

14000

5" Liner Top

14088

Pearsall

15339

1 5/8" Intermediate Casing

15340

zd





C02 Resistant Permanent Packer

Sligo



L



Tubular Detail

String

Hole Size

OD

Weight

Grade

MD



(in)

(in)

(#/ft)



(ft)

Conductor











Surface

14 3/4"

10 3/4"

55.5

S-95

3,610'

Intermediate

9 1/2"

7 5/8"

39

CY-95

15,340'

Liner

6 1/2"

5"

18

Q-125

14,088'-16,101'

Prod Tbg



2 3/8"

4.7

L-80

13453'

Cement Detail

String

Vol

Type

TOC

%XS



(sks)



(MD)



Surf Lead

1125

HLC

0'



Surf Tail

350

H





Int Lead

575

50:50 Poz:H

7359'



Int Tail

400

H





Liner

200

Premium

14088'



Edwards perfs production zone, 13,529*-13,841*	

Cumulative 6,555,750 MCF gas, 168,888 BBLs water produced

Initial production zone, 15,874'-16,056*

Cumulative 511,964 MCF gas, 22,026 BBLs water produced

Well History

#

Date

Description

1

12/30/1992

First spud as gas well, targeting the Sligo formation

2

2/13/1997

Plugged back to 14,000' and recompleted

-------
TUBING PRESSURE
ANNULUS PRESSURE

ps
ps

20000

18000

16000

14000

12000

10000

2000

16:05

SLURRY RATE

(bpm)

NOTE: THE CHARLIE C. OVERBY GU AND THE O'NEAL GU ARE THE SAME WELL. THE OVERBY WELL WAS DRILLED IN 1993 INTO THE SLIGO.
THIS ACID FRACTURE REPORT IS FOR THE ORIGINAL COMPLETION IN THE SLIGO FORMATION.

16:20

16:35

16:50

_r_—r

17:05	17:20

17:35

TIME (min)

"i	r

17:50	18:05

18:20

18:35

CUSTOMER: PARKER & PARSLEY DEV. CO. JOB DATE: APR-03-1993
WELL DECS: OVERBY §2	FORMATION: SLIGO

TICKET #: 30840901

JOB TYPE: SWIC ACID BALLOUT

-------
PASE i

Custoisr; PARKER & PARSLEY DEV. CO,	Ticket I; 30840901

Hell Descs OVERBY 12	Foraation; SLI80

TIME

STA6E

TUBING PR

ANNULUS PR SLURRY RT

HR:MH:SS

NO

(psi)

(usi)

(bpl)

16:06:02

0

0

0

0,00

16:07:02

0

3216

470

0.00

16:08:02

1 Event(Eng) Oper

ator Stags Advance



16:08:02

1

3251

"470

2.65

16:09:02

1

3904

470

8.43

16:10:02

1

4471

528

8.24

16:11:02

1

5059

1612

8.17

16:12:02

1

5812

1978

8.04

16:13:02

1

7j58

1906

8,62

16:14:02

1

9069

1875

7.03

16:15:02

1

9950

2004

5.82

16:16:02

1

9504

1922

5.82

16:17:02

1

9572

1863

6,51

16:18:02

1

9304

2003

6.86

16:19:02

1

9539

1870

8.03

16:20:02

1

9725

1945

7.95

16:21:02

1

9862

1920

6,52

16:22:02

1

9216

1886

4.43

16:23:02

1

9672

1992

4.43

16:24:02

2 Event(Eng) Operator Staoe Advance



16:24:02

2

9384

1906

4.15

16:25:02

2

9416

1906

5.36

16:26:02

7

9547

1964

4.56

16:27:02

2

9150

1915

2.05

16:28:02

2

9898

2032

3,96

16:29:02

£

9812

1948

3.30

16:30:02

7

9824

1876

3,30

16:31:02

2

9882

1944

3.30

16:32:02

¦/

10020

1967

3.26

16:33:02

2

9946

1898

3.24

16:34:02

2

9733

1986

2,90

16:35:02

2

9654

1980

2.90

16:36:02

2

9590

1921

2,90

16:37:02

2

9558

1870

2.91

16:38:02

2

9552

2018

2.90

16:39:02

2

9420

1960

2.30

16:40:02

2

9377

1908

2,97

16:41:02

2

9369

1866

2.90

16:42:02

2

9485

2010

3,07

16:43:02

2

9635

1961

3.10

16:44:02

2

9647

1910

3.09

16:45:02

2

9644

1868

3.12

16:46:02

3 Event(Eng) Operator Stage Advance



16:46:02

ij

9622

2011

3.10

16:47:02

3

9601

1955

3.10

16:48:02

d

9597

1905

3.10

16:49:02

3

9596

1867

3,10

16:50:02

3

9568

2020

3.10

16:51:02

j

9553

1968

3.10

16:52:02

3

9551

1923

3.10

16:53:02

3

9667

1883

3.26

16:54:02

3

9707

1859

3.26

16:55:02

3

9708

2024

3.22

16:56:02

i

9718

1974

3,27

16:57:02

3

9720

1927

3.25

Date; Apr 3, 1993
Job Type: SWIC ACID BAILOUT

-------
PfiBE 2

Custoaer; PARKER & PARSLEY DEV. CO.	Ticket I; 30840901	Bate: Apr 3, 1993

yell Desc: OVERBY 12	Foraation: SLI80	Job Types SWIC ACID BAILOUT

TIME

STAGE

TUBING PR ANNULUS PR SLURRY RT

HRiMHiSS

NO

(psi)

(psi)

(bps)

16:58:02

3

9705

1883

3,26

16:53:02

3

9709

1984

0 0^

u'» a.

17:00:02

3

9686

1996

3.26

17:01:02

3

9677

1958

3.27

17:02:02

3

96?!

1924

3.26

17:03:02

3

9630

1889

3.2b

17:04:02

3

9563

1857

3,26

17:05:02

3

9560

2025

3.26

17:06:02

3

9417

1983

3.28

17:07:02

3

9153

1943

3.12

17:08:02

3

9569

1933

3,12

17:09:02

3

9691

1909

3,10

17:10:02

3

9532

1880

3,12

17:11:02

3

9509

1943

3.10

17:12:02

3

9568

2012

3.10

17:13:02

3

9611

1979

3.12

17:14:02

3

9576

1947

2.97

17:15:02

3

9607

1917

3.06

17:16:02

n
0

9805

1893

3.28

17:17:02

3

9858

1865

3.29

17:18:02

3

9827

2031

3,28

17:19:02

3

9864

1994

3,43

17:20:02

3

9872

1963

3.30

17:21:02

3

9681

1927

3.12

17:22:02

0

9325

1884

3.37

1/««. «0 2

3

9445

1902

3.33

17:24:02

4 Event(Eng) Operator

Stags Advance



17:24:02

4

9468

2027

3,32

17:25:02

4

9436

1988

3«32

17:26:02

4

9594

1960

3,33

17:27:02

4

9502

1928

3,33

17:28:02

4

9428

1896

3.32

17:29:02

4

9425

1867

3,33

17:30:02

4

9437

2045

3,33

17:31:02

4

9439

2026

3.32

17:32:02

4

9454

1996

0 91
U t ujL

17:33:02

4

9492

1971

3.32

17:34:02

4

9577

1947

3.32

17:35:02

4

9585

1923

3.32

17:36:02

4

9818

1908

2.69

17:37:02

4

9839

1889

2.93

17:38:02

4

9661

1870

2.82

17:39:02

4

9808

1862

2.90

17:40:02

4

9642

2047

2,67

17:41:02

4

9589

2027

2,69

17:42:02

4

9583

2015

2.69

17:43:02

4

9858

2011

2.90

17:44:02

4

9662

1996

2.69

17:45:02

4

9649

1986

2,68

17:46:02

4

9624

1973

2.68

17:47:02

4

9477

1956

2,69

17:48:02

4

9360

1942

2.68

17:49:02

5 Eyent(Eng) Operator Stage Advance



17:49:02

3

5770

1941

2,99

17:50:02

5

9585

1926

2.66

-------
PASE 3

Custotisr; PARKER & PARSLEY DEV. CO.	Ticket #: 30340901	Date; Apr 3, 1993

Hell Desc; OVERBY #2	Fortation: SLI60	Job Type; SWIC ACID BAILOUT

TIME

STAGE TUBINQ PR

ANNULUS PR

SLURRY RT

HR:HH:SS

NO (osi)

(psi)

(boa)

17:51:02

5

9577

1913

2.85

17:52:02

5

9749

1908

2.78

17:53:02

5

9627

1895

2.68

17:54:02

5

9638

1885

2.67

17:55:02

5

9636

1873

2,68

17:56:02

5

9642

1866

2.68

17:57:02

5

9658

2047

2.70

17:58:02

r
J

9659

2047

2.68

17:59:02

5

9783

2036

2.99

i'3:00:02

5

9937

2028

2.78

18:01:02

5

9837

2014

2.93

18:02:02

5

9857

2003

2.72

13:03:02

D

9874

1992

2.70

18:04:02

5

9617

1972

2.73

18:05:02

5

10006

1978

2.05

18:06:02

5

8309

1925

0.00

18:07:02

5

Event(Eng)



SHUT

18:07:02

5

6123

1842

0.00

18:08:02

D

6862

2033

0.00

18:09:02

5

6742

2129

0,00

18:10:02

5

6873

2278

0.00

18:11:02

5 Event(Enq)

RESUME PUMPING

18:11:02

5

7239

2367

0.00

18:12:02

5

7694

2426

4.18

18:13:02

5

8434

2440

5.10

18:14:02

5

Event(Eng) PRESSURE BREAK AT 9000PSI

18:14:02

5

8891

2411

5.11

18:15:02

5

8952

2350

5.52

18:16:02

j

9814

2296

7.05

18:37:02

5

9831

2203

6.76

18:18:02

c
J

9875

2099

6.78

18:19:02

5

9919

1995

6.67

18:20:02

h

9954

1896

6.63

18:21:02

5

10000

1852

6.15

18:22:02

c
J

9622

2000

6.05

18:23:02

5

9607

1903

6.16

18:24:02

5

9620

1822

6.17

18:25:02

h

8541

1978

4.22

18:26:02

5

8562

1933

3.72

18:27:02

6 Event(Enq) Operator

Staqe Advance



18:27:02

&

7285

1880

0,00

18:28:02

6

7269

1913

0.00

18:29:02

&

7253

1954

0.00

18:30:02

6

7251

2001

0.00

EEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEE

-------
L- u s t o m er : P M k K b k * • P ft K fc> L E V D E. V. U U.	D at*""	A I"' k—U 3 — 1 y 9 3

Well Desc s OVERBY<	Tic t #j 30840301

Formations SL.1G0	Job Types SWIC ACID BALLOUT

InOMF'" I SLJF^VT I ON

Wei I bore Actual Casing Casing Tubing Tubing
Segment Length TVD ID 0D ID 0D
Number	i feet)	( feet)	( inch )	( i n c h )	<: inch )	< inch )

1	14088 14088 4,,276 5.000 2,441 2.875

2	15874 15874 4.276 5.000 0.000 0.000

i—" EE r: f* O iR:"I' 1 O tsl S O *=% "1"

# of Per for at ions .15.		

Perf. D iameter . 3 					

Ba 11 ed 0ut ? (YES/' N0) yes	 			

F" EE F~ O F? ft ~T' EE! O 2. fsi T" EE R

r'ROli
C f eet)
15874

TO	SF'F

C feet >

		IMse 		l

-------
Well Descs OvERBY /'"•	Ticl-'-t #; 30840901

F"ormat ions BL.IG0 '•	Job ypei SWIC AC11) BA!....L0U1"

M^VT

£ I. rt»	£3

It fvi V EE i'vS "S' O FS Y

T r e a t m e n t Flu i d s
D i s p 1 a c e m e n t F1 u :i. d :
S u r f a c t a n t T y p e:
Clay Controls
F r :i. c t i o n R e d u c e r ;
Perfpac Ballss

TREATED

WATER

L0SURF

300

CLAYFIX

I I

FR---2S

30

Density-
Density

gal 20
9 a 1
gal
Qty

6 - 33

40

¦:u

1 b / g a 1
1 b / q a 1

2	1	

@ 2	

© ~

L

7/8

Size 1,3

gal/Mgal
gal/Mgal
gal/Mg cl 1

y „ u.

-------
Customer; PARKER * PARSLEY DEV. CO,	Datf-	APR-~03~ 1393

Well Desc: OVEkBY .	Tic t #; 30840301

For mat i on s Si... IG0	J0b "I"ype; SWIC AC1D BAL.L0UT

i'"l A i l~~ K .1. f'--s 8	fcS C_l fxl 1	O G #—'s "1 It (3 ffsl

BfMRIINti FLUID VOLUME	20000
-------
Well Descs QVERBY "2	Tic1 #; 30840901

Formations SLIQO	Job ypes SWIC ACID BALL01.IT

oO

O A "1"

Acid Types

SWIC

	"/. ii.

			 g a i

10000



S u r f a c t a n t T y p e:

HC--2

oal

50

w 5

qal/Mqal

N E A g e n t T y p e:

SF-'ERfcSE ALL

a a 1

50

0 5

qal/Mqal

Corrosion Inh» s

HAI-85

a a I

200

(§ 20

qal/Mqal

Corrosion Inh.:

HI.!" 500

aal

200

0 20

qal/Mqal

Cracking Inh.:

SCA	130

q a 1

200

@ 20

qal/Mqal

Ir on Seqnest er:

F.E-.3

lb

1000

@ 100

lb/Mqal

F r i c t i o n R e d u c e r ;

SGA--HT

qal

30

fe 3

qal/Mqal

Ot her 5

A.B.F

	LB_

.12.0	

12

1 b /Mq aI

-------
Customer; PARKER PARSLEY DEV. CO.	Dat	APR-03-1993

Well Descs OVERBY #2	Ticket #g 30840901

Format ion: SLIGO	-Job Type; SWIC ACID BALLOUT

J O B O O HI £! D Li i	EE

S' I"" #=* €3 EE OI EE S C F? I F> "F X O M S

St;age		Descr ipt ion	

1	TREATED WATER - LOAD HOLE. EST, RATE

2	SWIC ACID

3	SWIC ACID WITH 30 BALLS

4	SWIC ACID

5	TREATED WATER - FLUSH

6	SHUTDOWN MONITOR PRESSURE

-------
Customer s PARKER /* • PARSLEY DEV. CO.	Dat'~*~	APR-OS-1993

Wei 1 Desc s OVLRBY ...	Tic. b #s 30840901

Formations SLIGG	Job Type; SWIC ACID BALL OUT

J O t.~.s fci i_j: i—I fc. O l_l i	EZ

t-i i #-11 fc£ I IM F~ OIR f'"1 A" 1"" 01M

2		3	4	5 	6

Fluid Type

FR-26LC

S6A-HT 15X

S6A-HT 157,

SSA-HT 15%

FR-26LC

FR-26LC

Planned Clean Vol line (gal)

5000

3000

5000

2000

6000

0

Planned Slurry Voluse (gal)

5000

3000

5000

2000

6000

0

Actual Slurry Volume (gal)

4764

2937

5002

3217

5628

2

Base Fluid Density (lb/gal)

8.33

8.36

8,36

8.96

8.33

8.33

Concentration

1.00

3.00

3.00

3.00

1.00

1.00

Proppant Size













Proppant Type













fibs. Proppant Volu#e (gal/lb)

0.04530

0.04530

0.04530

0.04530

0.04530

0,04530

Planned Fluid Rate (bps)

8,00

10.00

10.00

10.00

10.00

0,00

Planned Prop Cone (lb/gal)

0.00

0.00

0.00

0.00

0.00

0.00

-------
Customer;
We?11 Desc :
Format i on:

PARKER

GVERBY
SL160

PARSLEY DEV. CO.

Datr- -

Tic fc #s

Job Types

Apr 3, 1393
30840901

SWIC acid ballout

iz> 1 rt «..£i EE £:3L.J iM M if-'-t |-< 'V

Stage Times

St age
1

3

4

6

Total

St ar t
T i me
16:07s 05
16; 2 3 m '4 4
16;45s 47
17:23;04
17:48s11
18:26s 43

End
T i me

16	: 23 s 44
16;45:47
17s23s 04

17	: 48: 11
IBs 26s 43
18s 37:38

Elapsed
T i me
00:16;39
00:22:03
00 s 37 s17
00;25:07
00 s 38 s 32
00:10:55
02 : 30 : 33

T i me
at Per fs
16:25s 09
16:58;54
17:21:16
18:01:29
18s 22:26

St age
1

3

4

5

6

T ot/Avg

T utaing
Pressure
(p s i >
7748
9615
9626
9560
9005
4293
8860

Annul us
Pr essure

(p s i )
1613
1940
1943
1961
2036
1578
1906

SIurry
Rate
(b p rn >
6, 44
3.24
3.19
3. 05
3. 48
0.01
3. 38

SIurry
Volume
(. g a 1 >
4767
2996
5002
3215
5629

21610

-------
U ustomer : P A ft K E R * P A R S L EY DEV. CD.	Dai'""	A P R -03-1993

Well Desc 5 OVERBY ! ..	Tic t #s 30840901

Formation; SLI80	job Type; SWIC ACID BALLOUT

«=: v ti dm "i • f> ee: f* o re ~i -

staqe

Event
isneuB

Tise
HH;MM;SS

Event Description

e 1

stgad

16:07:05

Operator Stage Advance

--> TREATED HATER - LOAD HOLE. EST. RATE

B 2

stgad

16:23:44

Operator Stage Advance

--> SWIC ACID

e 3

stgad

16:45:47

Operator Stage Advance

--> SWIC ACID WITH 30 BALLS

e 4

stgad

17:23:04

Operator Stage Advance

--> SWIC ACID

e 5

stgad

17:48:12

Operator Stage Advance

--> TREATED WATER - FLUSH

e 5

NOTES

18:06:36

Operator's Notes

SHUT DOWN TO SURGE BALLS ISIP 9320

e 5

NOTES

18:10:44

Operator's Notes

*** RESUME PUMPING

e 5

NOTES

18:14:01

Operator's Notes

m PRESSURE BREAK fil 9UOOPSI

e 6

stgad

18:26:43

Operator Stage Advance

-> SHUTDOWN MONITOR PRESSURE

e 6

NOTES

18:31:25

Operator's Notes

Hit ISIP = 7285 PSI FS = .889

e &

NOTES

18:32:46

Operator'5 Notes

i« 5 HIN SIP = 7238 PSI

-------
APPENDIX A-4

Plugging Record

RAILROAD COMMISSION OF TEXAS
OIL AND GAS DIVISION

FORM W-3
Rev, 12/92

EAG0S97

API NO

(if available) 42-025-30388

FILE IN DUPLICATE WITH DISTRICT OFFICE OF DISTRICT IN WHICH
WELL IS LOCATED WEtfffif"THIRTY DAYS AFTER PLUGGING

1. RRC District
02

4. RRC Lease or Id.
Number
064112

2 FIELD NAME (as per RRC Records)
Pawnee	

( Sliqo )

3. Lease Name

Oveitoy, Charlie C. Gas Unit

5. Well Number
	1

OPERATOR
Pioneer Natural

6a. Original Form W-l Filed in Name of

10. County

purees USA, Inc.

Bee

7. ADDRESS
5205 N. O1

for Blvd. , Ste.

75039-3736
900 Irving, TX

6b. Any Subsequent W-l's Filed in Name of.

11. Date Drilling
Permit Issued

Location of^/ell, Relative to Nearest Lease Boundaries
of Leasg>eBwhich this Well is Located

' /	Feet From "W

Line and /7-S^ Feet From

12 Permit Number

>S Line of the

ron

Lease

9a SECTION, BLOCK, AND SURVEY
Marcelo Alcarte

A-70

9b. Djstance and Direction Fi'om Nearest Town in this
Co '

-ounty

3.5 miles South of Pawnee

13. Date Drilling
Commenced

16. Tvpe Well

(Oil, Gas, Diy)
	Gas	

Total Depth
16.300

18. If Gas, Amt. of Cond. on
Hand at time of Plugging

17. If Multiple Completion List All Field Names and Oil Lease or Gas ID No's

GAS ID or
OIL LEASE #

Oil-O
Gas-G

WELL
#

14. Date Drilling
Completed

^

15. Date Well Plugged

3-S-P7

CEMENTING TO PLUG AND ABANDON DATA:

PLUG #1

PLUG #2

PLUG #3

PLUG #4

PLUG #5

PLUG #6

PLUG #7

PLUG #8

*19. Cementing Date

2-27

2-27

3-2

3-5

3-6

3-6





20. Size of Hole or Pipe in which Plug Placqd^ippjie^,-,,^

3 1/2

3 1/2

7

7

7

7





21. Depth to Bottom of Tubing or Drill-Pipe-(fc»),c

9310

9200

3800

3563

300

15





*22. Sacks of Cement Used (each plug)

1

1

35

55

55

6





*23 Slurry Volume Pumped (cu ft) ~

1.06

1.06

37.10

58.30

58.30

6.36





*24- Calculated Top of Plug (ft.)

9280

9180

3650

3428

200

5





25. Measured Top of Plug (if tagged) (ft.)









187







*26. Slurry Wt. #/Gal. „

16.4

16.4

16.4

16.4

16.4

16.4





*27. Type Cement

H

H

H

H

H

H





28. CASING AND TUBING RECORD AFTER PLUGGING

29. Was any Non-Drillable Material (Other rav l—l xt
than Casing) Left in This Well ^ Yes U No

SIZE

WT.#/FT.

PUT IN WELL (ft.)

LEFT IN WELL (ft.)

