Technical Review of Subpart RR MRV Plan for
30-30 Gas Plant
November 2022
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For assistance in accessing this document, please contact ghgreporting@epa.gov.
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
OFFICE OF
AIR AND RADIATION
November 4, 2022
Mr. Joshua Roberts
Stakeholder Midstream, LLC
401 E Sonterra Boulevard
Suite 215
San Antonio, Texas 78258
Re: Monitoring, Reporting and Verification (MRV) Plan for 30-30 Gas Plant
Dear Mr. Roberts:
The United States Environmental Protection Agency (EPA) has reviewed the
Monitoring, Reporting and Verification (MRV) Plan submitted for 30-30 Gas Plant, as required
by 40 CFR Part 98, Subpart RR of the Greenhouse Gas Reporting Program. The EPA is
approving the MRV Plan submitted by 30-30 Gas Plant on September 13, 2022, as the final
MRV plan. The MRV Plan Approval Number is 1013701-1. This decision is effective
November 9, 2022 and is appealable to the EPA's Environmental Appeals Board under 40 CFR
Part 78.
If you have any questions regarding this determination, please contact me or Melinda
Miller of the Greenhouse Gas Reporting Branch at miller.melinda@epa.gov.
Sincerely,
Julius Banks, Chief
Greenhouse Gas Reporting Branch
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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 12
6 Summary of Findings 15
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 the Stakeholder Gas Services, LLC (Stakeholder) 30-30 Gas Plant (30-30) for its
treated acid gas (TAG) injection project into the Wristen Group in Yoakum County, Texas approximately
seven miles northwest of the town of Plains. Note that this evaluation pertains only to the Subpart RR
MRV plan, and does not in any way replace, remove, or affect Underground Injection Control (UIC)
permitting obligations.
1 Overview of Project
30-30 states in the introduction of the MRV plan that it currently has a Class II permit for acid gas
injection (AGI), issued by the Texas Railroad Commission (TRRC) in November 2018 under the state's
Underground Injection Control (UIC) program for the Rattlesnake AGI #1 well, API No. 42- 501-36998,
UIC #000117143. This permit was originally issued to Santa Fe Midstream Permian, LLC in 2018, but the
asset was subsequently acquired by Stakeholder in December of 2020. This permit currently authorizes
30-30 to inject up to 4,500 barrels per day (or around 25,266 standard cubic feet per day (scf/d)) of TAG
into the Devonian formation at a depth of 11,000 to 12,000 feet with a maximum allowable surface
pressure of 2,200 pounds per square inch (psi). 30-30 claims that since being permitted, injection has
proceeded without incident. The Rattlesnake AGI #1 well is located in a rural, sparsely populated area of
Yoakum County, Texas, approximately seven miles northwest of the town of Plains.
In addition to submitting this MRV plan to the EPA, 30-30 is also applying to the TRRC for an amendment
to the Rattlesnake AGI #1 well's Class II permit to increase its authorized injection volume and maximum
allowable surface injection pressure (MASIP). The MRV plan states that approval of the permit
amendment will allow 30-30 to increase its capacity, which removes H2S and C02 from natural gas
production using amine treating. Approval will also increase the injection well capacity for a future gas
processing facility which is currently under development by Stakeholder. Additionally, expanded
capacity allows 30-30 to potentially provide future disposal in its AGI well for TAG from similar third-
party gas processing facilities. The MRV plan states that increased disposal capacity will allow for greater
gas processing capacity in the region, ultimately helping to reduce flaring and its associated emissions.
Throughout the MRV plan, both in written reference and in modeling inputs, 30-30 has used the
applied-for expanded permit capacity of 16 million standard cubic feet per day (MMSCF/d). 30-30 plans
to inject C02 for approximately 14 more years (17 years in total from the start of injection in 2019).
30-30 states in the MRV plan that the Rattlesnake AGI #1 well is designed in such a way to protect
against migration of C02 out of the injection interval and to prevent surface releases. The injection
interval for Rattlesnake AGI #1 is located over 4,720 feet below the primary producing formation, the San
Andres, and 8,593 feet below the base of the lowest useable quality water table, as shown in Figure 2 of
the MRV plan. As stated in section 2 of the MRV plan, this well will inject a C02 stream that contains
9.20% H2S, 89.68% C02, and 1.12% other gases. For these reasons, the MRV plan states that the well and
the facility are designed to minimize any leakage to the surface.