HOLE SIZE (IN.)

29a. If answer to above is "Yes" state depth to top of "junk" left m hole
and briefly describe non-drillable material. (Use Reverse Side of
Form if more space is needed)

Left 3 1/2 tubing in well from 3800' to 15,055'. An

existing fish of 1 1/4" tubing from 9340' to 16,143'

also left in well.

16

49.50

61

61

UNK.

10 3/4

45.50

3513

3508

15"

7

49.50

15.529

15 r 524

8 3/4

4"

UNK

15055-16290

14247



30. LIST ALL OPEN HOLE AND/OR PERFORATED INTERVALS

FROM

15,911 T0 16.072



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

I have knowledge that the cemep
-------
• •

!L5SS?^a!S,* a Yes 32. How was Mud Applied? 33. Mud Weight

Railroad Commission I | No Cirnnl ated 12 5 I RS/fiAT

34, Total Depth
16,300

Other Fresh Water Zones by T.D.W.R.
TOP BOTTOM

35. Have all Abandoned Wells on this Lease been Plugged 1 I v»,
according to RRC Rules? Yes

~ No

Depth of Deepest
Fresh Water

250



36. If NO, Explain

37.	Name and Address of Cementing or Service company who mixed and pumped cement plugs in this well i Date RRC District Office
Bat's P & A, Inc. P.O. Box 0126. Biahr.r. IX 78343 	I notified of plugging 2-23-07

38.	Name(s) and Addresse(s) of Surface Owners of Well Site

39. Was Notice Given Before Plugging to the Above?

FILL IN BELOW FOR DRY HOLES ONLY

40. For Diy Holes, this Form must be accompanied by either a Driller's, Electric, Radioactivity or Acoustical/Sonic Log or such Log must be
released to a Commercial Log Service.

~ Log Attached	~ Log released to 			 Date	

Type Logs:

I—I Driller's	I	I Electric	I I Radioactivity	I I Acoustical/Sonic

41. Date FORM P-8 (Special Clearance) Filed?

42. Amount of Oil produced prior to Plugging

* Field FORM P-l (Oil Production Report) for month this oil was produced	

RRC USE ONLY

Nearest Field

REMARKS Unable to recover 3 1/2" tbg. as anticipated above existing 1 1/4" fish @ 9340'. Jet cut 3 1/2"	

	@ 9302' & 9243'. Unable to pull or establish calculation up 3 1/2 x 7" @ 3500 P.S.I.. Freepoint on 3 1/2

gsq-	at 4750 — . Notified and received approval from Kevin Shamette W/RRC to spt rrmp'g + 20' cmt below and

above cut's made on 3 1/2. Plug #1 & #2 - CIBP + 20' cmt. in 3 1/2" 12.95#. Cut 3 1/2 a 47fi9'anri perforated
3 1/2" 6 4765' but unable to pull or circulate. Re-cut @ 3800'. Received verbal approval from Kevin Shamo-H-p
W/RRC to set plug from 3800' tp 3650' Cut & perforated 7" casing 6 3563'. Casing not	TTnaKio i-r,	

establish circulation but established injection into 7" x 8 3/4" @ 2000 P.S.I.
Notified Ke.vin W/RRC to squeeze plug. Squeezed 5 5 sks. cmt. leaving 23 sks.
inside 7" 49.50# and 32 sks. outside in 7" x 8 3/4". Cut 7" csg. @ 300' but
unable to circulate. Received verbal approval to squeeze 55 sks. Squeezed
38 sks. out into 7" x 9 5/8" and left 17 sks inside 7" casing.

J

-------
O'Neal Gas Unit No. 4

APPENDIX B-l

Area of Review: Oil & Gas Wells List

API

WELL NAME

WELL NO.

CURRENT OPERATOR

ABSTRACT

LATITUDE
(WGS84)

LONGITUDE
(WGS84)

WELL STATUS

TOTAL DEPTH
(TVD FT.)

PERFORATED INTERVAL
(MD FT.)

DATE DRILLED

4202500002

ONEAL, A.

1

ROWAN & HOPE

126

28.603017

-98.000911

DRILLED

7010

NO RECORD

8/9/1949

4202500005

RUSSELL, S.

1

PAN AMERICAN PETROLEUM CORP.

308

28.594587

-97.999841

DRILLED

7515

NO RECORD

5/12/1947

4202530346

HENRY BUES

1

PIONEER NATURAL RES. USA, INC.

70

28.5986210

-98.0118480

INACTIVE PRODUCER

13842

7554-7558; 7612-7624;
13526-13760

11/10/1974

4202530359

ONEAL GAS UNIT

2

BB-SOUTHTEX, LLC

127

28.61178

-98.000661

PRODUCING

13961

13349-15821

4/5/1975

4202530388

OVERBY, CHARLIE C. GAS UNIT

1

PIONEER NATURAL RES. USA, INC.

70

28.601086

-98.005037

P &A

16300

15911-16072

6/6/1975

4202532342

DE LEON

1

T D EXPLORATION, INC.

126

28.6006330

-97.9917520

P &A

6512

NO RECORD

12/31/1985

4202532501

HENRY BUES GAS UNIT

2

BB-SOUTHTEX, LLC

70

28.599863

-98.009994

PRODUCING

13896

13504-15637

11/15/1988

4202532638

ONEAL GAS UNIT

3

BB-SOUTHTEX, LLC

70

28.604583

-98.007079

PRODUCING

13834

13508-13668

3/12/1992

4202532842

OVERBY, CHARLIE C.

1E

PIONEER NATURAL RES. USA, INC.

70

28.5998760

-98.0053330

P &A

14000

13514-13838

10/9/1995

4202532967

TOMASEK GAS UNIT

5

BB-SOUTHTEX, LLC

126

28.609862

-97.991519

PRODUCING

13875

13434-15693

6/12/1999

4202533006

ONEAL GAS UNIT

5

BB-SOUTHTEX, LLC

70

28.6067950

-98.0042210

PRODUCING

13772

13463-13764

7/15/2000

4202533035

ONEAL GAS UNIT

6

BB-SOUTHTEX, LLC

127

28.61091

-97.999073

PRODUCING

13835

13310-13833

9/14/2000

4202533085

ONEAL GAS UNIT

7

BB-SOUTHTEX, LLC

127

28.609397

-98.001471

PRODUCING

13868

13314-16072

5/4/2001

4202533114

HENRY BUES GAS UNIT

8

BB-SOUTHTEX, LLC

70

28.5984810

-98.0090260

PRODUCING

13732

13348-13732

6/11/2001

4202533197

ONEAL GAS UNIT

8

BB-SOUTHTEX, LLC

452

28.6075430

-98.0037990

PRODUCING

15638

13565-13820

2/5/2003

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

~

LONQUIST

SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

4202533272

HENRY BUES GAS UNIT

11

BB-SOUTHTEX, LLC

70

28.598737

-98.008615

PRODUCING

13856

13291-15853

6/23/2004

4202533273

ONEAL GAS UNIT

9

BB-SOUTHTEX, LLC

452

28.6029540

-98.0025090

PRODUCING

13872

13311-16585

6/3/2004

4202533328

ONEAL GAS UNIT

11

BB-SOUTHTEX, LLC

126

28.6036340

-97.9982100

PRODUCING

13787

13318-15928

4/19/2005

4202533345

TOMASEK GAS UNIT

8

BB-SOUTHTEX, LLC

126

28.608282

-97.991595

PRODUCING

13692

13293-16378

8/14/2004

4202533371

ONEAL GAS UNIT

12

BB-SOUTHTEX, LLC

452

28.6097460

-98.0027040

PRODUCING

13819

13313-16635

8/15/2006

4202533383

HENRY BUES GAS UNIT

15

BB-SOUTHTEX, LLC

70

28.600322

-98.00874

PRODUCING

13811

13302-15768

10/8/2006

4202533492

ONEAL GAS UNIT

13

BB-SOUTHTEX, LLC

70

28.605326

-98.012928

PRODUCING

13859

13382-14761

7/7/2007

4202533553

ONEAL GAS UNIT

14

BB-SOUTHTEX, LLC

127

28.613869

-98.000504

PRODUCING

13674

13450-15424

2/11/2008

4202533559

OVERBY GAS UNIT

2E

BB-SOUTHTEX, LLC

452

28.6011410

-98.0028580

PRODUCING

13734

13372-13734

3/23/2008

42025E2114

NO RECORD

NR

NO RECORD

126

28.608457

-97.995683

NO RECORD

NR

NO RECORD

NR

*Note: Well entries in red penetrate the upper confining layer.

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

APPENDIX B-2

Area of Review: Freshwater Wells List

WELL REPORT/ID NO.

OWNER'S NAME

OWNER ADDRESS

CITY/STATE/ZIP

LAT. WGS 84

LONG. WGS 84

WELL USE

WATER LEVEL (FT.)

TOTAL DEPTH (FT.)

DATE DRILLED

128936

JOHN DAVIDSON

12761 FM 673

KENEDY, TX 78119

28.606667

-98.011667

DOMESTIC

48

114

11/19/2007

7832308

HENRY BUES

NO RECORD

NO RECORD

28.598334

-98.012223

STOCK

-

150

1960

7925105

T. M. PLUMER

NO RECORD

NO RECORD

28.595556

-97.997778

STOCK

77

275

1931

7832309

W. A. MUELLER

NO RECORD

NO RECORD

28.608612

-98.005834

UNUSED

63

90

1925

7925106

R.C. HUNT ESTATE

NO RECORD

NO RECORD

28.593889

-97.997222

UNUSED

137

172

1925

O'Neal Gas Unit No. 4
Area of Review: Freshwater Wells List - Texas Water Development Board
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------
Request for Additional Information: O'Neal Gas Unit Well No. 4

March 1, 2024

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

1.

NA

NA

There is a lack of consistency with hyphens, holding, quotation
marks, spelling, and capitalization in the MRV plan. Examples
include but are not limited to:

Loann salt vs. Louann salt
C02 vs. C02

We recommend reviewing the formatting in the MRV plan for
consistency. Furthermore, we recommend doing an additional
review for spelling, grammar, etc.

The document has been reviewed and edited to address the
issues identified. There are numerous edits made to the MRV
plan: 1) in response to this RAI; 2) in grammatical edits
subsequent to the RAI responses for better clarification; and 3)
deletions of material no longer relevant based on these edits.

2.

Multiple

Multiple

There are several references to "production" in the MRV plan,
such as, "Any vertical migration from the Injection Zone would
return the C02to the production zone" (p. 52). However, the
plan indicates that "no C02 will be produced" (p. 72).

In the MRV plan, please provide additional explanation as to
whether any C02 is produced at this facility and what the
relationship of the facility is to any producing wells.

These references have been edited to clarify the use of
"production". The intent is to utilize shallower hydrocarbon
production formations as an early indicator of vertical migration
of C02 from the Sligo. These wells would act as an above zone
monitoring well in that they can provide early indication of C02
release and protect the USDW. No C02 is intended to be
produced.

3.

2.2.4

23

"Based on the results of the investigation, in-situ Sligo reservoir
fluid is anticipated to contain approximately 150,000 parts per
million TDS..."

This value differs from what is listed in Table 3. Please ensure
all values mentioned in the text are consistent with what is
listed in the tables.

This has been edited to reference only Sligo fluid samples. In the
absence of an actual sample from the O'Neal No. 4, we took a
conservative approach and rounded down to 150,000 ppm. This
would yield a slightly larger plume, thus being conservative

1

-------
No.

MRV Plan

EPA Questions

Responses

Section

Page

4.

2.8.1

41-45

We recommend including units in Figures 25-28.

A scale has been added to these figures.

5.

Table 8

52

Please explain what is meant by Post Injection Site Care
periods and UCZs in Table 8. These terms are not defined in the
plan.

Table 7 (previously 8) has been updated to define these terms.

6.

Table 8

52

The leakage characterization for "Existing wells within the
MMA" is described as "Unlikely. The lateral continuity of the
UCZ is recognized as a very competent seal."

Please explain why the competence of the seal would affect
potential leakage through wells, and/or update this text as
necessary.

Table 7 has been edited to clarify this comment.

7.

Table 8

52

The magnitude of potential leakage for each potential leakage
pathway is described as "low". Please elaborate what is meant
by this characterization.

A Magnitude Assessment Description has been added to Table 7.

8.

Table 10

63

Table 10 appears to have been corrupted, we recommend
replacing this table.

Table 9 (previously 10) has been updated.

9.

5.1/6.4

64/69

"Should leakage be detected during active injection operations,
the volume of C02 released will be calculated based on
operating conditions at the time of the event, per 40 CFR
§98.448(a)(5)".

We recommend also referencing 40 CFR 98.444(d) here.

40 CFR 98.444(d) has been added to both sections.

10.



69

Please clarify what types of measurements will be taken for the
soil gas and water sampling. Is this different from what is
described in "6.5 Groundwater Monitoring"? Furthermore,
does "fixed monitors" refer to H2S monitors, C02 monitors, or
both?

Sections 6.2 and 6.5 have been updated.

Fixed monitors and detectors refer to H2S monitors, as H2S is a
proxy for C02 as it is a combined gas stream. The operating areas
must have H2S monitors for safety requirements.

11.

5.4

67

Please include additional discussion on the potential risk for
induced seismicity. For example, will the facility take
precautions to ensure that seismicity is not induced?

Language has been added to Section 5.4 for monitoring and
mitigation of induced seismicity.

2

-------
No.

MRV Plan

EPA Questions

Responses

Section

Page

12.

7.5

73

"COzfi = Total annual C02 mass emitted (metric tons) from
equipment leaks and vented emissions from equipment
located on the surface between the flow meter used to
measure injection quantity and the injection wellhead"

Per 40 CFR 98.443(F)(2), this variable should be "C02fi = Total
annual C02 mass emitted (metric tons) from equipment leaks
and vented emissions from equipment located on the surface
between the flow meter used to measure injection quantity
and the injection wellhead, for which a calculation procedure is
provided in subpart W of this part." Equations and variables
cannot be modified from the regulations. Please revise this
section and ensure that all equations listed are consistent with
the text in 40 CFR 98.443.

This equation is confirmed to be consistent with 40 CFR
98.443(F)(2).

13.

8

74

Per 40 CFR 98.448(a)(7), please include a specific "proposed
date to begin collecting data for calculating total amount
sequestered according to equation RR-11 or RR-12 of this
subpart. This date must be after expected baselines as required
by paragraph (a)(4) of this section are established and the
leakage detection and quantification strategy as required by
paragraph (a)(3) of this section is implemented in the initial
AMA."

The Class II permit is still in-process with the TRRC. Until this is
issued, Ozona cannot specify a date certain. The plan provides
for all baseline testing and results prior to commencing of
injection. Upon approval of the MRV plan and completion of the
baseline testing, Ozona will commence data collection for
reporting sequestered quantities.

3

-------
'Ozona

Carbon Capture & Sequestration

Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
O'Neal Gas Unit Well No. 4

Bee County, TX

Prepared for Ozona CCS, LLC
San Antonio, TX

By

Lonquist Sequestration, LLC
Austin, TX

Version 2.0
January 2024

LONQUIST

SEQUESTRATION LLC

~

-------
INTRODUCTION

Ozona CCS, LLC ("Ozona") has a pending Class II acid gas injection ("AGI") permit application with
the Texas Railroad Commission ("TRRC"), which was submitted in September of 2023, for its
O'Neal Gas Unit Well No. 4 ("O'Neal No. 4"), API No. 42-025-32658. Granting of this application
would authorize Ozona to inject up to 1.5 million standard cubic feet per day ("MMscf/d") of
treated acid gas ("TAG") into the Sligo formation at a depth of 15,874 feet to 16,056 feet with a
maximum allowable surface pressure of 7,920 psig. The TAG for this AGI well is associated with
StarTex's Pawnee Gas Plant (the "Plant"), located in a rural area of Bee County, Texas,
approximately 2.0 miles south of Pawnee, Texas, as shown in Figure 1.

L

in»4l Lit IU *4

I '



|

1-	



r* \ (Midiim.'&iMiii





	

4- OfmM Gm Unc r<4

5 /

-ft Gm M





/



"*"0'Neal Ga* Un* «4



28-602915, 98 001428



/



1:50.000

/

0 12 3 4

/

## OTiW

1 ¦ J MlltS



Figure 1 - Location of StarTex Gas Plant and the O'Neal No. 4

Subpart RR MRV Plan - O'Neal No. 4

Page 2 of 77

-------
Ozona is submitting this Monitoring, Reporting, and Verification ("MRV") plan to the EPA for
approval under 40 CFR 98.440(a), Subpart RR, of the Greenhouse Gas Reporting Program
("GHGRP"). In addition to submitting this MRV plan to the EPA, Ozona has applied to the TRRC
for the O'Neal GU No. 4's Class II permit. Ozona plans to inject TAG for approximately 12 years.
Table 1 shows the expected composition of the gas stream to be sequestered from the nearby
StarTex Pawnee Gas Plant.

Table 1 - Expected TAG Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

Subpart RR MRV Plan - O'Neal No. 4

Page 3 of 77

-------
ACRONYMS AND ABBREVIATIONS

%

°c

°F

AMA
BCF
CH4
CMG

C02
E

EOS

EPA

ESD

FG

ft

GAPI

GAU

GEM

GHG

GHGRP

GL

H2S

JPHIE

mD

mi

MIT

MM

MMA

Subpart RR MRV Plan - O'Neal No. 4

Percent (Percentage)

Degrees Celsius
Degrees Fahrenheit
Active Monitoring Area
Billion Cubic Feet
Methane

Computer Modelling Group

Carbon Dioxide (may also refer to other Carbon
Oxides)

East

Equation of State

U.S. Environmental Protection Agency
Emergency Shutdown
Fracture Gradient
Foot (Feet)

Gamma Units of the American Petroleum Institute
Groundwater Advisory Unit
Computer Modelling Group's GEM 2023.2
Greenhouse Gas

Greenhouse Gas Reporting Program
Ground Level Elevation
Hydrogen Sulfide

Effective Porosity (corrected for clay content)

Millidarcy

Mile(s)

Mechanical Integrity Test
Million

Maximum Monitoring Area

Page 4 of 77

-------
MCF	Thousand Cubic Feet

MMcf	Million Cubic Feet

MMscf	Million Standard Cubic Feet

Mscf/D	Thousand Standard Cubic Feet per Day

MMscf/D	Million Standard Cubic Feet per Day

MRV	Monitoring, Reporting, and Verification

v	Poisson's Ratio

N	North

NW	Northwest

OBG	Overburden Gradient

PG	Pore Gradient

pH	Scale of Acidity

ppm	Parts per Million

psi	Pounds per Square Inch

psig	Pounds per Square Inch Gauge

S	South

SE	Southeast

SF	Safety Factor

SWD	Saltwater Disposal

TAC	Texas Administrative Code

TAG	Treated Acid Gas

TOC	Total Organic Carbon

TRRC	Texas Railroad Commission

UIC	Underground Injection Control

USDW	Underground Source of Drinking Water

W	West

Subpart RR MRV Plan - O'Neal No. 4

Page 5 of 77

-------
TABLE OF CONTENTS

INTRODUCTION	2

ACRONYMS AND ABBREVIATIONS	4

SECTION 1 - UIC INFORMATION	10

1.1	Underground Injection Control Permit Class: Class II	10

1.2	UIC Well Identification Number	10

1.3	Facility Address	10

SECTION 2 - PROJECT DESCRIPTION	11

2.1	Regional Geology	11

2.1.1	Geologic Setting and Depositional Environment	13

2.1.2	Regional Structure and Faulting	15

2.2	Site Characterization	17

2.2.1	Stratigraphy and Lithologic Characteristics	17

2.2.2	Upper Confining Interval - Pearsall Formation	19

2.2.3	Injection Interval - Upper Sligo Formation	21

2.2.4	Formation Fluid	23

2.2.5	Fracture Pressure Gradient	24

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations	24

2.3	Local Structure	25

2.4	Injection and Confinement Summary	30

2.5	Groundwater Hydrology	30

2.6	References	34

2.7	Description of the Injection Process	35

2.7.1 Current Operations	35

2.8	Reservoir Characterization Modeling	35

2.8.1 Simulation Modeling	39

SECTION 3- DELINEATION OF MONITORING AREA	48

3.1	Maximum Monitoring Area	48

3.2	Active Monitoring Area	50

SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE	52

4.1	Leakage from Surface Equipment	52

4.2	Leakage Through Existing Wells Within the MMA	55

4.2.1	Future Drilling	58

4.2.2	Groundwater Wells	58

4.3	Leakage Through Faults and Fractures	60

4.4	Leakage Through the Confining Layer	60

4.5	Leakage from Natural or Induced Seismicity	60

SECTION 5 - MONITORING FOR LEAKAGE	63

5.1	Leakage from Surface Equipment	64

5.2	Leakage Through Existing and Future Wells Within the MMA	64

5.3	Leakage Through Faults, Fractures, or Confining Seals	67

5.4	Leakage Through Natural or Induced Seismicity	67

Subpart RR MRV Plan - O'Neal No. 4

Page 6 of 77

-------
SECTION 6-BASELINE DETERMINATIONS	69

6.1	Visual Inspections	69

6.2	CO2/H2S Detection	69

6.3	Operational Data	69

6.4	Continuous Monitoring	69

6.5	Groundwater Monitoring	70

SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION	71

7.1	Mass of CO2 Received	71

7.2	Mass of CO2 Injected	71

7.3	Mass of CO2 Produced	72

7.4	Mass of CO2 Emitted by Surface Leakage	72

7.5	Mass of CO2 Sequestered	73

SECTION 8-IMPLEMENTATION SCHEDULE FOR MRV PLAN	74

SECTION 9 - QUALITY ASSURANCE	75

9.1	Monitoring QA/QC	75

9.2	Missing Data	75

9.3	MRV Plan Revisions	76

SECTION 10 - RECORDS RETENTION	77

Figures

Figure 1 - Location of StarTex Gas Plant and the O'Neal No. 4	2

Figure 2 - Structural features of the Gulf of Mexico and locator map (modified from Roberts-

Ashby etal., 2012)	11

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining
intervals. Offset productive intervals are noted with a green star (modified from Roberts-Ashby

etal., 2012)	12

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The
proposed injection interval is shaded light blue and proposed confining intervals are shaded light

yellow (modified from Bebout, D.G., et al., 1981)	13

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bebout, D.G., et al., 1981)	14

Figure 6-Generalized northwest to southeast schematic cross-section of the Trinity Group, south

Texas	15

Figure 7 - Depositional model for the Lower Cretaceous carbonate platform w/ estimated
porosity and permeability values of typical facies (modified from Talbert and Atchley, 2000) .. 15
Figure 8 - Structural features and fault zones near the proposed injection site. The red star
represents the approximate location of the O'Neal No. 4 (modified from Swanson S.M., et al.,

2016)	16

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through
Word field, northeast of the O'Neal No. 4 project area (modified from Swanson S.M., et al., 2016)

	17

Figure 10 - Type Log with tops, confining, and injection intervals depicted	18

Subpart RR MRV Plan - O'Neal No. 4	Page 7 of 77

-------
Figure 11 - Porosity-permeability cross-plot of Pearsall Formation crushed rock core data

(Swanson S.M., et al., 2016)	20

Figure 12 - Seismic line across the Stuart City (Edwards/Buda) shelf margin and locator map.. 20
Figure 13 - Environmental setting of Lower Cretaceous Platform (Bebout, D.G., et al., 1981)...21
Figure 14 - Open-hole log from the O'Neal No. 4 (API No. 42-025-32658). Porosity curves shaded

green >0%, permeability curve shaded blue >0 mD, and resistivity shaded red > 5 ohms	22

Figure 15 - Offset wells used for formation fluid characterization	23

Figure 16 - Environmental setting of Lower Cretaceous tidal flat deposits (Bebout, D.G., et al.,

1981)	25

Figure 17 - Subsea Structure Map: top of Sligo (injection interval). The red star signifies the

location of the O'Neal No. 4	27

Figure 18 - Northwest to Southeast Structural Cross-Section: A-A' Oriented along regional dip.
The red star signifies the location of the O'Neal No. 4. Line of section is depicted in red on locator

map	28

Figure 19 - Southwest to Northeast Structural Cross-Section: B-B' Oriented along regional strike.
The red star signifies the location of the O'Neal No. 4. The Line of section is depicted in blue on

locator map	29

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of

the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	31

Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury, A.H. and Turco, M.J.,

2006)	32

Figure 22 - Cross-Section S-S' across the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	32

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the

approximate location of the O'Neal No. 4 (modified from Bruun, B., et al., 2016)	33

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model	37

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection)	41

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)	42

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

	44

Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End

of Simulation)	45

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time	46

Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum

Monitoring Area	49

Figure 31 - Active Monitoring Area	51

Figure 32 - O'Neal No. 4 Wellbore Schematic	54

Figure 33 - All Oil and Gas Wells Within the MMA	56

Figure 34 - Oil and Gas Wells Penetrating the Gross Injection Interval Within the MMA	57

Figure 35 - Groundwater Wells Within the MMA	59

Figure 36 - 25 km Seismicity Review	62

Figure 37 - Groundwater Wells	66

Figure 38 - Seismic Events and Monitoring Station	68

Subpart RR MRV Plan - O'Neal No. 4

Page 8 of 77

-------
Tables

Table 1 - Expected TAG Composition	3

Table 2 - Analysis of Lower Cretaceous (Albian) age formation fluids from seven nearby Edwards

oil-field brine samples	24

Table 3 - Analysis of Lower Cretaceous (Aptian) age formation fluid from the closest offset Sligo

oil-field brine sample	24

Table 4 - Gas Composition	35

Table 5 - Modeled Injectate Composition	36

Table 6 - GEM Model Layer Package Properties	38

Table 7 - Bottomhole and Wellhead Pressures from the Start of Injection	47

Table 8 - Potential Leakage Pathway Risk Assessment	52

Table 9 - Summary of TAG Detectors and Equipment	53

Table 10 - Summary of Leakage Monitoring Methods	63

Appendices

Appendix A - TRRC O'Neal Gas Unit Well No. 4 Forms

Appendix A-l - GAU Groundwater Protection Determination
Appendix A-2 - Drilling Permit
Appendix A-3 - Completion Report
Appendix A-4 - Plugging Records

Appendix B - Area of Review

Appendix B-l - Oil and Gas Wells Within the MMA List
Appendix B-2 - Water Wells Within the MMA List

Subpart RR MRV Plan - O'Neal No. 4

Page 9 of 77

-------
SECTION 1 - UIC INFORMATION

This section contains key information regarding the Underground Injection Control (UIC) Permit.

1.1	Underground Injection Control Permit Class: Class II

The TRRC regulates oil and gas activities in Texas and has primacy to implement the Underground
Injection Control ("UIC") Class II program. TRRC classifies the O'Neal No. 4 as a UIC Class II well.
Ozona has applied for a Class II permit for the O'Neal No. 4 under TRRC Rule 36 (entitled "Oil, Gas,
or Geothermal Resource Operation in Hydrogen Sulfide Areas") and under TRRC Rule 46 (entitled
"Fluid Injection into Productive Reservoirs").

1.2	UIC Well Identification Number

• O'Neal No. 4, API No. 42-025-32658, UIC # 56819

1.3 Facility Address

•	Gas Plant Facility Name: StarTex Pawnee Gas Plant

•	Operator: StarTex Field Services, LLC

•	Coordinates in NAD83 for this facility:

o Latitude: 28.622211
o Longitude: -97.992772

Subpart RR MRV Plan - O'Neal No. 4

Page 10 of 77

-------
SECTION 2 - PROJECT DESCRIPTION

This section discusses the geologic setting, planned injection process and volumes, and the
reservoir and plume modeling performed for the O'Neal No. 4.

The O'Neal No. 4 will inject the TAG stream into the Sligo formation at a depth of 15,874 feet to
16,056 feet, and approximately 14,924 feet below the base of the Underground Source of
Drinking Water (USDW). Therefore, the well and the facility are designed to protect against the
leakage out of the injection interval, to protect against contaminating other subsurface
formations, and most critically to prevent surface releases.

2.1 Regional Geology

The O'Neal No. 4 (API No. 42-025-32658) is located in south Texas within the Gulf of Mexico
Basin, The onshore portion of the Gulf of Mexico basin spans approximately 148,049,000 acres
and encompasses portions of Texas, Louisiana, Mississippi, Alabama, Arkansas, Missouri,
Kentucky, Tennessee, Florida, and Georgia to the state-waters boundary of the United States
(Roberts-Ashby et a I., 2012). The location of the O'Neal No. 4 is designated by the red star in
Figure 2 relative to the present coastal extent and major structural features of the basin.

al., 2012)

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Figure 3 depicts a generalized stratigraphic column of the U.S. Gulf Coast with light blue shading
signifying the proposed injection interval and green stars indicating productive formations
identified within five miles of the O'Neal No. 4. The injection interval is found within the Sligo
formation with confinement provided by the overlying Pearsall formation and tight underlying
fades of the Lower Sligo and Hosston formations.

System /
Series

Global
Chronostratigraphic
Units

Calabrian

Piacenzian
Zanclean

Messinian
Tortonian
Serravallian

Langhian
Burdigalian
Aquitanian

Chattian

Rupelian

Priabonian

Bartonian
Lutetian

Ypresian

Thanetian
Selandian
Danian

Maastrichtian

Campanian

Santonian
Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian
Hauterivian

Valanginian
Berriasian

North American
Chronostratigraphic
Units

M.ddie Mioc. Fleming Fm

Chickasawhayan

Vicksburgian

Jacksonian

Claibornian

Sabinian

Midwayan

Navarroan

Tayloran

Austinian

Eaglefordian

Woodbinian

Washitan-
Fredericksburgian

Trinitian

Nuevoleonian

Durangoan

Stratigraphic Unit

Undifferentiated

Undifferentiated

Upper Mioc.

Lower Mioc.

~ Catahoula
Fm/Ss

Frio Formation

Vicksburg Formation

Jackson Group

Sparta Sand

Claiborne Group Cane River Fm

	Carnzo Sand

Wilcox Group

Midway Group

Navarro Group

Taylor Group

Austin Group /
Tokio Formation /
Eutaw Formation

Eagle Ford Shale

Woodbine / Tuscaloosa Fms

Washita Group
(Buda Ls)

Fredericksburg Group ^
(Edwards Ls / Paluxy Fm)^

Glen Rose Ls
(Rusk/ Rodessa Fms)

Pearsall FormationW

Sligo^

Hosston
Formation

Fm

UPPER CONFINING INTERVAL
INJECTION INTERVAL

LOWER CONFINING
INTERVAL

Figure 3 - Stratigraphic column of the U.S. Gulf Coast signifying proposed injection and confining intervals.
Offset productive intervals are noted with a green star (modified from Roberts-Ashby et al., 2012)

Subpart RR MRV Plan - O'Neal No. 4

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The targeted formations of this study are located entirely within the Trinity Group, as clarified by
the detailed stratigraphic column provided in Figure 4. During this time the area of interest was
located along a broad, shallow marine carbonate platform that extended along the northern rim
of the ancestral Gulf of Mexico, The Lower Cretaceous platform spanned approximately 870
miles from western Florida to northeastern Mexico with a shoreline to basin margin that ranged
between 45 to 125 miles wide (Yurewicz, D.A., et al, 1993),

CO
D
O

UJ

O
<
>—

UJ

GL

o



a
a

D

oj

5

Turonian

Cenomanian

Albian

Aptian

Barremian

Hauterivian

Eagle Ford

Washita

Buda

Del Rio

Georgetown

Edwards

Stuart

City

Glen Rose

a

3
O

a

'£

Pear:

Sliao

Hosslon

?

Figure 4 - Detailed stratigraphic column of Lower Cretaceous formations of south Texas. The proposed
injection interval is shaded light blue and proposed confining intervals are shaded light yellow (modified
from Bebout, D.G., et al., 1981)

2.1.1 Geologic Setting and Depositional Environment

The depositional environment during the Lower Cretaceous generally consisted of a well-defined
platform margin with a shallow marine platform interior or lagoon to the north, a shallow marine
outer platform to the south, and a foreslope that gradually dipped southward towards the basin
center. The platform margin remained stable for tens of millions of years during the Cretaceous
but experienced episodic changes in sea level that resulted in cyclic deposition of several key
facies that vary both spatially and within the geologic section. Facies distributions were heavily
impacted by positioning relative to the margin, the height of the watercolumn at any given time,
and the degree of energy or wave action within the system (Galloway, 2008; Yurewicz, D.A., et
al, 1993).

In general, long stands of reef development and ooid shoaling developed primary porosity and
permeability along the shallow, high-energy carbonate platform and represent reservoir quality
rock found within Cretaceous reef deposits. Deeper, basinward deposits tend to result in tighter

Subpart RR MRV Plan - O'Neal No. 4

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petrophysical properties due to a relative increase in the amount of entrained clay associated
with the heightening of the water column whilst moving down-slope. Backreef deposits have the
potential for porosity development but tend to have low permeability due to a general lack of
wave action caused by restricted access to open water by the platform margin. Facies and
petrophysical properties of the Lower Cretaceous section are anticipated to be relatively
homogenous moving southwest-northwest along reef trend with increased heterogeneity
moving northwest-southeast due to the orientation of the carbonate rim and its effect on
deposition and facies distributions (Yurewicz, D.A., et al, 1993).

Figure 5 displays the paleogeography during deposition of the Lower Cretaceous section to
visually demonstrate the position of the O'Neal No. 4 relative to the Sligo shelf margin and up-
dip extents of Sligo deposition. A generalized schematic cross-section of the Trinity Group is
provided in Figure 6 which nearly intersects the project area from the northwest. The schematic
illustrates the gross section thickening basinward with primary reservoir development improving
with proximity to the reef margin. Figure 7 displays a depositional model of the Lower Cretaceous
carbonate platform to visually conceptualize depositional environments and anticipated
petrophysical properties of facies introduced above.

Figure 5 - Paleogeography of the Lower Cretaceous of south Texas. The red star represents the
approximate location of the O'Neal No. 4 (modified from Bebout, D.G., et al., 1981)

Subpart RR MRV Plan - O'Neal No. 4

Page 14 of 77

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Figure 6 - Generalized northwest to southeast schematic cross-section of the Trinity Group, south Texas.
The iine of section depicted in Figure 5. The red star and line represent the approximate location of the
O'Neal No. 4 (modified from Kirkland, B.L., et al., 1987)

0=15-25
K>200

=10-15
K=20-100

SHOAL

0=2-12
K<1

BACKREEF

FOREREEF W/N0 CLAY	u-

W CLAY

CLAY-RICH

LEGEND

Sedimentary Structures Grams

---v Current Ripple
—— RaserWsvy Bedding
—< mm LaminatiQrts
-v— Mud Cracks

- Planar and Festoon Bedding
\J Burrow Clay Seam

e 0»d (2> Oyster indrft
. Peloid *-> Bwahre untfff
t>Rudelundfl, & Gastropod
0 Solitary C
-------
associated with areas of variable crustal thickness arid local structuring caused by movement of
Louann salt (Yurewicz, DA, et al, 1993). The combination of these processes resulted in the
structural development of regional arches, grabens, uplifts, embayments, salt domes, and salt
basins around the northern edge of the basin (Dennen and Hackley, 2012; Galloway, 2008). The
location of these structural features can be referenced in Figures 2 and 8 relative to the location
of the O'Neal No, 4.

The schematic dip-oriented cross-section displayed in Figure 9 presents a common interpretation
of the current structural setting. Most of the published literature suggests faulting near the
project area is restricted to the shallower, overlying Cenozoic section, as seen in Figure 9, with
shallow faulting dying out before reaching the Pearsall formation. However, one source did
interpret the potential for faulting to the south (Swanson S.M., et al., 2016). The closest potential
fault is depicted in Figure 8 relative to the location of the O'Neal No. 4. According to the map,
the interpreted fault lies approximately 4.25 miles south-southeast of the well and approximately
3.9 miles south-southeast of the stabilized plume extent in the year 2047.

50

50
. I

~r—r

100 Kilometers

100 Miles
J	I

EXPLANATION
Uplift

Plateau
Basin

TPS boundary
Fault zone

Lower Cretaceous shelf margin

	County line

* Field in Edwards Limestone
associated with fault zones

O Salt structure

Y' Anticlinal axis; large arrow indicates
^ direction of plunge

GOM Gulf of Mexico

Figure 8 — Structural features and fault zones near the proposed injection site. The red star represents
the approximate location of the O'Neal No. 4 (modified from Swanson S.M., et al., 2016)

Rio Grande
embayment

Subpart RR MRV Plan - O'Neal No. 4

Page 16 of 77

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NW

Published
Edwards Ls.
shelf margin

SE

Word field

1 Kilometer

I Edwards Limestone, potential reservoir
facies (shallow-water facies)

Pearsall Fm.

~ Sligo Formation, wedges of downslope
debris



Fault

Figure 9 - Northwest to southeast schematic interpretation of the Edwards shelf margin through Word
field, northeast of the O'Neal No. 4 project area (modified from Swanson S.M., et al., 2016)

2.2 Site Characterization

The following section discusses site-specific geological characteristics of the O'Neal No. 4.
2.2.1 Stratigraphy and Lithologic Characteristics

Figure 10 depicts openhole logs from two offset wells (API No. 42-025-00473 and API No. 42-025-
31892) to the O'Neal No. 4 indicating the injection and primary upper confining zone. The
Tomasek No. 1 (API: No. 42-025-00473) is located approximately 1 mile northeast of the O'Neal
No. 4 and displays the shallow section from 0-8,200 ft. The Gordon No. 3 (API: No, 42-025-31892)
is located approximately 1.6 miles northeast of the O'Neal No. 4 and displays a shallow section
from 8,200-16,400 ft.

Subpart RR MRV Plan - O'Neal No. 4

Page 17 of 77

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Figure 10 - Type Log with tops, confining, and injection intervals depicted

COOK_MOUNTA!N

BB-SOUTHTEX, LLC

TOMASEK GAS UNIT 1

V

42025004730000

BUQW

BASEJJSDW

SPARTA
WECHES SS

QUEEN_CITY

RECKLAW

CARRIZO
WILCOX

PIONEER NATURAL RESOURCES

A GORDON GAS UNITS

42025318920000

MIDWAY

AUSTIN
EAGLEFORD

EDWARDS

PRSL

Subpart RR MRV Plan - O'Neal No. 4

Page 18 of 77

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2.2.2 Upper Confining Interval - Pearsall Formation

Following the deposition of the Sligo formation, the Lower Cretaceous shelf was drowned by
eustatic sea-level rise and deposition of the deep-water Pine Island Shale Member of the Pearsall
formation throughout the region (Roberts-Ashby et al., 2012). The Pine Island shale consists of
alternating beds of pelagic mudstone, hemipelagic mudstone, and Fe-rich dolomitic mudstone
interpreted to have been deposited along the outer ramp. This is in agreement with core data
published by Bebout and others (1981) and later by Swanson and others (2016) who identified
the presence of C. Margerelli, a nannofossil indicative of anoxic conditions. The core-derived
porosity-permeability relationship displayed in Figure 11 suggests permeability of the Pine Island
Shale is incredibly low and stays below 0.0001 mD, regardless of porosity (Figure 11; Hull, D.C.,
2011). This is further supported by the 2012 USGS C02 Storage Resource Assessment, which
suggests the Pine Island shale contains the physical properties required to act as a regional seal
and was chosen as the upward confining interval for their C50490108 SAU assessment of the Gulf
Coast. The 2012 USGS report also noted that the Pine Island shale is a sufficient regional seal
with as little as 50 feet of contiguous shale development. The top of the Pearsall is encountered
at a depth of 15,339 feet in the O'Neal No. 4 with a gross thickness of 535 feet (Figure 14). The
Pine Island Shale member is approximately 130 feet thick at the O'Neal No. 4 location with
deposition of additional members of the overlying Pearsall formation, which include the Cow
Creek limestone, Cow Creek Shale, and Bexar Shale Members (Roberts-Ashby et al., 2012;
Swanson S.M., et al., 2016).

The seismic line displayed in Figure 12 runs northwest to southeast across the Stuart City reef
trend southwest of the project area. The top of Buda, Pearsall, and Sligo formation markers are
depicted in color to demonstrate the lateral continuity of the section near the O'Neal No. 4.
Seismic reflectors within the Pearsall formation appear to lack deformation suggesting consistent
deposition over the reef margin. This is in agreement with reviewed published literature which
suggests deposition of the Pine Island shale occurred during widespread marine transgression
(Bebout, D.G., et al., 1981; Hull, D.C., 2011.; Roberts-Ashby et al., 2012, Swanson S.M., et al.,
2016).

Subpart RR MRV Plan - O'Neal No. 4

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0.0001
(100 nd:

Permeability and Porosity-
Crushed Rock Data

T3

E

-Q
03
0)

E

-------
2.2.3 Injection Interval - Upper Sligo Formation

The Sligo Formation underlies the Pearsall Formation and is predominately composed of shelf-
edge limestones that were deposited along the Lower Cretaceous platform (Roberts-Ashby et a I.,
2012). However, the Cretaceous also experienced episodic changes in sea level that resulted in
the deposition of cyclic Sligo facies that vary both spatially and within the geologic section. The
overall Sligo interval is interpreted to be a transgressive sequence occasionally interrupted by
progradational cycles that consists of porous shoaling-upward sequences that represent primary
reservoir potential within the system (Bebout, D.G., et al., 1981). Facies distributions of these
reef complexes are heavily impacted by positioning relative to the margin, the height of the water
column at any given time, and the degree of energy or wave action within the system (Galloway,
2008). Figure 13 depicts an idealized environmental setting of the Lower Cretaceous Platform
during deposition. Primary porosity and permeability of the Upper Sligo formation tends to
develop in high-energy sequences with normal marine conditions that are dominated by the
deposition of oolitic and skeletal grainstones.

Figure 13 - Environmental setting of Lower Cretaceous Platform (Bebout, D.G., et al., 1981)

According to the 2012 USGS C02 Storage Resource Assessment, "the average porosity in the
porous intervals of the storage reservoir decreases with depth from 9 to 16 percent' for their
C50490108 DEEP SAU assessment of the Gulf Coast (>13,000 feet). The study also reported that
"the average permeability in the storage reservoirs decreases with depth from 0.05 to 200 mD,
with a most-likely value of 8 mD" for their C50490108 DEEP SAU assessment of the Gulf Coast
(Roberts-Ashby et al., 2012).

The top of the Upper Sligo is encountered at a depth of 15,874 feet in the O'Neal No, 4 with a
gross thickness of 183 feet (Figure 14). The type log displayed in Figure 14 plots the Effective
Porosity for the confining interval and the Total Porosity of the injection interval to account for

Subpart RR MRV Plan - O'Neal No. 4

Page 21 of 77

-------
the increased volume of shale ("Vshale") seen in the Pearsall formation. The porosity data was
compared to the analysis performed by Nutech to generate a permeability curve with a
reasonable porosity-permeability relationship. The permeability curve was generated utilizing
the Coates permeability equation incorporated with a 20% irreducible to match analysis provided
by Nutech. Petrophysical analysis of the O'Neal No. 4 indicates an average porosity of 4.6%, a
max porosity of 15%, an average permeability of 0.16 mD, and a max permeability of 3.3 mD.
These curves have been extrapolated to the injection site and used to establish reservoir
characteristics in the plume model.

BB-SOUTHTEX, LLC

ONEAL GAS UNIT 4

o

42025326580000

K_COATES20
10	0

PHIE

0.3 >0 % 0

Pearsall

Very Low Perm:
Pine Island Shale

Very Low Perm:
Lower Sligo

Figure 14 - Open-hole log from the O'Neal No. 4 (API No. 42-025-32658). Porosity curves shaded green
>0%, permeability curve shaded blue >0 mD, and resistivity shaded red > 5 ohms.

Subpart RR MRV Plan - O'Neal No. 4

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2.2.4 Formation Fluid

Eight wells were identified through a review of chemical analyses of oil-field brines from the U.S.
Geological Survey (USGS) National Produced Waters Geochemical Database v2.3 (Blondes, M.S.,
et al, 2018). Only one sample was taken from the Sligo formation in the region, located
approximately 30 miles north of the O'Neal No. 4. Therefore, the investigation was expanded to
compare Total Dissolved Solids (TDS) concentrations from other formations to improve
understanding of water chemistry variation in the area. The USGS database contained chemical
analysis for seven wells within three miles of the O'Neal. However, the samples were taken from
the Edwards reef section that lies approximately 2,000-2,500 feet above the top of Sligo. The
location of these wells is shown in Figure 15 relative to the O'Neal No. 4 and the Sligo water
sample identified to the north. A summary of water chemistry analyses conducted on Edwards
oil-field brines near the injection site is provided in Table 2. Chemical analysis of the identified
Sligo water sample is provided in Table 3. Based on the results of the investigation, in-situ Sligo
reservoir fluid is anticipated to contain approximately 150,000 parts per million ("ppm") TDS near
the O'Neal No. 4 and is compatible with the proposed injection stream.

Figure 15 - Offset wells used for formation fluid characterization

Subpart RR MRV Plan - O'Neal No. 4

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Table 2 - Analysis of Lower Cretaceous (Albian) age formation fluids from seven nearby Edwards oil-field
brine samples

Measurement

Average

Low

High

Total Dissolved Solids (mg/L)

79,573

60,794

110,300

Sodium (mg/L)

24,280

17,600

34,000

Calcium (mg/L)

5,137

3,320

8,320

Chloride (mg/L)

47,871

37,200

64,700

Sample Depth (ft)

13,940

13,778

14,043

Note: Edwards analysis does not contain pH values

Table 3 - Analysis of Lower Cretaceous (Aptian) age formation fluid from the closest offset Sligo oil-field
brine sample

Measurement

Value

Total Dissolved Solids (mg/L)

234,646

Sodium (mg/L)

51,168

Calcium (mg/L)

34,335

Chloride (mg/L)

146,500

Sample Depth (ft)

13,580 to 13,660

PH

5.85

Note: Sligo sample located approximately 30 miles north of the O'Neal No. 4

2.2.5	Fracture Pressure Gradient

The fracture pressure gradient was obtained from an acid fracture report taken during the April
1993 completion of the Sligo interval in the O'Neal No. 4. The Sligo was perforated between the
depths of 15,874 and 16,056 feet with continuous monitoring during pumping of the acid job.
The report noted a pressure break experienced at approximately 9,000 psi and calculated a
fracture gradient of 0.889 psi/ft based on an initial shut-in pressure ("ISIP") of 7,275 psi. A 10
percent safety factor was then applied to the calculated gradient resulting in a maximum allowed
bottom hole pressure of 0.8 psi/ft. This was done to ensure that the injection pressure would
never exceed the fracture pressure of the injection zone.

2.2.6	Lower Confining Interval - Lower Sligo and Hosston Formations

The O'Neal No. 4 reaches its total depth in the Lower Sligo formation, directly below the Upper
Sligo proposed injection interval. The Lower Sligo is interpreted by Bebout and others (1981) to
represent the seaward extension of the low-energy lagoon and tidal-flat system of the underlying
Hosston formation, a sequence of siliciclastics, evaporites, and dolomitic mudstone (Figure 16).
The Hosston to Lower Sligo 'contact' represents a gradational package with a decrease in

Subpart RR MRV Plan - O'Neal No. 4

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terrigenous sediments, an increase in carbonate sediments, and an increase in burrows of marine
organisms working up-section into the Lower Sligo. The Lower Sligo consists of numerous cycles
of subtidal to supratidal carbonates deposited in a low-energy lagoon and tidal-flat system
(Bebout, D.G., et al., 1981). These low-permeability facies of the Lower Sligo and underlying
Hosston formation will provide lower confinement to the Upper Sligo injection interval. Figure
16 illustrates the typical environmental setting for the deposition of tidal flat facies along the
Lower Cretaceous margin. The type log displayed in Figure 14 illustrates the porosity of the
Lower Sligo ranges between 0-2% with permeability staying close to 0 mD. Thus, the
petrophysical characteristics of the Lower Sligo and Hosston are ideal for prohibiting the
migration of the injection stream outside of the injection interval.

Figure 16 - Environmental setting of Lower Cretaceous tidal flat deposits (Bebout, D.G., et al., 1981)

2.3 Local Structure

Structures surrounding the proposed sequestration site were influenced by regional arches,
grabens, uplifts, embayments, movement of Loann salt, and the development of carbonate reef
complexes around the northern edge of the basin. However, one potential fault was identified
in the literature within proximity and lies approximately 4.25 miles south-southeast of the well
and approximately 3.9 miles south-southeast of the stabilized plume extent in the year 2062
(Swanson S.M., et al., 2016). The location of these structural features can be referenced in
Figures 2 and 8 relative to the location of the O'Neal No. 4.

A subsea true vertical depth ("SSTVD") structure map on the top of the Sligo formation is
provided in Figure 17. The map illustrates the gentle basinward dip of the Sligo formation from
the northwest to the southeast. The structural cross-sections provided in Figures 18 and 19
illustrate the structural changes encountered moving away from the O'Neal No. 4 site. The
figures also demonstrate the laterally continuous nature of the Pearsall formation that overlies
the injection interval with sufficient thickness and modeled petrophysical properties to alleviate

Subpart RR MRV Plan - O'Neal No. 4

Page 25 of 77

-------
the risk of upward migration of injected fluids. Please see section 2.1.2 discussing Regional
Structure and Faulting for a regional discussion pertinent to this topic.

Subpart RR MRV Plan - O'Neal No. 4

Page 26 of 77

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Legend
^ SHL C.I. = 200'

Edwards Reef Trend

Sligo Reef Trend

-iwoo ...
o Sligo Penetration









&





-12,450

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-15,594

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—

-12600

—

-12800

—

-13003

—

-13203

—

-13400

—

-13600

—

-13S03

—

-HOOD

—

-14200

—

-14400

—

-14600

—

-14800

—

-15030

—

-15203

—

-15400

—

-15600

—

-15-803

—

-16003

—

-16200

—

-16403

—

-18603

—

-16803

I—

-17000

—

Ozoca CCS LLC

Figure 17 - Subsea Structure Map: top of Sligo (injection interval). The red star signifies the location of the O'Neal No. 4
Subpart RR MRV Plan - O'Neal No. 4	Page 27 of 77

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13600
13700
13800
13900
TtoflT
14100
14200
14300
14400

Logged
cased
hole in
EDRD,
DPHI ^
Over-
estimated

TS5W

14600
14700
14800

14500
14600
14700
14800

15000
15100
15200

15000
15100
15200

15400
15500
15600
15700
15800
15900
16000

15400
15500
15600
15700
15800

16000

16100
16200
16300
16400
16500
16600
16700

[ ) Injection Reservoir
Color Fill

ASTN

LEGFD

EDRD

PRSL

SLGO

SLGOJNJ
BASE

PRSL

Jpper Confining Zone
(Pearsall Formation)

Injection Reservoir SLGO
(Sligo Formation)

SLGOJNJ
BASE

16700
16800

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200
13300
13400
13500
13600
13700
13800
13900
14000
14100
14200
14300
14400

16100
16200
16300
16400
16500
16600

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200
13300
13400

13600

13700
13800
13900
14000
14100
14200
14300
14400
14500
14600
14700
14800
14900
15000
15100
15200
15300
15400
13388
15600
15700
15800
15900

16100
16200
16300

11700
11800
11900
12000
12100
12200
12300
12400
12500
12600
12700
12800
12900
13000
13100
13200

tmr

13400

Figure 18 - Northwest to Southeast Structural Cross-Section: A-A' Oriented along regional dip. The red star signifies the location of the O'Neal
No. 4. Line of section is depicted in red on locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 28 of 77

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422973335100
MCMORAN EX Ft CO
DUUAHAN JOSE PHI fC

422973332700
SPARTAN PETRO CORP
STRIDDE OSCAR

420253265800
33-SOU1HTEX LLC
OVERS Y CmfiP. LIE C GA

420253189200
PIONEER NAT RES USA
ROESSLER GAS UMT

42025315210000
SESCARES CORF
BOONEJACKEBETAL

14250
14300
14350
14400
14450
14500
14550

14400
14450
14500
14550
14600
14650
14700
14750
14800
14850
14900
14950
15000
15050
15100
15150
15200
15250
15300

14500
14550
14600

14300
14350
14400
14450
14500
14550
14600

14450
14500
14550
14600
14650
14700
14750

Logged

cased

hole in

EDRD,

DPHI

Over-

14650
14700
14750
14800
14850
14900
14950

14600

"T4650'
14700
14750
14800

ASTN
LEGFD

14650

14850
14900
14950
15000
15050
15100

14700

estimated

14750

15000
15050
15100
15150
15200
15250
15300
15350
15400
T52ST
15500
15550
15600
15650
15700
15750
15800
15850
15900
15950
16000
16050
16100
16150
16200
16250
16300
16350

BUDA

14850
14900
14950
15000
15050

14900
14950
15000
15050

Upper Confining Zone
(Pearsall Formation)

'fir j
15200
15250
15300
15350
15400
15450

DLRO

15100
15150
15200

15100

EDRD

15150
15200
15250
15300
15350
15400
15450
15500
15550
15600
-15650-

T535U"
15400
15450
15500
15550
15600

SLGO

15250
15300
15350
15400
15450
15500
15550

15500

Injection Reservoir
(Sligo Formation)

15550
15600
15650
15700
15750
15800
15850
15900
15950

SLGOJNJ
BASE

15650
15700
15750

15700
15750
15800
15850
15900
15950
16000
ifiren

15900
15950
16000

15800
15850

16000
16050
16100
16150

15900

15950
16000

16100
16150
16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750
16800
16850
16900
16950
17000
17050
17100
17150
17200
17250

~ Injection Reservoir
Color Fill

16050

16200
16250
16300
16350
16400
16450
16500
16550
16600
16650
16700
16750

16100
16150
16200
16250
16300
16350

16100
16150
16200

16250

KARNES

16300
16350

ATASCOSA

16400
16450
16500
16550

16400
16450
16500
16550
16600

16600
16650

SLGO

16650
16700
16750
16800
16850

16700
16750
16800
16850

16850
16900
16950
17000
17050
17100
17150
17200
17250

SLGOJN
BASE

16900
16950
17000
17050
17100

16950
17000
17050
17100

Figure 19 - Southwest to Northeast Structural Cross-Section; B-B' Oriented along regional strike. The red star signifies the location of the O'Neal
No. 4. The Line of section is depicted in blue on locator map.

Subpart RR MRV Plan - O'Neal No. 4

Page 29 of 77

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2.4 Injection and Confinement Summary

The lithologic and petrophysical characteristics of the Sligo formation at the O'Neal No. 4 location
indicate the reservoir contains the necessary thickness, porosity, and permeability to receive the
proposed injection stream. The overlying Pearsall formation is regionally extensive at the O'Neal
No. 4 location with low permeability and sufficient thickness to serve as the upper confining interval.
Beneath the injection interval, the low permeability, low porosity facies tidal flat and lagoonal facies
of the Lower Sligo and underlying Hosston formation are unsuitable for fluid migration and serve as
the lower confining interval.

2.5 Groundwater Hydrology

Bee County falls within the boundary of the Bee Groundwater Conservation District. Only one
aquifer is identified by the Texas Water Development Board's Texas Aquifers Study near the O'Neal
No. 4 location, the unconfined to semi-confined Gulf Coast Aquifer. The Gulf Coast Aquifer parallels
the Gulf of Mexico and extends across the state of Texas from the Mexican border to the border of
Louisiana (Bruun, B., et al., 2016). The extents of the Gulf Coast Aquifer are provided in Figure 20
below for reference.

The Gulf Coast Aquifer is a major aquifer system comprised of several individual aquifers: the Jasper,
Evangeline, and Chicot. These aquifers are composed of discontinuous clay, silt, sand, and gravel
beds that range from Miocene to Holocene in age (Figure 21). Numerous interbedded lenses and
layers of silt and clay are present within the aquifers which can confine individual aquifers locally.
The underlying Oligocene Catahoula tuff represents the lower confining interval but it should be
noted the formation is prone to leaking along the base of the aquifer. However, the Burkeville
confining interval provides isolation between Jasper and Evangeline aquifers which helps protect the
shallower Evangeline and Chicot Aquifers (Bruun, B., et al., 2016).

The schematic cross-section provided in Figure 22 runs south of the O'Neal No. 4, illustrating the
structure and stratigraphy of the aquifer system. The thickness of individual sedimentary units
within the Cenozoic section tends to thicken towards the Gulf of Mexico due to the presence of
growth faults that allow additional loading of unconsolidated sediment. The total net sand thickness
of the aquifer system ranges between 700 feet of sand in the south, to over 1,300 in the north, with
the saturated freshwater thickness averaging 1,000 feet.

Water quality of the Aquifer System varies with depth and locality but water quality generally
improves towards the central to northeastern portions of the aquifer where TDS values are less than
500 milligrams per liter ("mg/L"). The salinity of the Gulf Coast Aquifer increases to the south where
TDS ranges between 1,000 to over 10,000 mg/L. The Texas Water Development Board's Texas
Aquifers Study (2016) suggests that areas associated with higher salinities are possibly associated
with saltwater intrusion likely "resulting from groundwater pumping or to brine migration in
response to oil field operations and natural flows from salt domes intruding into the aquifer" (Bruun,
B., et al., 2016).

Page 30 of 77

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According to the Total Dissolved Solids (TDS) map of the Gulf Coast Aquifer (Figure 23), the total
dissolved solids in northern Bee County range between 500-3,000 mg/L near the O'Neal No. 4,
categorizing the aquifer as fresh to slightly saline.

The TRRC's Groundwater Advisory Unit ("GAU") identified the Base of Useable Quality water
("BUQW") at a depth of 250' and the Base of Underground Sources of Drinking Water ("USDW") at
a depth of 950 feet at the location of the O'Neal No, 4 location. Approximately 14,924 feet is
separating the base of the USDW and the injection interval, A copy of the GAU's Groundwater
Protection Determination letter issued by the TRRC as part of the Class II permitting process for the
O'Neal No. 4 is provided in Exhibit A-l. The base of the deepest aquifer is separated from the
injection interval by more than 14,924 feet of rock, including 4,200 feet of Midway Shale. Though
unlikely for reasons outlined in the confinement and potential leaks sections, if migration of injected
fluid did occur above the Pearsall formation, thousands of feet of tight sandstone, limestone, shale,
and anhydrite beds occur between the injection interval and the lowest water-bearing aquifer.

Figure 20 - Extent of the Gulf Coast Aquifer. The red star represents the approximate location of the
O'Neal No. 4 (modified from Bruun, B., et al., 2016)

Page 31 of 77

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Figure 21 - Stratigraphic Column of the Gulf Coast Aquifer (Chowdhury, A.H. and Turco, M.J., 2006)

-1,000-1
-2,000

a>

Cl) -3,000
c

•2 -4,000-
co
>

0)

UJ -5,GOO-

'S,000-
-7,000

Figure 22 - Cross-Section S-S' across the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun, B., et al., 2016)

S1

25 Miles

Chicot Aquifer

Evangeline Aquifer

Page 32 of 77

-------
Freestone'

,nderson

Brown

Hamilton

[acogdoche

McLennan Yimestoni

Coryell

Houston

Angelina

tobertson1

Madison'

Milam

Williamson

Burleson

Hardin

Travis

Montgomery

'ashingto

Bastrop

Jefferson

Austin

Kendall

Harris

F^y6tte

.Caldweli

lambefe.

Comal

Colorado

Guadalupi

Lavaca

Wharton

Brazoria

Wilson

Dewitt

Jackson j Matagorda

Barnes

Victoria

Goliad

McMull^n

Duval Jiln Welf NueceV\

Kleberg

Brooks

Kenedy

Hidalgo

Cwieron >.

San Saba>amPasas

? Burnet

Mason Llano ?

Gillespie

Blancc

Bandera

Bexar

Medina

La Salle

Webb -

Gulf of Mexico

Mexico

120

¦ Miles

Total dissolved solids (milligrams per liter)

| t-1,000 Fresh	1,000-3,000 Slighty saline	3.000-10,000 Moderately saline	10,000-35,000 Very saline

^ State boundary | | County boundary | j Aquifer boundary

Figure 23 - Total Dissolved Solids (TDS) in the Gulf Coast Aquifer. The red star represents the approximate
location of the O'Neal No. 4 (modified from Bruun, EL, et al., 2016)

Page 33 of 77

-------
2.6 References

Roberts-Ashby, T. L., Brennan, S. T., Buursink, M. L., Covault, J. A., Craddock, W. H., II, Drake R. M.,
Merrill, M.D., Slucher, E.R, Warwick, P.D., Blondes, M.S., Gosai, M.A., Freeman, P.A., Cahan,
S.M., DeVera, C.A., and Lohr, C.D, 2012. Geologic framework for the national assessment of
carbon dioxide storage resources: U.S. Gulf Coast. USGS.

Bebout, D. G., Budd, D. A., and Schatzinger, R. A., 1981. Depositional and Diagenetic History of the
Sligo and Hosston Formations (Lower Cretaceous) in South Texas: The University of Texas at
Austin, Bureau of Economic Geology, Report of Investigations No. 109.

Bruun, B., Anaya, R., Boghici, R., French, L.N, Jones, I., Petrossian, R., Ridgeway, C., Shi, J., Wade, S.,
Weinberg, A., Ballew, N., Goswami, R., Olden, M., 2016. Texas Aquifers Study: Chapter 6,
Gulf Coast Aquifers.

Blondes, M.S., Gans, K.D., Engle, M.A., Kharaka, Y.K., Reidy, M.E., Saraswathula, V., Thordsen, J.J.,
Rowan, E.L., and Morrissey, E.A., 2018. U.S. Geological Survey National Produced Waters
Geochemical Database (ver. 2.3, January 2018): U.S. Geological Survey data release,
https://doi.org/10.5066/F7J964W8.

Chowdhury, A.H. and Turco, M.J., 2006. Geology of the Gulf Coast Aquifer, Texas. In: Mace, R.E., et
al., Eds., Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report.

Dennen, K.O. and Hackley, P.C., 2012. Definition of Greater Gulf Basin Lower Cretaceous and Upper
Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico
basin onshore and state waters: https://pubs.usgs.gov/publication/70176229

Galloway, W. E., 2008. Sedimentary Basins of the World, Chapter 15: Depositional Evolution of the
Gulf of Mexico Sedimentary Basin. 505-549.

Hull, D.C., 2011. Stratigraphic Architecture, Depositional Systems, and Reservoir Characteristics of
the Pearsall Shale-Gas System, Lower Cretaceous, South Texas: Thesis for M.S. of Science in
Geology, University of Texas, Austin.

Kirkland, B L, Lighty, R G, Rezak, R, and Tieh, TT, 1987. Lower Cretaceous barrier reef and outer shelf
facies, Sligo Formation, south Texas, United States.

Swanson, S.M., Enomoto, C.B., Dennen, K.O., Valentine, B.J., and Cahan, S.M., 2017. Geologic
assessment of undiscovered oil and gas resources—Lower Cretaceous Albian to Upper
Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups, United
States Gulf of Mexico Coastal Plain and State Waters: U.S. Geological Survey Open-File
Report 2016-1199, 69 p., https://doi.org/10.3133/ofr20161199.

Talbert, S.J. and Atchley, S.J., 2000. Sequence Stratigraphy of the Lower Cretaceous (Albian)
Fredericksburg Group, Central and North Texas: Department of Geology, Baylor University,
Waco, Texas 76798.

Page 34 of 77

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Yurewicz, D.A., et a I, 1993, D.A., Marler, T.B., Meyerholtz, K.A., Siroky, F.X., 1993. Early Cretaceous
Carbonate Platform, North Rim of the Gulf of Mexico, Mississippi, and Louisiana.

2.7 Description of the Injection Process
2.7.1 Current Operations

The Plant and the O'Neal No. 4 are existing operating assets. The O'Neal No. 4 will be recompleted
for acid gas injection service under the Class II permit process. Under the Class II application, the
maximum injection rate is 28 MT/yr (1.5 MMscf/d). The TAG is 98.2% CO2, which equates to 27.5
MT/yr of CO2 each year. The current composition of the TAG stream is:

Table 4 - Gas Composition

Component

Mol Percent

Carbon Dioxide

98.2%

Hydrocarbons

1.03%

Hydrogen Sulfide

0.4%

Nitrogen

0.37%

The Plant is designed to treat, dehydrate, and compress the natural gas produced from the
surrounding acreage in Bee County. The Plant uses an amine unit to remove the CO2 and other
constituents from the gas stream. The TAG stream is then dehydrated, compressed, and routed
directly to the O'Neal No. 4 for injection. The remaining gas stream is processed to separate the
natural gas liquids, which are then sold along with the natural gas. The Plant is monitored 24 hours
per day, 7 days per week.

2.8 Reservoir Characterization Modeling

The modeling software used to evaluate this project was Computer Modelling Group's GEM 2023.2
(GEM) simulator. Computer Modelling Group (CMG) has created one of the most comprehensive
reservoir simulation software packages for conventional, unconventional, and secondary recovery.

advanced

computational methods to evaluate compositional, chemical, and geochemical processes and
characteristics. This results in the creation of exceedingly precise and dependable simulation
models for carbon injection and storage. The GEM model holds recognition from the EPA for its
application in the delineation modeling aspect of the area of review, as outlined in the Class VI Well
Area of Review Evaluation and Corrective Action Guidance document.

The Sligo formation serves as the target formation for the O'Neal No. 4 (API No. 42-025-32658). The
Petra software package was utilized to construct the geological model for this target formation.
Within Petra, formation top contours were generated and subsequently brought into GEM to
outline the geological structure.

Page 35 of 77

-------
Porosity and permeability estimates were determined using the porosity log from the O'Neal No. 4.
A petrophysical analysis was then conducted to establish a correlation between porosity values and
permeability, employing the Coates equation. Both the porosity and permeability estimates from
the O'Neal No. 4 were incorporated into the model, with the assumption that they exhibit lateral
homogeneity throughout the reservoir.

The reservoir is assumed to be at hydrostatic equilibrium. Given the geological formation in which
this well is located and its previous history as a gas producer, the model is assumed to be primarily
saturated with gas. More precisely, the reservoir is assumed to be 80% gas saturated and 20% brine
saturated, as deduced from the well log data. The modeled injection interval exhibits an average
permeability of 0.23 mD and an average porosity of 5%. All layers within the model have been
perforated. An infinite-acting reservoir has been created to simulate the boundary conditions.

The gas injectate is composed predominantly of CO2 as shown in Table 5. The modeled composition
takes into consideration the carbon dioxide and other constituents of the total stream. As the Plant
has been in operation for many years, the gas composition for the proposed injection period is
expected to remain constant.

Table 5 - Modeled Injectate Composition

Component

Expected Composition
(mol %)

Modeled
Composition (mol %)

Carbon Dioxide (CO2)

98.2

98.2

Hydrocarbons

1.03%

Hydrocarbons

Hydrogen Sulfide

0.4%

Hydrogen Sulfide

Nitrogen

0.37%

Nitrogen

Core data from the literature review was used to determine residual gas saturation (Keelan and
Pugh, 1975) and relative permeability curves between carbon dioxide and the connate brine within
the Sligo carbonates (Bennion and Bachu, 2010). The Corey-Brooks method was used to create
relative permeability curves. The key inputs used in the model include a Corey exponent for brine
of 1.8, a Corey exponent for gas of 2.5, gas permeability at irreducible brine saturation of 50%,
irreducible water saturation of 20%, and a maximum residual gas saturation of 35%. The relative
permeability curves used for the GEM model are shown in Figure 24.

Page 36 of 77

-------
Two-Phase (C02/Brine) Relative Permeability Curves
O'Neal No. 4 Sligo Formation

Figure 24 - Two-Phase Relative Permeability Curves Used in the GEM Model

The grid contains 81 blocks in the x-direction (east-west) and 81 blocks in the y-direction (north-
south), resulting in a total of 6,561 grid blocks per layer. Each grid block spans dimensions of 250 ft
x 250 ft. This configuration yields a grid size measuring 20,250 ft x 20,250 ft, equating to just under
15 square miles in area. The grid cells in the vicinity of the O'Neal No. 4, within a radius of 0.5 miles,
have been refined to dimensions of 83.333 ft x 83.333 ft in all layers. This refinement is employed
to ensure a more accurate representation of the plume and pressure effects near the wellbore.

In the model, each layer is characterized by homogeneous permeability and porosity values. These
values are derived from the porosity log of the O'Neal No. 4. The model encompasses a total of 61
layers, each featuring a thickness of approximately 3 ft per layer. As previously mentioned, the
model is perforated in each layer, with the top layer being the top of the injection interval and the
bottom layer being the lowest portion of the injection interval. The summarized property values for
each of these packages are displayed in Table 6.

Page 37 of 77

-------
Table 6 - GEM Model Layer Package Properties

Layer #

Top
(TVD ft)

Thickness

Perm.
(mD)

Porosity
(%)

1

15,874

3

0.004

3.75%

2

15,877

3

0.002

2.98%

3

15,880

3

0.001

1.62%

4

15,883

3

0.001

1.78%

5

15,886

3

0.002

2.32%

6

15,889

3

0.001

1.96%

7

15,892

3

0.002

3.10%

8

15,895

3

0.002

2.99%

9

15,898

3

0.003

3.52%

10

15,901

3

0.006

4.00%

11

15,904

3

0.005

3.93%

12

15,907

3

0.001

2.15%

13

15,910

3

0.001

1.99%

14

15,913

3

0.002

2.97%

15

15,916

3

0.001

2.22%

16

15,919

3

0.002

2.88%

17

15,922

3

0.001

2.38%

18

15,925

3

0.093

6.68%

19

15,928

3

0.005

2.62%

20

15,931

3

0.002

2.58%

21

15,934

3

0.003

3.07%

22

15,937

3

0.006

3.62%

23

15,940

3

0.002

2.68%

24

15,943

3

0.001

1.08%

25

15,946

3

0.002

1.87%

26

15,949

3

0.025

4.70%

27

15,952

3

0.024

4.37%

28

15,955

3

0.001

1.97%

29

15,958

3

0.003

2.27%

30

15,961

3

0.007

3.09%

31

15,964

3

0.110

6.75%

32

15,967

3

0.037

5.62%

33

15,970

3

0.011

4.41%

34

15,973

3

0.022

4.59%

35

15,976

3

0.297

7.88%

36

15,979

3

0.440

9.21%

37

15,982

3

0.060

5.90%

38

15,985

3

0.001

2.22%

Page 38 of 77

-------
39

15,988

3

0.001

2.21%

40

15,991

3

0.001

1.12%

41

15,994

3

0.003

2.05%

42

15,997

3

0.014

4.56%

43

16,000

3

0.007

4.15%

44

16,003

3

0.033

5.95%

45

16,006

3

1.233

10.25%

46

16,009

3

1.476

12.04%

47

16,012

3

0.566

10.08%

48

16,015

3

1.679

12.18%

49

16,018

3

2.194

13.08%

50

16,021

3

1.235

12.02%

51

16,024

3

0.788

11.22%

52

16,027

3

0.944

10.48%

53

16,030

3

0.424

9.05%

54

16,033

3

0.378

8.85%

55

16,036

3

0.378

8.81%

56

16,039

3

0.378

8.84%

57

16,042

3

0.736

9.91%

58

16,045

3

0.232

7.94%

59

16,048

3

0.238

7.97%

60

16,051

3

0.012

3.01%

61

16,054

3

0.038

4.30%

2.8.1 Simulation Modeling

The primary objectives of the model simulation were as follows:

1.	Estimate the maximum areal extent and density drift of the injectate plume after injection.

2.	Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone.

3.	Assess the likelihood of the injectate plume migrating into potential leak pathways.

The reservoir is assumed to have an irreducible brine saturation of 20%. The salinity of the brine
within the formation is estimated to be 150,000 ppm (U.S. Geological Survey National Produced
Waters Geochemical Database, ver. 2.3), typical for the region and formation. The injectate stream
is primarily composed of CO2 and H2S as stated previously. Core data from the literature was used
to help generate relative permeability curves. From the literature review, also as previously
discussed, cores that most closely represent the carbonate rock formation of the Sligo seen in this
region were identified, and the Corey-Brooks equations were used to develop the curves (Bennion
and Bachu, 2010). A low, conservative residual gas saturation based on the cores from the literature
review was then used to estimate the size of the plume (Keelan and Pugh, 1975).

Page 39 of 77

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The model is initialized with a reference pressure of 10,995 psig at a subsea depth of 15,740 ft. This,
when a Kelly Bushing "KB" elevation of 334 ft is considered, correlates to a gradient of 0.684 psi/ft.
This pressure gradient was determined from production data of the O'Neal No. 4. An initial reservoir
pressure of 0.76 psi/ft was calculated before initial production. However, in 1997 after producing
approximately 0.5 Bcf of gas, the well was shut-in. The last bottomhole pressure reading was
calculated to be 0.480 psi/ft. This assumes the reservoir repressurizes after production ceases, but
not fully back to in-situ conditions. Therefore, a 10% safety factor was given to the initial reservoir
pressure gradient of 0.76 psi/ft and a gradient of 0.684 psi/ft was implemented into the model as a
conservative estimate. A skin factor of -2 was applied to the well to simulate the stimulation of the
O'Neal No. 4 for gas production from the Sligo formation, which is based on the acid fracture report,
provided in Appendix A-3.

The fracture gradient of the injection zone was estimated to be 0.954 psi/ft, which was determined
from the acid fracture report. A 10% safety factor was then applied to this number, putting the
maximum bottomhole pressure allowed in the model at 0.86 psi/ft, which is equivalent to 13,652
psig at the top of the Sligo injection interval.

The model, which begins in January 2025, runs for a total of 22 years, comprising of 12 years of
active injection, and is then succeeded by 10 years of density drift. Throughout the entire 12-year
injection period, an injection rate of 1.5 MMscf/D is used to model the maximum available rate,
yielding the largest estimate of the plume size. After the 12-year injection period, when the O'Neal
No. 4 ceases injection, the density drift of the plume continues until the plume stabilizes 10 years
later. The maximum plume extent during the 12-year injection period is shown in Figure 25. The
final extent after 10 years of density drift after injection ceases is shown in Figure 26.

Page 40 of 77

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C02 Saturation at End of Injection

283750 -

282500 -					0 60

281250 -

280000 -

0.80-=

-0.70

-0.50

-0,0

-0.30

-0.20

278750 -	H-0.10

' ' ' I	I	I	I	I	I

2316000	2318000	2320(300	2322000	2324000	2326000

Figure 25 - Areal View of Saturation Plume at Shut-in (End of Injection)

Page 41 of 77

-------
C07 Saturation at End of Simulation

1	i	i

0.80n

283750

282500 -

281250 -

280000 -

L

-0.70

-0.60

-0.50

....

-0.30

-0.20

278750 -

-0.10

I	I	I

2316000	2318000	2320000	2322000

T
2324000

T
2326000

Figure 26 - Areal View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Page 42 of 77

-------
The cross-sectional view of the O'Neal No. 4 shows the extent of the plume from a side-view angle,
cutting through the formation at the wellbore. Figure 27 shows the maximum plume extent during
the 12-year injection period. During this time, gas from the injection well is injected into the
permeable layers of the formation and predominantly travels laterally. Figure 28 shows the final
extent of the plume after 10 years of migration. Then, the effects of residual gas saturation and
migration due to density drift are clearly shown. At least 35% of injected gas that travels into each
grid cell is trapped, as the gas travels mostly vertically—as it is less dense than the formation brine—
until an impermeable layer is reached. Both figures are shown in an east-to-west view.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 43 of 77

-------
C02 Saturation at End of Injection

15500 -

15563 -

15625 -

15688 -

15750

15813



0.70

-0.60

-0.50

U.40
1-0.30

-0.20

-0.10

2319000

2321000

2323000

Figure 27 - East-West Cross-Sectional View of Gas Saturation Plume at Shut-in (End of Injection)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 44 of 77

-------
C02 Saturation at End of Simulation

15500 -

15563 -

15625

15688 -

15750

0.80-=

-0.70

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—'—T
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Figure 28 -East-West Cross-Sectional View of Gas Saturation Plume 10 Years After Shut-in (End of Simulation)

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 45 of 77

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Figure 29 shows the surface injection rate, bottom hole pressures, and surface pressures over the
injection period—and the period of density drift after injection ceases. The bottom hole pressure
increases the most as the injection rate ends, reaching a maximum pressure of 13,337 psig, at the
end of injection. This buildup of 2,362 psig keeps the bottom hole pressure below the fracture
pressure of 13,652 psig. The maximum surface pressure associated with the maximum bottom hole
pressure reached is 6,095 psig, well below the maximum allowable 7,937 psig per the TRRC UIC
permit application for this well. Bottomhole and wellhead pressures are provided in Table 7.

2,000,000
1,750,000

_ 1,500,000
¦a

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4-»

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o

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4,000
2,000
0

• Gas Rate (scf/d)

• BHP (psig)

WHP(psig) — — —BHP Constraint (psig) — — — WHP Constraint (psig)

Figure 29 - Well Injection Rate and Bottomhole and Surface Pressures Over Time

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 46 of 77

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Table 7 - Bottomhole and Wellhead Pressures from the Start of Injection

Time from Start of Injection
(years)

BHP (psig)

WHP (psig)

0

10,975

-

10

13,311

6,073

12 (End of Inj.)

13,337

6,095

20

11,029

-

22 (End of Model)

11,013

-

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 47 of 77

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SECTION 3 - DELINEATION OF MONITORING AREA

This section discusses the delineation of both the maximum monitoring area (MMA) and active
monitoring area (AMA) as described in

3.1 Maximum Monitoring Area

The MMA is defined as equal to or greater than the area expected to contain the free-phase CO2
plume until the plume has stabilized, plusan all-around bufferzone of at least half a mile. Numerical
simulation was used to predict the size and drift of the plume. With CMG's GEM software package,
reservoir modeling was used to determine the areal extent and density drift of the plume. The
model considers the following:

•	Offset well logs to estimate geologic properties

•	Petrophysical analysis to calculate the heterogeneity of the rock

•	Geological interpretations to determine faulting and geologic structure

•	Offset injection history to predict the density drift of the plume adequately

Ozona's expected gas composition was used in the model. The injectate is estimated at a molar
composition of 98.2% CO2 and 1.8% of other constituents. The StarTex Plant has been in stable
operations for many years. Ozona believes the gas analysis provided in Table 1 is an accurate
representation of the injectate. In the future, if the actual gas analysis varies materially from the
injectate composition herein, an update to this MRV plan will be submitted to the GHGRP. As
discussed in Section 2, the gas will be injected into the Sligo formation. The geomodel was created
based on the rock properties of the Sligo.

The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of
3% gas saturation was used to determine the boundary of the plume. When injection ceases in Year
12, the area expanse of the plume will be approximately 270 acres. The maximum distance between
the wellbore and the edge of the plume is approximately 0.42 miles to the west. After 10 additional
years of density drift, the areal extent of the plume is 303 acres with a maximum distance to the
edge of the plume of approximately 0.45 miles to the west. Since the plume shape is relatively
circular, the maximum distance from the injection well after density drift was used to define the circular
boundary of the MMA. The AMA and the MMA have similar areas of influence, with the AMA being only
marginally smaller than the MMA. Therefore, Ozona will set the AMA equal to the MMA as the basis for
the area extent of the monitoring program.

This is shown in Figure 30 with the plume boundary at the end of injection, the stabilized plume
boundary, and the MMA. The MMA boundary represents the stabilized plume boundary after 10
years of density drift plus an all-around buffer zone of one half mile.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 48 of 77

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Figure 30 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 49 of 77

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3.2 Active Monitoring Area

The AMA was initially set equal to the expected total injection period of 12-years. The AMA was
analyzed by superimposing the area based on a one-half mile buffer around the anticipated plume
location after 12 years of injection (2037), with the area of the projected free-phase CO2 plume at
five additional years (2042). In this case, as shown in Figure 31 the plume boundary in 2042 is within
the plume in 2037 plus the one-half mile buffer. Since the Active Monitoring Area boundary is only
slightly smaller than the Maximum Monitoring Area boundary, Ozona will define the AMA to be equal
to the MMA. By 2037, Ozona will submit a revised MRV plan to provide an updated AMA and MMA.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 50 of 77

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CfrMMthrl* |

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Figure 31 - Active Monitoring Area

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 51 of 77

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SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE

This section identifies and discusses the potential pathways within the MMA for CO2 to reach the
surface, and is summarized in Table 8. Also included are the likelihood, magnitude, and timing of
such potential leakage. The potential leakage pathways are:

•	Surface equipment

•	Existing wells within the MMA

•	Faults and fractures

•	Upper confining layer

•	Natural or induced seismicity

Table 8 - Potential Leakage Pathway Risk Assessment

Potential Leakage Pathway

Likelihood

Magnitude

Timing

Surface Equipment

Possible during injection
operations.

Low. Automated systems
will detect leaks and
execute shut-down
procedures.

During active injection
period. Thereafterthe
well will be plugged.

Existing wells within the MMA

Unlikely. The lateral
continuity of the UCZ is
recognized as a very
competent seal.

Low. Any vertical migration
from the Injection Zone
would return the C02to
the production zone.

During active injection
and Post Injection Site
Care periods.

Faults and fractures

Possible. The lateral
continuity of UCZ is
recognized as a very
competent seal.

Low. Vertical migration
from the Injection Zone
would return the C02 to
the production zone.

During active injection
and Post Injection Site
Care periods.

Upperconfining layer

Unlikely. The lateral
continuity of the UCZ is
recognized as a very
competent seal.

Low. Vertical migration
from the Injection Zone
would return the C02 to
the production zone.

During active injection
and Post Injection Site
Care periods.

Natural or induced seismicity

Possible. The lateral
continuity of the UCZ is
recognized as a very
competent seal.

Low. Vertical migration
from the Injection Zone
would return the C02 to
the production zone.

During active injection
and Post Injection Site
Care periods.

4.1 Leakage from Surface Equipment

The Plant and O'Neal No. 4 are designed for separating, transporting, and injecting TAG primarily
consisting of CO2 in a manner to ensure safety to the public, the employees, and the environment.
The mechanical aspects of this are noted in Table 9 and Figure 32. The facilities have been designed
to minimize leakage and failure points, following applicable National Association of Corrosion
Engineers (NACE) and American Petroleum Institute (API) applicable standards and practices. As the

Subpart RR MRV Plan - O'Neal Gas Unit No. 4
Page 52 of 77

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TAG stream contains H2S, monitors installed for H2S detection will also indicate the presence of CO2.
These monitors will be installed at key locations around the Plant and the O'Neal No. 4 location.
These devices will be continuously monitored by the Supervisory Control and Data Acquisition
(SCADA) system and will alarm at set points determined by the Plant HS&E Director, consistent with
Occupational Safety and Health Administration (OSHA) requirements. The Plant will set the
detection and alarm states for personnel at 10 ppm and at 40 ppm for initiating Emergency
Shutdown. Key monitoring points and parameters are provided in Table 9.

The facilities will incorporate important safety equipment to ensure reliable and safe operations. In
addition to the H2S monitors, emergency shutdown (ESD) valves, with high- and low-pressure
shutoff settings to isolate the Plant, the O'Neal No. 4, and other components, StarTex has a flare
stack to safely handle the TAG when a depressuring event occurs. These facilities will be constructed
in the coming months. The exact location of this equipment is not yet known, but it will be installed
in accordance with applicable engineering and safety standards.

Table 9 - Summary of TAG Detectors and Equipment

Device

Location

Set Point

H2S Detectors (1 - 4)

O'Neal No. 4 wellsite

10 ppm High Alarm

40 ppm Emergency Shutdown

H2S Detectors (5 - 8)

In-Plant Detectors

10 ppm High Alarm

40 ppm Emergency Shutdown

Flare Stack

Plant Site Perimeter

N/A

AGI Flowmeter

In-Plant (downstream of the
Amine Unit)

Calibrated per API specifications

Emergency Shutdown

In-Plant Detectors

40 ppm Emergency Shutdown

Emergency Shutdown

O'Neal No. 4 wellsite

40 ppm Emergency Shutdown

Subpart RR MRV Plan - O'Neal Gas Unit No. 4
Page 53 of 77

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With the continuous air monitoring at the Plant and the well site, a release of CO2 would be quickly
identified, and the safety systems and protocols would effectuate an orderly shutdown to ensure
safety and minimize the release volume. The CO2 injected into the O'Neal No. 4 is from the amine
unit at the Pawnee Gas Plant. If any leakage were to be detected, the volume of CO2 released would
be quantified based on the operating conditions at the time of release, as stated in Section 7 in
accordance with 40 CFR §98.448(a)(5). Ozona concludes that the leakage of CO2 through the surface
equipment is unlikely.

4.2 Leakage Through Existing Wells Within the MMA

The O'Neal No. 4 is engineered to prevent migration from the injection interval to the surface
through a special casing and cementing design as depicted in the schematic provided in Figure 32.
Mechanical integrity tests (MITs), required under Statewide Rule (SWR) §3.46 [40 CFR §146.23
(b)(3)], will take place every 5 years to verify that the well and wellhead can contain the appropriate
operating pressures. If the MIT were to indicate a leak, the well would be isolated and the leak
mitigated to prevent leakage of the injectate to the atmosphere.

A map of all oil and gas wells within the MMA is shown in Figure 33. Figure 34 is a map of all the oil
and gas wells that penetrate the MMA's gross injection zone. Only one well penetrated the MMA's
gross injection zone. This well was non-productive and has been plugged and abandoned in
accordance with TRRC requirements. A summary table of all oil and gas wells within the MMA is
provided in Appendix B-l.

This table in Appendix B-l provides the total depth (TD) of all wells within the MMA. The wells that
are shallower and do not penetrate the injection zone are separated by the Pearsall Formation with
a gross thickness of 535'. The Pine Island Shale comprises approximately 130 feet of this interval as
discussed in Section 2.2.2, and provides a competent regional seal making vertical migration of fluids
above the injection zone unlikely.

The shallower producing offset wells within the MMA will also serve as above zone monitoring wells.
As gas analysis is routinely performed for monthly settlement statements from these wells, Ozona
will be notified if a material difference in the quantity of CO2 produced occurs, indicating a potential
migration of injectate from the Sligo formation. Ozona would investigate and develop a mitigation
plan, which may include reducing the injection rate or shutting the well in. Based on the
investigation, the appropriate equation in Section 7 would be used to make any adjustments to the
reported volumes.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4
Page 55 of 77

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 56 of 77

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 57 of 77

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4.2.1 Future Drilling

Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations have proven to date to be nonproductive in this area and therefore Ozona does not see
this as a risk. This is supported by a review of the TRRC Rule 13 (entitled Casing, Cementing, Drilling,
Well Control, and Completion Requirements), 16 TAC §3.13. The Sligo is not among the formations
listed for which operators in Bee County and District 2 (where the O'Neal No. 4 is located) are
required to comply with TRCC Rule 13 and therefore the TRRC does not believe there are productive
horizons below the Sligo. The O'Neal No. 4 drilling permit is provided in Appendix A-2.

4.2.2 Groundwater Wells

The results of a groundwater well search found 5 wells within the MMA, as identified by the Texas
Water Development Board as shown in Figure 35, and in tabular form in Appendix B-2.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4
Page 58 of 77

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4	Page 59 of 77

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The surface, intermediate, and production casings of the O'Neal No. 4, as shown in Figure 32, are
designed to protect the shallow freshwater aquifers, consistent with applicable TRRC regulations,
and the GAU letter issued for this location is provided in Appendix A-l. The wellbore casings and
compatible cements prevent CO2 leakage to the surface along the borehole. Ozona concludes that
leakage of the sequestered CO2 to the groundwater wells is unlikely.

4.3	Leakage Through Faults and Fractures

Detailed mapping of open hole logs surrounding the O'Neal No. 4 did not identify any faulting within
the Pearsall or Sligo section. However, there is a general lack of deep penetrators within the area
which limits the amount of openhole coverage available.

The majority of the published literature suggests faulting near the project area is restricted to the
shallower, overlying Cenozoic section, as seen in Figure 9, with shallow faults dying out before
reaching the Pearsall formation. One source interpreted the potential for faulting to the south
(Swanson S.M., et al., 2016). The potential fault is depicted in Figure 8 relative to the location of the
O'Neal No. 4. According to the map, the interpreted fault lies approximately 4.25 miles south-
southeast of the well and approximately 3.9 miles south-southeast of the stabilized plume extent in
the year 2047. In the unlikely scenario in which the injection plume or pressure front reaches the
potential fault, and the potential fault was to act as a transmissive pathway, the upper confining
Pearsall shale contains sufficient thickness and petrophysical properties required to confine and
protect injectates from leaking outside of the permitted injection zone.

Please see Section 2.1.2 discussing Regional Structure and Faulting and Section 2.3 covering Local
Structure for additional material relevant to this topic.

4.4	Leakage Through the Confining Layer

The Sligo injection zone has competent sealing intervals present above and below the targeted
carbonate sequence of the Sligo section. The overlying Pine Island shale member of the Pearsall
formation is approximately 130 feet thick at the O'Neal No. 4. Above this confining unit, the Cow
Creek limestone, Cow Creek shale, and Bexar shale members of the Pearsall formation will act as
additional confinement between the injection interval and the USDW. The USDW lies well above
the sealing properties of the formations outlined above, making stratigraphic migration of fluids into
the USDW highly unlikely. The petrophysical properties of the Lower Sligo and Hosston formations
make these ideal for lower confinement. The low porosity and permeability of these underlying
formations minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injectate to the in-situ reservoir fluid makes migration below the lower confining layer
unlikely.

4.5	Leakage from Natural or Induced Seismicitv

The O'Neal No. 4 is located in an area of the Gulf of Mexico considered to be active from a seismic
perspective. Therefore, the Bureau of Economic Geology's TexNet (from 2017 to present) and
USGS's Advanced National Seismic System (from 1971 to present) databases were reviewed to

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 60 of 77

-------
identify any recorded seismic events within 25 km of the O'Neal No. 4.

The investigation identified a multitude of seismic events within the 25 km search radius, however,
the magnitude of most of the events was below 2.5. The nearest seismic event with a recorded
magnitude of 3.0 or greater was measured approximately 5.6 km northwest of the O'Neal No. 4 at
a depth of 5 km. The results of the investigation are plotted on the map provided in Figure 36
relative to the O'Neal No. 4 and 25 km search radius.

The Plant will have operating procedures and set points programmed into the control and SCADA
systems to ensure operating pressures are maintained within the injection and confining intervals
approved fracture gradients. Given the seismic activity in the area, Ozona will closely monitor
nearby TexNet station EF71 for activity and any corresponding irregularities in the operating
pressures of O'Neal No. 4.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 61 of 77

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Figure 36 - 25 km Seismicity Review

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

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Page 62 of 77

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SECTION 5 - MONITORING FOR LEAKAGE

This section discusses the strategy that Ozona will employ for detecting and quantifying surface
leakage of CO2 through the pathways identified in Section 4, to meet the requirements of 40 CFR
§98.448(a)(3). As the injectate stream contains both H2S and CO2, the H2S will be a proxy for CO2
leakage and therefore the monitoring systems in place to detect H2S will also indicate a release of
CO2. Table 10 summarizes the monitoring of the following potential leakage pathways to the
surface. Monitoring will occur during the planned 12-year injection period or cessation of injection
operations, plus a proposed 10-year post-injection period until the plume has stabilized.

•	Leakage from surface equipment

•	Leakage through existing and future wells within the MMA

•	Leakage through faults, fractures, or confining seals

•	Leakage through natural or induced seismicity

Table 10 - Summary of Leakage Monitoring Methods

Leakage Pathway

Monitoring Method

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Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 63 of 77

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5.1 Leakage from Surface Equipment

The Plant and the O'Neal No. 4 were designed to operate in a safe manner to minimize the risk of
an escape of CO2 and H2S. Leakage from surface equipment is unlikely and would quickly be
detected and addressed. The facility design minimizes leak points through the equipment used, and
key areas are constructed with materials that are NACE and API compliant. A baseline atmospheric
CO2 concentration will be established prior to commencing operation once facility construction has
been completed. Ambient H2S monitors will be located at the Plant and near the O'Neal No. 4 site
for local alarm and are connected to the SCADA system for continuous monitoring.

The Plant and O'Neal No. 4 are continuously monitored through automated control systems. These
monitoring points were discussed in Section 4.1. In addition, field personnel conduct routine visual
field inspections of gauges, and gas monitoring equipment. The effectiveness of the internal and
external corrosion control program is monitored through the periodic inspection of the corrosion
coupons and inspection of the cathodic protection system. These inspections and the automated
systems allow Ozona to detect and respond to any leakage situation quickly. The surface equipment
will be monitored for the injection and post-injection period. Should leakage be detected during
active injection operations, the volume of CO2 released will be calculated based on operating
conditions at the time of the event, per 40 CFR §98.448(a)(5).

Pressures, temperatures, and flow rates through the surface equipment are continuously monitored
during operations. If a release occurred from surface equipment, the amount of CO2 released would
be quantified based on the operating conditions, including pressure, flow rate, percentage of CO2 in
the injectate, size of the leak-point opening, and duration of the leak. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7.

5.2 Leakage Through Existing and Future Wells Within the MMA

Ozona continuously monitors and collects injection volumes, pressures, and temperatures through
their SCADA systems, for the O'Neal No. 4. This data is reviewed by qualified personnel and will
follow response and reporting procedures when data exceeds acceptable performance limits. A
change of injection or annular pressure would indicate the presence of a possible leak and be
thoroughly investigated. In addition, MITs performed every 5 years, as expected by the TRRC and
UIC, would also indicate the presence of a leak. Upon a negative MIT, the well would be isolated
and investigated to develop a leak mitigation plan.

As discussed previously, TRRC Rule 13 ensures that new wells in the field are constructed with
proper materials and practices to prevent migration from the injection interval.

In addition to the fixed monitors described previously, Ozona will also establish and operate an in-
field monitoring program to detect CO2 leakage within the AMA. This would include H2S monitoring
as a proxy for CO2 at the well site and annual soil gas samples taken near any identified wells that
penetrate the injection interval within the AMA. These samples will be analyzed by a qualified third
party. Prior to commencing operation, and through the post-injection monitoring period, Ozona
will have these monitoring systems in place.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 64 of 77

-------
Currently, there is only one well in the MMA identified that penetrates the injection interval. This
well was plugged and abandoned in 2007. The TRRC records are provided in Appendix A-4. Ozona
will take an annual soil gas sample from this area which will be analyzed by a third-party lab.
Additional monitoring will be added as the AMA is updated over time. In the unlikely event a leak
occurs, Ozona will quantify the leak volumes by the methodologies discussed in Section 7 and
present these results and related activities in the annual report.

Ozona will also utilize shallower producing gas wells as proxies for above zone monitoring wells.
Production data from these wells is analyzed for monthly production statements, and therefore
would be an early indicator of any possible subsurface issues. Should any material change from
historical trends in the CO2 concentration occur, Ozona would investigate and develop a corrective
action plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is
very low, as the producing reservoir provides an ideal containment given the Upper Confining Zone
of this reservoir has proven competent. In the unlikely event a leak occurs, Ozona would quantify
the leak perthe strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443
based on the actual circumstances, and include these results in the annual report.

5.2.1.1 Groundwater Quality Monitoring

Ozona will monitor the groundwater quality above the confining interval by sampling from
groundwater wells near the O'Neal No. 4 and analyzing the samples with a third-party laboratory
on an annual basis. In the case of the O'Neal No. 4, 5 existing groundwater wells have been
identified within the AMA (Figure 38). Initial groundwater quality tests will be performed to
establish a baseline prior to commencing operations.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 65 of 77

-------
w

V\

S

H
H
H

.7832309

jm%

4-

^O Ncal Gai Unit *4
28.602915, -98.001428

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H
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H
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. • BufVr from Worn# £aS*nt 0
Scjbtaabort)

• TW06 Groundv**«f Wrlb

O SOftOeWdb

Figure 37 - Groundwater Wells

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 66 of 77

-------
5.3 Leakage Through Faults. Fractures, or Confining Seals

Ozona will continuously monitorthe operations of the O'Neal No. 4 through the automated controls
and SCADA systems. Any deviation from normal operating volume and corresponding injection
pressure could indicate movement into a potential leak pathway, such as a fault or breakthrough of
the confining seal, and would trigger an alert due to a change in the injection pressure. Any such
alert would be reviewed by field personnel and appropriate action would be taken, including
shutting in the well, if necessary.

Ozona will also utilize shallower producing wells as proxies for above zone monitoring wells.
Production data is analyzed regularly for monthly production statements and therefore would be
an early indicator of any possible subsurface issues. Should any material change from historical
trends in the CO2 concentration occur, Ozona would investigate and develop a corrective action
plan. Should any CO2 migrate vertically from the Sligo, the magnitude risk of this event is very low,
as the producing reservoir provides an ideal containment given the Upper Confining Zone has
proven competent. In the unlikely event a leak occurs, Ozona would quantify the leak per the
strategies discussed in Section 7, or as may be applicable provided in 40 CFR §98.443 based on the
actual circumstances.

5.4 Leakage Through Natural or Induced Seismicitv

While the likelihood of a natural or induced seismicity event is low, Ozona plans to use the nearest
TexNet seismic monitoring station EF71 to monitor the area around the O'Neal No. 4. This station
is approximately three miles to the northwest, as shown in Figure 38. This is sufficient distance to
allow for accurate and detailed monitoring of the seismic activity in the area. Ozona will monitor
this station for any seismic activity, and if a seismic event of 3.0 magnitude or greater is detected,
Ozona will review the injection volumes and pressures of the O'Neal No. 4 to determine if any
significant changes have occurred that would indicate potential leakage. In the unlikely event a leak
occurs, Ozona will quantify the leak per the strategies discussed in Section 7, and take appropriate
operational actions based on the circumstances.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 67 of 77

-------
1 /
2TEf68	/

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28.602915, 98 001428

T

2T.EFS2

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0

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Figure 38 - Seismic Events and Monitoring Station

Subpart RR MRV Plan - O'Neal Gas Unit No, 4

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Page 68 of 77

-------
SECTION 6 - BASELINE DETERMINATIONS

This section identifies the strategies Ozona will undertake to establish the expected baselines for
monitoring CO2 surface leakage per 40 CFR §98.448(a)(4). Ozona will use the existing SCADA
monitoring systems to identify changes from the expected performance that may indicate leakage
of injectate and calculate a corresponding amount of CO2.

6.1	Visual Inspections

Regular inspections will be conducted by field personnel at the Plant and O'Neal No. 4 site. These
inspections will aid in identifying and addressing possible issues to minimize the risk of leakage. If
any issues are identified, such as vapor clouds or ice formations, corrective actions will be taken
prudently and safely to address such issues.

6.2	CO2/H2S Detection

In addition to the fixed monitors in the Plant and at the wellsite, Ozona will establish and perform
an annual in-field sampling program to monitor and detect any CO2 leakage within the AMA. This
will consist of soil gas sampling near any artificial penetrations of the injection zone and sampling of
water wells. These samples will be analyzed by a 3rd party lab and the results provided in the annual
report. Initial samples will be taken and analyzed before the commencement of operation and will
establish the baseline reference levels.

6.3	Operational Data

Upon starting injection operations, baseline measurements of injection volumes and pressures will
be recorded. Any significant deviations over time will be analyzed for indication of leakage of
injectate and the corresponding component of CO2.

6.4	Continuous Monitoring

The total mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly,
as the injection stream for this project is near the Occupational Safety and Health Administration
(OSHA) Permissible Exposure Limit (PEL) 8-hourTime Weighted Average (TWA) of 5,000 ppm. Direct
leak surveys present a hazard to personnel due to the presence of H2S in the gas stream. Continuous
monitoring systems will trigger alarms if there is a release. The mass of the CO2 released would be
calculated based on the operating conditions, including pressure, flow rate, percentage of CO2, size
of the leak-point opening, and duration. This method is consistent with 40 CFR §98.448(a)(5),
allowing the operator to calculate site-specific variables used in the mass balance equation.

In the case of a de-pressuring event, the acid gas stream will be sent to a flare stack to be safely
processed and will be reported under reporting requirements for the Plant. Any such events will be
accounted for in the sequestered reporting volumes consistent with Section 7.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 69 of 77

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6.5 Groundwater Monitoring

Initial samples will be taken from groundwater wells in the area of the O'Neal No. 4 upon approval
of the MRV plan, and before commencement of CO2 injection. These samples will be analyzed and
reports prepared by a third-party laboratory to establish baseline water quality parameters.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 70 of 77

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SECTION 7 - SITE-SPECIFIC CONSIDERATIONS FOR MASS

BALANCE EQUATION

This section identifies how Ozona will calculate the mass of CO2 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the CO2 emissions from equipment leaks and
vented emissions of CO2 between the injection flow meter and the injection well, per 40 CFR
§98.448(a)(5).

7.1	Mass of CO2 Received

Per 40 CFR §98.443, the mass of CO2 received must be calculated using the specified CO2 received
equations "unless you follow the procedures in 40 CFR §98.444(a)(4)." 40 CFR §98.444(a)(4) states
that "if the CO2 you receive is wholly injected and is not mixed with any other supply of CO2, you
may report the annual mass of CO2 injected that you determined following the requirements under
paragraph (b) of this section as the total annual mass of CO2 received instead of using Equation RR-
1 or RR-2 of this subpart to calculate CO2 received." The CO2 received for this injection well is wholly
injected and not mixed with any other supply; the annual mass of CO2 injected will equal the amount
received. Any future streams would be metered separately before being combined into the
calculated stream.

7.2	Mass of CO2 Injected

Per 40 CFR §98.444(b), since the flow rate of CO2 injected will be measured with a volumetric flow
meter, the total annual mass of CO2, in metric tons, will be calculated by multiplying the mass flow
by the CO2 concentration in the flow according to Equation RR-5:

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

QP,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p (standard
cubic meters per quarter)

D = Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682

Cco2,P,u = Quarterly CO2 concentration measurement in flow for flow meter u in quarter p
(volume percent CO2, expressed as a decimal fraction)

p = Quarter of the year

u = Flow meter

4

p=1

Where:

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 71 of 77

-------
7.3 Mass of CO2 Produced

The O'Neal No. 4 is not part of an enhanced oil recovery project; therefore, no CO2 will be produced.
7.4 Mass of CO2 Emitted by Surface Leakage

The mass of CO2 emitted by surface leakage and equipment leaks will not be measured directly due
to the H2S concentration in the injection stream. Direct leak surveys are dangerous and present a
hazard to personnel. Because no venting is expected to occur, the calculations would be based on
the unusual event that a blowdown is required and those emissions would be sent to a flare stack
and reported as a part of the required GHG reporting for the Plant. Any leakage would be detected
and managed as an upset event. Continuous monitoring systems should trigger an alarm upon a
release of H2S and CO2. The mass of the CO2 released would be calculated for the operating
conditions, including pressure, flow rate, size of the leak-point opening, and duration of the leak.
This method is consistent with 40 CFR §98.448(a)(5), allowing the operator to calculate site-specific
variables used in the mass balance equation.

In the unlikely event that CO2 was released because of surface leakage, the mass emitted would be
calculated for each surface pathway according to methods outlined in the plan and totaled using
Equation RR-10 as follows:

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

Calculation methods using equations from Subpart W will be used to calculate CO2 emissions due to
any surface leakage between the flow meter used to measure injection quantity and the injection
wellhead.

As discussed previously, the potential for pathways for all previously mentioned forms of leakage is
unlikely. Given the possibility of uncertainty around the cause of a leakage pathway that is
mentioned above, Ozona believes the most appropriate method to quantify the mass of CO2
released will be determined on a case-by-case basis. Any mass of CO2 detected leaking to the
surface will be quantified by using industry proven engineering methods including, but not limited
to, engineering analysis on surface and subsurface measurement data, dynamic reservoir modeling,
and history-matching of the sequestering reservoir performance, among others. In the unlikely

X

x=l

Where:

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 72 of 77

-------
event that a leak occurs, it will be addressed, quantified, and documented within the appropriate
timeline. Any records of leakage events will be kept and stored as provided in Section 10.

7.5 Mass of CO2 Sequestered

The mass of CO2 sequestered in subsurface geologic formations will be calculated based on Equation
RR-12. Data collection for calculating the amount of CO2 sequestered in the O'Neal No. 4 will begin
once the subsurface recompletion work, and the surface facilities construction has been completed,
and subject to approval of the MRV plan. The calculation of sequestered volumes utilizes the
following equation as the O'Neal No. 4 will not actively produce oil, natural gas, or any other fluids:

C02 — C02i — C02e ~ C02fi

Where:

CO2 = Total annual CO2 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year

CO21 = Total annual CO2 mass injected (metric tons) in the well covered by this source
category in the reporting year

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

CO 2fi - Total annual CO2 mass emitted (metric tons) from equipment leaks and vented
emissions of CO2 from equipment located on the surface, between the flow meter used to
measure injection quantity and the injection wellhead

CO2F1 will be calculated in accordance with Subpart W for reporting of GHGs. Because no venting is
expected to occur, the calculations would be based on the unusual event that a system blowdown
event occurs. Those emissions would be sent to a flare stack and reported as part of the GHG
reporting for the Plant.

• Calculation methodsfrom Subpart W will be used to calculate CO2 emissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 73 of 77

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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN

The O'Neal Gas Unit No. 4 is an existing natural gas well that will be recompleted as a Class II well
with corrosion resistant materials. Ozona is submitting this MRV application to the GHGRP to
comply with the requirements of Subpart RR. The MRV plan will be implemented upon receiving
EPA approval. The Annual Subpart RR Report will be filed on March 31 of the year following the
reporting year.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 74 of 77

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SECTION 9 - QUALITY ASSURANCE

This section identifies how Ozona plans to manage quality assurance and control to meet the

requirements of 40 CFR §98.444.

9.1	Monitoring QA/QC

CO2 Injected

•	The flow rate of the CO2 being injected will be measured with a volumetric flow meter,
consistent with API standards. These flow rates will be compiled quarterly.

•	The composition of the injectate stream will be measured upstream of the volumetric flow
meter with a continuous gas composition analyzer or representative sampling consistent
with API standards.

•	The gas composition measurements of the injected stream will be averaged quarterly.

•	The CO2 measurement equipment will be calibrated per the requirements of 40 CFR
§98.444(e) and §98.3(i).

CO2 Emissions from Leaks and Vented Emissions

•	Gas monitors at the Plant and O'Neal No. 4 will be operated continuously, except for
maintenance and calibration.

•	Gas monitors will be calibrated according to the requirements of 40 CFR §98.444(e) and
§98.3(i).

•	Calculation methodsfrom Subpart W will be used to calculate CO2 emissions from equipment
located on the surface, between the flow meter used to measure injection quantity and the
injection wellhead.

Measurement Devices

•	Flow meters will be continuously operated except for maintenance and calibration.

•	Flow meters will be calibrated according to 40 CFR §98.3(i).

•	Flow meters will be operated and maintained in accordance with applicable standards as
published by a consensus-based standards organization.

All measured volumes of CO2 will be converted to standard cubic meters at a temperature of 60°F

and an absolute pressure of 1 atmosphere.

9.2	Missing Data

In accordance with 40 CFR §98.445, Ozona will use the following procedures to estimate missing

data if unable to collect the data needed for the mass balance calculations:

•	If a quarterly quantity of CO2 injected is missing, the amount will be estimated using a
representative quantity of CO2 injected from the nearest previous period at a similar
injection pressure.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 75 of 77

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• Fugitive CO2 emissions from equipment leaks from facility surface equipment will be
estimated and reported per the procedures specified in Subpart W of 40 CFR §98.

9.3 MRV Plan Revisions

If any changes outlined in 40 CFR §98.448(d) occur, Ozona will revise and submit an amended MRV
plan within 180 days to the Administrator for approval.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 76 of 77

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SECTION 10 - RECORDS RETENTION

Ozona will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
3 years and include the following:

•	Quarterly records of the CO2 injected

o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the CO2 stream

•	Annual records of the information used to calculate the CO2 emitted by surface leakage from
leakage pathways.

•	Annual records of the information used to calculate CO2 emitted from equipment leaks and
vented emissions of CO2 from equipment located on the surface, between the flow meter
used to measure injection quantity and the injection wellhead.

Subpart RR MRV Plan - O'Neal Gas Unit No. 4

Page 77 of 77

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APPENDICES
APPENDIX A - O'Neal No. 4 TRRC FORMS

APPENDIX A-l: GAU GROUNDWATER PROTECTION DETERMINATION

APPENDIX A-2: DRILLING PERMIT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

APPENDIX A-3: COMPLETION REPORT

•	CHARLIE C. OVERBY API 42-025-32658

•	O'NEAL GAS UNIT NO. 4 API 42-025-32658

•	ACID FRACTURE REPORT

APPENDIX A-4: API 42-025-30388 CHARLIE C. OVERBY GU PLUGGING RECORDS

-------
APPENDIX B - AREA OF REVIEW

APPENDIX B-l: OIL AND GAS WELLS WITHIN THE MMA LIST

APPENDIX B-2: WATER WELLS WITHIN THE MMA LIST

-------
APPENDIX A-l

GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit

Form GW-2

Date Issued:

26 May 2023

GAU Number:

367912

Attention:

OZONA CCS LLC

API Number:

02532658



19026 RIDGEWOOD

County:

BEE



SAN ANTONIO, TX 78259

Lease Name:

O'Neal Gas Unit









Lease Number:

162214

Operator No.:

100116







Well Number:

4





Total Vertical

16101





Latitude:

28.602914





Longitude:

-98.001428





Datum:

NAD27

Purpose:
Location:

Injection into Producing Zone (H1)
Survey-EL&RR RR CO; Abstract-452; Section-1



To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:

The base of usable-quality water-bearing strata is estimated to occur at a depth of 250 feet at the site of the referenced
well.

The BASE OF UNDERGROUND SOURCES OF DRINKING WATER (USDW) is estimated to occur at a depth of 950
feet at the site of the referenced well.

Note: Unless stated otherwise, this recommendation is intended to apply to all wells drilled within 200 feet of the subject well.
Unless stated otherwise, this recommendation is for normal drilling, production, and plugging operations only.

This determination is based on information provided when the application was submitted on 05/26/2023. If the location
information has changed, you must contact the Groundwater Advisory Unit, and submit a new application if necessary.

If you have questions, please contact us at 512-463-2741 orgau@rrc.texas.gov.

Groundwater Advisory Unit, Oil and Gas Division

Form GW-2 P.O. Box 12967 Austin Texas 78771-2967 512-463-2741 Internet address: www.rrc.texas.
Rev. 02/2014

-------
Online System

Oil & Gas Data Query

Query Menu

Drilling Permit (W-1) Query Results

APPENDIX A-2

Search Criteria:
API No.: 02532658

Return



2 results Page: 1 of 1 Page Size: view ah v

API NO.

District

Lease

Well
Number

Permitted
O iterator

Countv

Status
Date

Status
Number

Wellbore
Profiles

Filina
PurDose

Amend

Total
Death

Stacked
Lateral
Parent
Well DP

#

Status

02532658 Links v

02

CHARLIE
C.

OVERBY
GAS
UNIT

2

PARKER &
PARSLEY
DEVELOPMENT
CO.(640889)

BEE

Submitted:
11/30/1992
Approved:
11/30/1992

406655

Vertical

New Drill

N

16700



APPROVED

02532658 Links v

02

O'NEAL
GAS
UNIT
Q622141

4

PARKER &
PARSLEY
DEVELOPMENT
L.P(640886)

BEE

Submitted:
11/20/1996
Approved:
12/16/1996

455434

Vertical

Re completion

N

14040



APPROVED

Download

Return



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NOTE: THE CHARLIE C. OVERBY GU AND THE O'NEAL GU ARE THE SAME WELL. THE OVERBY WELL WAS DRILLED IN 1993 INTO THE SLIGO.
IN 1997 THE WELL WAS RECOMPLETED IN THE EDWARDS FORMATION. THIS WAS DONE UNDER A NEW LEASE, AS THE O'NEAL GU NO. 4.

-------
Form W-1: Field List

Log In

Status # 406655
API # 025-32658

OP # 640889 - PARKER & PARSLEY DEVELOPMENT CO.

Approved ,Issued: 11/30/1992 ,Filed: Hardcopy

CHARLIE C. OVERBY GAS UNIT - Well # 2

02 - BEE County

New Drill

Vertical

NEAREST WELL COMMENT: 1607.8 ( 11/30/1992 12:00:00 AM )

Status:

Back to Public Query Search Results

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

01/01/1993

02/11/1993

01/01/1993

Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (SLIGO)

Gas

02/11/1993

06/18/1993

General / Location Information

Basic Information:

Filing
Purpose

Welbore
Profiles

Lease Name

Well

#

SWR

Total
Depth

Horizontal
Wellbore

Stacked Lateral Parent
Well DP #

New Drill

Vertical

CHARLIE C. OVERBY
GAS UNIT

2

SWR
36

16700





Surface Location Information:

API #

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658

4.0 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





EL&RR RR CO

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Survey Lines

2784.0 feet

from the S line and

1045.5 feet

from the W line

Permit Restrictions:

Code

Description

30

REGULAR PROVIDED THAT UPON SUCCESSFUL COMPLETION OF THIS WELL IN THE SAME RESERVOIR AS ANY OTHER WELL
PREVIOUSLY ASSIGNED THIS ACREAGE, A P-15 AND REVISED PRORATION PLATS MUST BE SUBMITTED WITH NO

30

DOUBLE ASSIGNMENT OF ACREAGE.

30

REGULAR PROVIDED THIS WELL IS NEVER COMPLETED IN THE SAME RESERVOIR AS ANY OTHER WELL CLOSER THAN 2640
FEET ON THIS SAME LEASE.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

https://webapps.rrc.texas.gov/DP/drillDownQuery Action, do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362... 1/2

-------
11/28/23, 4:52 PM

Form W-1: Field List

30 O'NEAL GU #3, O'NEAL #1, OVERBY #120 & NEAL #1.

Fields

District

Field
Name

Field #

Completion
Depth

Lease
Name

Well

#

Well
Type

Acres

Distance to

Nearest

Well

Distance to
Nearest
Lease Line

SWR

Pooled/
Unitized

02

PAWNEE
(SLIGO)

Primary
Field

69845800

16700

CHARLIE C.
OVERBY GAS
UNIT

2

Oil or

Gas

Well

704.0





SWR
36

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 2390.0 feet from the E line and 3446.0 feet from the N line



I

Comments

Remark

Date Entered

Entered By

NEAREST WELL COMMENT: 1607.8

11/30/1992 12:00:00 AM

SYSTEM

Attachments

Attachment Type

File Path

Associated Fields and/or Plats

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https://webapps.rrc.texas.gov/DP/drillDownQuery Action.do ;jsessionid=1sgYITd2j0yRMPcplNSYQdAEbUJ0fUkSXI-AvaSR7IL5etXxKu4l!-1777335362.

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-------
***** Online System

Log in

Form W-1: Review

Status# 455434
API # 025-32658

OP #640886 - PARKER & PARSLEY DEVELOPMENT L.P

Approved ,Issued: 12/16/1996 ,Filed: Hardcopy

O'NEAL GAS UNIT - Well # 4

02 - BEE County

Recompletion

Vertical

NEARESTWELL COMMENT: 1787 ( 11/20/1996 12:00:00 AM )

Status:

Back to Pui?iig Query Search Resets

Completion Information

Well Status Code

Spud Date

Drilling Completed

Surface Casing Date

W - Final Completion

02/04/1997

02/13/1997



Field Name

Completed Well Type

Completed Date

Validated Date

PAWNEE (EDWARDS)

Gas

02/13/1997

02/26/1997

General / Location Information

Bask Information:

Filing Purpose

Wei bore Profiles

Lease Name

Well #

SWR

Total Depth

Horizontal Wellbore

Stacked Lateral Parent Well DP #

Recompletion

Vertical

O'NEAL GAS UNIT

4

SWR 36, SWR37H

14040





Surface Location Information:

API#

Distance from
Nearest Town

Direction from
Nearest Town

Nearest Town

Surface Location Type

025-32658 lil

3.5 miles

S

PAWNEE

Land

Survey/Legal Location Information:

Section

Block

Survey

Abstract #

County





E.L.&R.R. RR CO. #1

452

BEE

Township

League

Labor

Porcion

Share

Tract

Lot















Perpendicular surface location from two nearest designated reference lines:

Perpendiculars

Distance

Direction

Distance

Direction

Survey Lines

825.0 feet

from the W line and

2784.0 feet

from the S line

Permit Restrictions:

Code

Description

30

WILDCAT ABOVE 14040 FEET

30

ANY WELLBORE DRILLED UNDER THIS PERMIT MUST BE COMPLETED, OPERATED, AND PRODUCED IN COMPLIANCE WITH STATEWIDE RULE 32.

30

REGULAR PROVIDED THIS WELL IS DRILLED IN COMPLIANCE WITH RULE 36.

Fields

District

Field Name

Field #

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

WILDCAT
Primary Field

00004001

14040

O'NEAL GAS UNIT

4

Oil or Gas Well

704.0





37H

Y

Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the S line





District

Field Name

Field#

Completion Depth

Lease Name

Well #

Well Type

Acres

Distance to Nearest Well

Distance to Nearest Lease Line

SWR

Pooled/ Unitized

02

PAWNEE CEDWARDS)

69845200

14040

O'NEAL GAS UNIT

4

Gas Well

704.0





SWR 36, 37H

Y



Perpendiculars Distance Direction Distance Direction
Surface Lease Lines 4900.0 feet from the W line and 2784.0 feet from the S line







Exceptions

Field

Exception

Case Docket Number

Resolution

WILDCAT

SWR 37 [Historical]

0214349



PAWNEE CEDWARDS)

SWR 37 [Historical]

0214349



Comments

Remark

Date Entered

Entered By

NEARESTWELL COMMENT: 1787

11/20/1996 12:00:00 AM

SYSTEM

Attachments

Attachment Type	File Path	Associated Fields and/or Plats

Disdaimer | RRC Online Home | RRC Home | Contact

-------
APPENDIX A-3

Ozona CCS

Well Name: ONeal Gas Unit 4 (current)
Formation: Edwards
County, State: Bee County, TX
API #: 42-025-32658
Permit #:

Rig
GL
RKB
TD (MD)
TP (TVD)

Lat, Long 28.6031807,-98.0017091 (NAD83)
GAU Depth:

MD/TVD

10.75" Surface Casing

Cook Mountai n

3657

Sparta

4259

Weches Sandstone

4326

Queen City

4655

Reklaw

5244

Carrizo

5864

Wilcox

5922

Midway

9026

Austin Chalk

13266

Eagle Ford

13344

Buda

13494

Edwards

13500

CIBP w/ 20' Cement on Top

14000

5" Liner Top

14088

Pearsall

15339

1 5/8" Intermediate Casing

15340

zd





C02 Resistant Permanent Packer

Sligo



L



Tubular Detail

String

Hole Size

OD

Weight

Grade

MD



(in)

(in)

(#/ft)



(ft)

Conductor











Surface

14 3/4"

10 3/4"

55.5

S-95

3,610'

Intermediate

9 1/2"

7 5/8"

39

CY-95

15,340'

Liner

6 1/2"

5"

18

Q-125

14,088'-16,101'

Prod Tbg



2 3/8"

4.7

L-80

13453'

Cement Detail

String

Vol

Type

TOC

%XS



(sks)



(MD)



Surf Lead

1125

HLC

0'



Surf Tail

350

H





Int Lead

575

50:50 Poz:H

7359'



Int Tail

400

H





Liner

200

Premium

14088'



Edwards perfs production zone, 13,529*-13,841*	

Cumulative 6,555,750 MCF gas, 168,888 BBLs water produced

Initial production zone, 15,874'-16,056*

Cumulative 511,964 MCF gas, 22,026 BBLs water produced

Well History

#

Date

Description

1

12/30/1992

First spud as gas well, targeting the Sligo formation

2

2/13/1997

Plugged back to 14,000' and recompleted

-------
TUBING PRESSURE
ANNULUS PRESSURE

ps
ps

20000

18000

16000

14000

12000

10000

2000

16:05

SLURRY RATE

(bpm)

NOTE: THE CHARLIE C. OVERBY GU AND THE O'NEAL GU ARE THE SAME WELL. THE OVERBY WELL WAS DRILLED IN 1993 INTO THE SLIGO.
THIS ACID FRACTURE REPORT IS FOR THE ORIGINAL COMPLETION IN THE SLIGO FORMATION.

16:20

16:35

16:50

_r_—r

17:05	17:20

17:35

TIME (min)

"i	r

17:50	18:05

18:20

18:35

CUSTOMER: PARKER & PARSLEY DEV. CO. JOB DATE: APR-03-1993
WELL DECS: OVERBY §2	FORMATION: SLIGO

TICKET #: 30840901

JOB TYPE: SWIC ACID BALLOUT

-------
PASE i

Custoisr; PARKER & PARSLEY DEV. CO,	Ticket I; 30840901

Hell Descs OVERBY 12	Foraation; SLI80

TIME

STA6E

TUBING PR

ANNULUS PR SLURRY RT

HR:MH:SS

NO

(psi)

(usi)

(bpl)

16:06:02

0

0

0

0,00

16:07:02

0

3216

470

0.00

16:08:02

1 Event(Eng) Oper

ator Stags Advance



16:08:02

1

3251

"470

2.65

16:09:02

1

3904

470

8.43

16:10:02

1

4471

528

8.24

16:11:02

1

5059

1612

8.17

16:12:02

1

5812

1978

8.04

16:13:02

1

7j58

1906

8,62

16:14:02

1

9069

1875

7.03

16:15:02

1

9950

2004

5.82

16:16:02

1

9504

1922

5.82

16:17:02

1

9572

1863

6,51

16:18:02

1

9304

2003

6.86

16:19:02

1

9539

1870

8.03

16:20:02

1

9725

1945

7.95

16:21:02

1

9862

1920

6,52

16:22:02

1

9216

1886

4.43

16:23:02

1

9672

1992

4.43

16:24:02

2 Event(Eng) Operator Staoe Advance



16:24:02

2

9384

1906

4.15

16:25:02

2

9416

1906

5.36

16:26:02

7

9547

1964

4.56

16:27:02

2

9150

1915

2.05

16:28:02

2

9898

2032

3,96

16:29:02

£

9812

1948

3.30

16:30:02

7

9824

1876

3,30

16:31:02

2

9882

1944

3.30

16:32:02

¦/

10020

1967

3.26

16:33:02

2

9946

1898

3.24

16:34:02

2

9733

1986

2,90

16:35:02

2

9654

1980

2.90

16:36:02

2

9590

1921

2,90

16:37:02

2

9558

1870

2.91

16:38:02

2

9552

2018

2.90

16:39:02

2

9420

1960

2.30

16:40:02

2

9377

1908

2,97

16:41:02

2

9369

1866

2.90

16:42:02

2

9485

2010

3,07

16:43:02

2

9635

1961

3.10

16:44:02

2

9647

1910

3.09

16:45:02

2

9644

1868

3.12

16:46:02

3 Event(Eng) Operator Stage Advance



16:46:02

ij

9622

2011

3.10

16:47:02

3

9601

1955

3.10

16:48:02

d

9597

1905

3.10

16:49:02

3

9596

1867

3,10

16:50:02

3

9568

2020

3.10

16:51:02

j

9553

1968

3.10

16:52:02

3

9551

1923

3.10

16:53:02

3

9667

1883

3.26

16:54:02

3

9707

1859

3.26

16:55:02

3

9708

2024

3.22

16:56:02

i

9718

1974

3,27

16:57:02

3

9720

1927

3.25

Date; Apr 3, 1993
Job Type: SWIC ACID BAILOUT

-------
PfiBE 2

Custoaer; PARKER & PARSLEY DEV. CO.	Ticket I; 30840901	Bate: Apr 3, 1993

yell Desc: OVERBY 12	Foraation: SLI80	Job Types SWIC ACID BAILOUT

TIME

STAGE

TUBING PR ANNULUS PR SLURRY RT

HRiMHiSS

NO

(psi)

(psi)

(bps)

16:58:02

3

9705

1883

3,26

16:53:02

3

9709

1984

0 0^

u'» a.

17:00:02

3

9686

1996

3.26

17:01:02

3

9677

1958

3.27

17:02:02

3

96?!

1924

3.26

17:03:02

3

9630

1889

3.2b

17:04:02

3

9563

1857

3,26

17:05:02

3

9560

2025

3.26

17:06:02

3

9417

1983

3.28

17:07:02

3

9153

1943

3.12

17:08:02

3

9569

1933

3,12

17:09:02

3

9691

1909

3,10

17:10:02

3

9532

1880

3,12

17:11:02

3

9509

1943

3.10

17:12:02

3

9568

2012

3.10

17:13:02

3

9611

1979

3.12

17:14:02

3

9576

1947

2.97

17:15:02

3

9607

1917

3.06

17:16:02

n
0

9805

1893

3.28

17:17:02

3

9858

1865

3.29

17:18:02

3

9827

2031

3,28

17:19:02

3

9864

1994

3,43

17:20:02

3

9872

1963

3.30

17:21:02

3

9681

1927

3.12

17:22:02

0

9325

1884

3.37

1/««. «0 2

3

9445

1902

3.33

17:24:02

4 Event(Eng) Operator

Stags Advance



17:24:02

4

9468

2027

3,32

17:25:02

4

9436

1988

3«32

17:26:02

4

9594

1960

3,33

17:27:02

4

9502

1928

3,33

17:28:02

4

9428

1896

3.32

17:29:02

4

9425

1867

3,33

17:30:02

4

9437

2045

3,33

17:31:02

4

9439

2026

3.32

17:32:02

4

9454

1996

0 91
U t ujL

17:33:02

4

9492

1971

3.32

17:34:02

4

9577

1947

3.32

17:35:02

4

9585

1923

3.32

17:36:02

4

9818

1908

2.69

17:37:02

4

9839

1889

2.93

17:38:02

4

9661

1870

2.82

17:39:02

4

9808

1862

2.90

17:40:02

4

9642

2047

2,67

17:41:02

4

9589

2027

2,69

17:42:02

4

9583

2015

2.69

17:43:02

4

9858

2011

2.90

17:44:02

4

9662

1996

2.69

17:45:02

4

9649

1986

2,68

17:46:02

4

9624

1973

2.68

17:47:02

4

9477

1956

2,69

17:48:02

4

9360

1942

2.68

17:49:02

5 Eyent(Eng) Operator Stage Advance



17:49:02

3

5770

1941

2,99

17:50:02

5

9585

1926

2.66

-------
PASE 3

Custotisr; PARKER & PARSLEY DEV. CO.	Ticket #: 30340901	Date; Apr 3, 1993

Hell Desc; OVERBY #2	Fortation: SLI60	Job Type; SWIC ACID BAILOUT

TIME

STAGE TUBINQ PR

ANNULUS PR

SLURRY RT

HR:HH:SS

NO (osi)

(psi)

(boa)

17:51:02

5

9577

1913

2.85

17:52:02

5

9749

1908

2.78

17:53:02

5

9627

1895

2.68

17:54:02

5

9638

1885

2.67

17:55:02

5

9636

1873

2,68

17:56:02

5

9642

1866

2.68

17:57:02

5

9658

2047

2.70

17:58:02

r
J

9659

2047

2.68

17:59:02

5

9783

2036

2.99

i'3:00:02

5

9937

2028

2.78

18:01:02

5

9837

2014

2.93

18:02:02

5

9857

2003

2.72

13:03:02

D

9874

1992

2.70

18:04:02

5

9617

1972

2.73

18:05:02

5

10006

1978

2.05

18:06:02

5

8309

1925

0.00

18:07:02

5

Event(Eng)



SHUT

18:07:02

5

6123

1842

0.00

18:08:02

D

6862

2033

0.00

18:09:02

5

6742

2129

0,00

18:10:02

5

6873

2278

0.00

18:11:02

5 Event(Enq)

RESUME PUMPING

18:11:02

5

7239

2367

0.00

18:12:02

5

7694

2426

4.18

18:13:02

5

8434

2440

5.10

18:14:02

5

Event(Eng) PRESSURE BREAK AT 9000PSI

18:14:02

5

8891

2411

5.11

18:15:02

5

8952

2350

5.52

18:16:02

j

9814

2296

7.05

18:37:02

5

9831

2203

6.76

18:18:02

c
J

9875

2099

6.78

18:19:02

5

9919

1995

6.67

18:20:02

h

9954

1896

6.63

18:21:02

5

10000

1852

6.15

18:22:02

c
J

9622

2000

6.05

18:23:02

5

9607

1903

6.16

18:24:02

5

9620

1822

6.17

18:25:02

h

8541

1978

4.22

18:26:02

5

8562

1933

3.72

18:27:02

6 Event(Enq) Operator

Staqe Advance



18:27:02

&

7285

1880

0,00

18:28:02

6

7269

1913

0.00

18:29:02

&

7253

1954

0.00

18:30:02

6

7251

2001

0.00

EEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEEE

-------
L- u s t o m er : P M k K b k * • P ft K fc> L E V D E. V. U U.	D at*""	A I"' k—U 3 — 1 y 9 3

Well Desc s OVERBY<	Tic t #j 30840301

Formations SL.1G0	Job Types SWIC ACID BALLOUT

InOMF'" I SLJF^VT I ON

Wei I bore Actual Casing Casing Tubing Tubing
Segment Length TVD ID 0D ID 0D
Number	i feet)	( feet)	( inch )	( i n c h )	<: inch )	< inch )

1	14088 14088 4,,276 5.000 2,441 2.875

2	15874 15874 4.276 5.000 0.000 0.000

i—" EE r: f* O iR:"I' 1 O tsl S O *=% "1"

# of Per for at ions .15.		

Perf. D iameter . 3 					

Ba 11 ed 0ut ? (YES/' N0) yes	 			

F" EE F~ O F? ft ~T' EE! O 2. fsi T" EE R

r'ROli
C f eet)
15874

TO	SF'F

C feet >

		IMse 		l

-------
Well Descs OvERBY /'"•	Ticl-'-t #; 30840901

F"ormat ions BL.IG0 '•	Job ypei SWIC AC11) BA!....L0U1"

M^VT

£ I. rt»	£3

It fvi V EE i'vS "S' O FS Y

T r e a t m e n t Flu i d s
D i s p 1 a c e m e n t F1 u :i. d :
S u r f a c t a n t T y p e:
Clay Controls
F r :i. c t i o n R e d u c e r ;
Perfpac Ballss

TREATED

WATER

L0SURF

300

CLAYFIX

I I

FR---2S

30

Density-
Density

gal 20
9 a 1
gal
Qty

6 - 33

40

¦:u

1 b / g a 1
1 b / q a 1

2	1	

@ 2	

© ~

L

7/8

Size 1,3

gal/Mgal
gal/Mgal
gal/Mg cl 1

y „ u.

-------
Customer; PARKER * PARSLEY DEV. CO,	Datf-	APR-~03~ 1393

Well Desc: OVEkBY .	Tic t #; 30840301

For mat i on s Si... IG0	J0b "I"ype; SWIC AC1D BAL.L0UT

i'"l A i l~~ K .1. f'--s 8	fcS C_l fxl 1	O G #—'s "1 It (3 ffsl

BfMRIINti FLUID VOLUME	20000
-------
Well Descs QVERBY "2	Tic1 #; 30840901

Formations SLIQO	Job ypes SWIC ACID BALL01.IT

oO

O A "1"

Acid Types

SWIC

	"/. ii.

			 g a i

10000



S u r f a c t a n t T y p e:

HC--2

oal

50

w 5

qal/Mqal

N E A g e n t T y p e:

SF-'ERfcSE ALL

a a 1

50

0 5

qal/Mqal

Corrosion Inh» s

HAI-85

a a I

200

(§ 20

qal/Mqal

Corrosion Inh.:

HI.!" 500

aal

200

0 20

qal/Mqal

Cracking Inh.:

SCA	130

q a 1

200

@ 20

qal/Mqal

Ir on Seqnest er:

F.E-.3

lb

1000

@ 100

lb/Mqal

F r i c t i o n R e d u c e r ;

SGA--HT

qal

30

fe 3

qal/Mqal

Ot her 5

A.B.F

	LB_

.12.0	

12

1 b /Mq aI

-------
Customer; PARKER PARSLEY DEV. CO.	Dat	APR-03-1993

Well Descs OVERBY #2	Ticket #g 30840901

Format ion: SLIGO	-Job Type; SWIC ACID BALLOUT

J O B O O HI £! D Li i	EE

S' I"" #=* €3 EE OI EE S C F? I F> "F X O M S

St;age		Descr ipt ion	

1	TREATED WATER - LOAD HOLE. EST, RATE

2	SWIC ACID

3	SWIC ACID WITH 30 BALLS

4	SWIC ACID

5	TREATED WATER - FLUSH

6	SHUTDOWN MONITOR PRESSURE

-------
Customer s PARKER /* • PARSLEY DEV. CO.	Dat'~*~	APR-OS-1993

Wei 1 Desc s OVLRBY ...	Tic. b #s 30840901

Formations SLIGG	Job Type; SWIC ACID BALL OUT

J O t.~.s fci i_j: i—I fc. O l_l i	EZ

t-i i #-11 fc£ I IM F~ OIR f'"1 A" 1"" 01M

2		3	4	5 	6

Fluid Type

FR-26LC

S6A-HT 15X

S6A-HT 157,

SSA-HT 15%

FR-26LC

FR-26LC

Planned Clean Vol line (gal)

5000

3000

5000

2000

6000

0

Planned Slurry Voluse (gal)

5000

3000

5000

2000

6000

0

Actual Slurry Volume (gal)

4764

2937

5002

3217

5628

2

Base Fluid Density (lb/gal)

8.33

8.36

8,36

8.96

8.33

8.33

Concentration

1.00

3.00

3.00

3.00

1.00

1.00

Proppant Size













Proppant Type













fibs. Proppant Volu#e (gal/lb)

0.04530

0.04530

0.04530

0.04530

0.04530

0,04530

Planned Fluid Rate (bps)

8,00

10.00

10.00

10.00

10.00

0,00

Planned Prop Cone (lb/gal)

0.00

0.00

0.00

0.00

0.00

0.00

-------
Customer;
We?11 Desc :
Format i on:

PARKER

GVERBY
SL160

PARSLEY DEV. CO.

Datr- -

Tic fc #s

Job Types

Apr 3, 1393
30840901

SWIC acid ballout

iz> 1 rt «..£i EE £:3L.J iM M if-'-t |-< 'V

Stage Times

St age
1

3

4

6

Total

St ar t
T i me
16:07s 05
16; 2 3 m '4 4
16;45s 47
17:23;04
17:48s11
18:26s 43

End
T i me

16	: 23 s 44
16;45:47
17s23s 04

17	: 48: 11
IBs 26s 43
18s 37:38

Elapsed
T i me
00:16;39
00:22:03
00 s 37 s17
00;25:07
00 s 38 s 32
00:10:55
02 : 30 : 33

T i me
at Per fs
16:25s 09
16:58;54
17:21:16
18:01:29
18s 22:26

St age
1

3

4

5

6

T ot/Avg

T utaing
Pressure
(p s i >
7748
9615
9626
9560
9005
4293
8860

Annul us
Pr essure

(p s i )
1613
1940
1943
1961
2036
1578
1906

SIurry
Rate
(b p rn >
6, 44
3.24
3.19
3. 05
3. 48
0.01
3. 38

SIurry
Volume
(. g a 1 >
4767
2996
5002
3215
5629

21610

-------
U ustomer : P A ft K E R * P A R S L EY DEV. CD.	Dai'""	A P R -03-1993

Well Desc 5 OVERBY ! ..	Tic t #s 30840901

Formation; SLI80	job Type; SWIC ACID BALLOUT

«=: v ti dm "i • f> ee: f* o re ~i -

staqe

Event
isneuB

Tise
HH;MM;SS

Event Description

e 1

stgad

16:07:05

Operator Stage Advance

--> TREATED HATER - LOAD HOLE. EST. RATE

B 2

stgad

16:23:44

Operator Stage Advance

--> SWIC ACID

e 3

stgad

16:45:47

Operator Stage Advance

--> SWIC ACID WITH 30 BALLS

e 4

stgad

17:23:04

Operator Stage Advance

--> SWIC ACID

e 5

stgad

17:48:12

Operator Stage Advance

--> TREATED WATER - FLUSH

e 5

NOTES

18:06:36

Operator's Notes

SHUT DOWN TO SURGE BALLS ISIP 9320

e 5

NOTES

18:10:44

Operator's Notes

*** RESUME PUMPING

e 5

NOTES

18:14:01

Operator's Notes

m PRESSURE BREAK fil 9UOOPSI

e 6

stgad

18:26:43

Operator Stage Advance

-> SHUTDOWN MONITOR PRESSURE

e 6

NOTES

18:31:25

Operator's Notes

Hit ISIP = 7285 PSI FS = .889

e &

NOTES

18:32:46

Operator'5 Notes

i« 5 HIN SIP = 7238 PSI

-------
APPENDIX A-4

Plugging Record

RAILROAD COMMISSION OF TEXAS
OIL AND GAS DIVISION

FORM W-3
Rev, 12/92

EAG0S97

API NO

(if available) 42-025-30388

FILE IN DUPLICATE WITH DISTRICT OFFICE OF DISTRICT IN WHICH
WELL IS LOCATED WEtfffif"THIRTY DAYS AFTER PLUGGING

1. RRC District
02

4. RRC Lease or Id.
Number
064112

2 FIELD NAME (as per RRC Records)
Pawnee	

( Sliqo )

3. Lease Name

Oveitoy, Charlie C. Gas Unit

5. Well Number
	1

OPERATOR
Pioneer Natural

6a. Original Form W-l Filed in Name of

10. County

purees USA, Inc.

Bee

7. ADDRESS
5205 N. O1

for Blvd. , Ste.

75039-3736
900 Irving, TX

6b. Any Subsequent W-l's Filed in Name of.

11. Date Drilling
Permit Issued

Location of^/ell, Relative to Nearest Lease Boundaries
of Leasg>eBwhich this Well is Located

' /	Feet From "W

Line and /7-S^ Feet From

12 Permit Number

>S Line of the

ron

Lease

9a SECTION, BLOCK, AND SURVEY
Marcelo Alcarte

A-70

9b. Djstance and Direction Fi'om Nearest Town in this
Co '

-ounty

3.5 miles South of Pawnee

13. Date Drilling
Commenced

16. Tvpe Well

(Oil, Gas, Diy)
	Gas	

Total Depth
16.300

18. If Gas, Amt. of Cond. on
Hand at time of Plugging

17. If Multiple Completion List All Field Names and Oil Lease or Gas ID No's

GAS ID or
OIL LEASE #

Oil-O
Gas-G

WELL
#

14. Date Drilling
Completed

^

15. Date Well Plugged

3-S-P7

CEMENTING TO PLUG AND ABANDON DATA:

PLUG #1

PLUG #2

PLUG #3

PLUG #4

PLUG #5

PLUG #6

PLUG #7

PLUG #8

*19. Cementing Date

2-27

2-27

3-2

3-5

3-6

3-6





20. Size of Hole or Pipe in which Plug Placqd^ippjie^,-,,^

3 1/2

3 1/2

7

7

7

7





21. Depth to Bottom of Tubing or Drill-Pipe-(fc»),c

9310

9200

3800

3563

300

15





*22. Sacks of Cement Used (each plug)

1

1

35

55

55

6





*23 Slurry Volume Pumped (cu ft) ~

1.06

1.06

37.10

58.30

58.30

6.36





*24- Calculated Top of Plug (ft.)

9280

9180

3650

3428

200

5





25. Measured Top of Plug (if tagged) (ft.)









187







*26. Slurry Wt. #/Gal. „

16.4

16.4

16.4

16.4

16.4

16.4





*27. Type Cement

H

H

H

H

H

H





28. CASING AND TUBING RECORD AFTER PLUGGING

29. Was any Non-Drillable Material (Other rav l—l xt
than Casing) Left in This Well ^ Yes U No

SIZE

WT.#/FT.

PUT IN WELL (ft.)

LEFT IN WELL (ft.)

HOLE SIZE (IN.)

29a. If answer to above is "Yes" state depth to top of "junk" left m hole
and briefly describe non-drillable material. (Use Reverse Side of
Form if more space is needed)

Left 3 1/2 tubing in well from 3800' to 15,055'. An

existing fish of 1 1/4" tubing from 9340' to 16,143'

also left in well.

16

49.50

61

61

UNK.

10 3/4

45.50

3513

3508

15"

7

49.50

15.529

15 r 524

8 3/4

4"

UNK

15055-16290

14247



30. LIST ALL OPEN HOLE AND/OR PERFORATED INTERVALS

FROM

15,911 T0 16.072



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

FROM



TO



FROM TO

I have knowledge that the cemep
-------
• •

!L5SS?^a!S,* a Yes 32. How was Mud Applied? 33. Mud Weight

Railroad Commission I | No Cirnnl ated 12 5 I RS/fiAT

34, Total Depth
16,300

Other Fresh Water Zones by T.D.W.R.
TOP BOTTOM

35. Have all Abandoned Wells on this Lease been Plugged 1 I v»,
according to RRC Rules? Yes

~ No

Depth of Deepest
Fresh Water

250



36. If NO, Explain

37.	Name and Address of Cementing or Service company who mixed and pumped cement plugs in this well i Date RRC District Office
Bat's P & A, Inc. P.O. Box 0126. Biahr.r. IX 78343 	I notified of plugging 2-23-07

38.	Name(s) and Addresse(s) of Surface Owners of Well Site

39. Was Notice Given Before Plugging to the Above?

FILL IN BELOW FOR DRY HOLES ONLY

40. For Diy Holes, this Form must be accompanied by either a Driller's, Electric, Radioactivity or Acoustical/Sonic Log or such Log must be
released to a Commercial Log Service.

~ Log Attached	~ Log released to 			 Date	

Type Logs:

I—I Driller's	I	I Electric	I I Radioactivity	I I Acoustical/Sonic

41. Date FORM P-8 (Special Clearance) Filed?

42. Amount of Oil produced prior to Plugging

* Field FORM P-l (Oil Production Report) for month this oil was produced	

RRC USE ONLY

Nearest Field

REMARKS Unable to recover 3 1/2" tbg. as anticipated above existing 1 1/4" fish @ 9340'. Jet cut 3 1/2"	

	@ 9302' & 9243'. Unable to pull or establish calculation up 3 1/2 x 7" @ 3500 P.S.I.. Freepoint on 3 1/2

gsq-	at 4750 — . Notified and received approval from Kevin Shamette W/RRC to spt rrmp'g + 20' cmt below and

above cut's made on 3 1/2. Plug #1 & #2 - CIBP + 20' cmt. in 3 1/2" 12.95#. Cut 3 1/2 a 47fi9'anri perforated
3 1/2" 6 4765' but unable to pull or circulate. Re-cut @ 3800'. Received verbal approval from Kevin Shamo-H-p
W/RRC to set plug from 3800' tp 3650' Cut & perforated 7" casing 6 3563'. Casing not	TTnaKio i-r,	

establish circulation but established injection into 7" x 8 3/4" @ 2000 P.S.I.
Notified Ke.vin W/RRC to squeeze plug. Squeezed 5 5 sks. cmt. leaving 23 sks.
inside 7" 49.50# and 32 sks. outside in 7" x 8 3/4". Cut 7" csg. @ 300' but
unable to circulate. Received verbal approval to squeeze 55 sks. Squeezed
38 sks. out into 7" x 9 5/8" and left 17 sks inside 7" casing.

J

-------
O'Neal Gas Unit No. 4

APPENDIX B-l

Area of Review: Oil & Gas Wells List

API

WELL NAME

WELL NO.

CURRENT OPERATOR

ABSTRACT

LATITUDE
(WGS84)

LONGITUDE
(WGS84)

WELL STATUS

TOTAL DEPTH
(TVD FT.)

PERFORATED INTERVAL
(MD FT.)

DATE DRILLED

4202500002

ONEAL, A.

1

ROWAN & HOPE

126

28.603017

-98.000911

DRILLED

7010

NO RECORD

8/9/1949

4202500005

RUSSELL, S.

1

PAN AMERICAN PETROLEUM CORP.

308

28.594587

-97.999841

DRILLED

7515

NO RECORD

5/12/1947

4202530346

HENRY BUES

1

PIONEER NATURAL RES. USA, INC.

70

28.5986210

-98.0118480

INACTIVE PRODUCER

13842

7554-7558; 7612-7624;
13526-13760

11/10/1974

4202530359

ONEAL GAS UNIT

2

BB-SOUTHTEX, LLC

127

28.61178

-98.000661

PRODUCING

13961

13349-15821

4/5/1975

4202530388

OVERBY, CHARLIE C. GAS UNIT

1

PIONEER NATURAL RES. USA, INC.

70

28.601086

-98.005037

P &A

16300

15911-16072

6/6/1975

4202532342

DE LEON

1

T D EXPLORATION, INC.

126

28.6006330

-97.9917520

P &A

6512

NO RECORD

12/31/1985

4202532501

HENRY BUES GAS UNIT

2

BB-SOUTHTEX, LLC

70

28.599863

-98.009994

PRODUCING

13896

13504-15637

11/15/1988

4202532638

ONEAL GAS UNIT

3

BB-SOUTHTEX, LLC

70

28.604583

-98.007079

PRODUCING

13834

13508-13668

3/12/1992

4202532842

OVERBY, CHARLIE C.

1E

PIONEER NATURAL RES. USA, INC.

70

28.5998760

-98.0053330

P &A

14000

13514-13838

10/9/1995

4202532967

TOMASEK GAS UNIT

5

BB-SOUTHTEX, LLC

126

28.609862

-97.991519

PRODUCING

13875

13434-15693

6/12/1999

4202533006

ONEAL GAS UNIT

5

BB-SOUTHTEX, LLC

70

28.6067950

-98.0042210

PRODUCING

13772

13463-13764

7/15/2000

4202533035

ONEAL GAS UNIT

6

BB-SOUTHTEX, LLC

127

28.61091

-97.999073

PRODUCING

13835

13310-13833

9/14/2000

4202533085

ONEAL GAS UNIT

7

BB-SOUTHTEX, LLC

127

28.609397

-98.001471

PRODUCING

13868

13314-16072

5/4/2001

4202533114

HENRY BUES GAS UNIT

8

BB-SOUTHTEX, LLC

70

28.5984810

-98.0090260

PRODUCING

13732

13348-13732

6/11/2001

4202533197

ONEAL GAS UNIT

8

BB-SOUTHTEX, LLC

452

28.6075430

-98.0037990

PRODUCING

15638

13565-13820

2/5/2003

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

~

LONQUIST

SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

4202533272

HENRY BUES GAS UNIT

11

BB-SOUTHTEX, LLC

70

28.598737

-98.008615

PRODUCING

13856

13291-15853

6/23/2004

4202533273

ONEAL GAS UNIT

9

BB-SOUTHTEX, LLC

452

28.6029540

-98.0025090

PRODUCING

13872

13311-16585

6/3/2004

4202533328

ONEAL GAS UNIT

11

BB-SOUTHTEX, LLC

126

28.6036340

-97.9982100

PRODUCING

13787

13318-15928

4/19/2005

4202533345

TOMASEK GAS UNIT

8

BB-SOUTHTEX, LLC

126

28.608282

-97.991595

PRODUCING

13692

13293-16378

8/14/2004

4202533371

ONEAL GAS UNIT

12

BB-SOUTHTEX, LLC

452

28.6097460

-98.0027040

PRODUCING

13819

13313-16635

8/15/2006

4202533383

HENRY BUES GAS UNIT

15

BB-SOUTHTEX, LLC

70

28.600322

-98.00874

PRODUCING

13811

13302-15768

10/8/2006

4202533492

ONEAL GAS UNIT

13

BB-SOUTHTEX, LLC

70

28.605326

-98.012928

PRODUCING

13859

13382-14761

7/7/2007

4202533553

ONEAL GAS UNIT

14

BB-SOUTHTEX, LLC

127

28.613869

-98.000504

PRODUCING

13674

13450-15424

2/11/2008

4202533559

OVERBY GAS UNIT

2E

BB-SOUTHTEX, LLC

452

28.6011410

-98.0028580

PRODUCING

13734

13372-13734

3/23/2008

42025E2114

NO RECORD

NR

NO RECORD

126

28.608457

-97.995683

NO RECORD

NR

NO RECORD

NR

*Note: Well entries in red penetrate the upper confining layer.

O'Neal Gas Unit No. 4
Area of Review: Oil and Gas Well Penetration List
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------
O'Neal Gas Unit No. 4

APPENDIX B-2

Area of Review: Freshwater Wells List

WELL REPORT/ID NO.

OWNER'S NAME

OWNER ADDRESS

CITY/STATE/ZIP

LAT. WGS 84

LONG. WGS 84

WELL USE

WATER LEVEL (FT.)

TOTAL DEPTH (FT.)

DATE DRILLED

128936

JOHN DAVIDSON

12761 FM 673

KENEDY, TX 78119

28.606667

-98.011667

DOMESTIC

48

114

11/19/2007

7832308

HENRY BUES

NO RECORD

NO RECORD

28.598334

-98.012223

STOCK

-

150

1960

7925105

T. M. PLUMER

NO RECORD

NO RECORD

28.595556

-97.997778

STOCK

77

275

1931

7832309

W. A. MUELLER

NO RECORD

NO RECORD

28.608612

-98.005834

UNUSED

63

90

1925

7925106

R.C. HUNT ESTATE

NO RECORD

NO RECORD

28.593889

-97.997222

UNUSED

137

172

1925

~

O'Neal Gas Unit No. 4
Area of Review: Freshwater Wells List - Texas Water Development Board
Texas Registration No. F-8952

ifH LONQUIST

l\| SEQUESTRATION LLC

-------