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In Section 2 of the MRV plan, 30-30 describes the geologic setting, planned injection volumes and
process, and the reservoir modeling performed for the Rattlesnake AGI #1. The target injection
formation is the Wristen Group. This formation was deposited in a basin platform setting across the
northern half of the Permian Basin. The MRV plan refers to this sequence as Devonian, Silurian-
Devonian, or Siluro-Devonian in age. The Silurian-age lithology on the inner platform is dominated by
grain-rich skeletal carbonates. The MRV plan states that the thickness of the Silurian-age rock is
approximately 1,000 feet thick at the Rattlesnake AGI #1 well location. Carbonate buildups are common
within the shallow inner platform, mainly skeletal wackestone, indicating a lower-energy deposition on
the inner platform. The Wristen Group is composed of three formations: Fasken, Frame, and Wink. The
Frame and Wink Formations are found near the ramp boundary to the south, while the Fasken
formation is found predominantly in the inner platform, where the Rattlesnake AGI #1 well is located.
The Fasken Formation is predominately dolomite grading to limestone, occurring as cycles, down
section. Figure 4 in the MRV plan shows a generalized stratigraphic column of the area underlying the
Rattlesnake AGI #1 well.
The MRV plan states that the upper confining interval is the Woodford Shale. The Woodford Shale is a
late Devonian-age organic-rich shale deposited as a result of a widespread marine transgression. The
flooding event occurred over most of the Permian basin, which produced a low relief, blanket-like shale
deposit of the Woodford. Two major lithofacies found within the Woodford are black shale and
siltstone. Nutrient-rich surface waters promoted the decay of abundant organic matter within the
Woodford, resulting in a high total organic carbon (TOC) percentage.
The MRV plan states that the low-permeability Montoya Formation is a tight limestone/dolomite that
will act as the lower confining unit for the injection interval. The MRV plan states that the porosity in the
lower section can range from 2-3% with permeabilities below 1 millidarcy (md). The Rattlesnake AGI #1
well drilled six feet into the Montoya formation, but the section was not logged. The MRV plan states
that the Montoya Formation is anticipated to be roughly 250 feet thick. The MRV plan states that these
petrophysical characteristics represent ideal sealing properties to prohibit any migration of injected fluid
outside of the injection interval.
The description of the project is determined to be acceptable and 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 the
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 the active
monitoring area as "the area that will be monitored over a specific time interval from the first year of
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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.
30-30 has indicated in the MRV plan that the initial AMA will cover a 14-year monitoring period, which is
equal to the expected time of future injection. The MRV plan states that the AMA itself will be
established based on the half-mile buffer around the anticipated plume location at the end of injection
in 2036. The area of projected free-phase C02 plume after five additional years (t + 5) was also reviewed,
but the boundaries of the plume at t + 5 were inside the plume boundary in 2016 plus the Vz mile buffer.
Therefore, the MRV plan delineates the AMA as the plume at the end of injection plus the Vz mile buffer.
The AMA is shown in Figure 27. 30-30 states that it may submit a revised MRV plan on or before 2036 to
amend the AMA if necessary.
The plume boundary was defined by the weighted average gas saturation in the aquifer. A value of 3%
gas saturation of C02 was used to determine the boundary of the plume. When injection ceases in year
2036, the MRV plan states that the areal expanse of the plume will be 1,052 acres. The maximum
distance between the wellbore and the edge of the plume is expected to be approximately 0.87 miles to
the southeast. After 743 additional years of density drift, the areal extent of the plume is predicted by
30-30 to be 2,177 acres with a maximum distance to the edge of the plume of approximately 1.35 miles
to the southeast. A map of the plume boundary can be seen in Figure 26 of the MRV plan.
The MMA is defined in the MRV plan 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, and is delineated in Figure 26. The MMA is consistent with Subpart RR requirements because the
defined MMA accounts for the expected free phase C02 plume, based on modeling results, and
incorporates the additional 0.5-mile or greater buffer area. The rationale used to delineate the MMA, as
described in 30-30's MRV plan, accounts for the existing operational and subsurface conditions at the
site, along with any potential changes in future operations. Therefore, the designation of the MMA is an
acceptable approach.
The delineations of the MMA and AMA were determined to be acceptable per the requirements in 40
CFR 98.448(a)(1). The MMA and AMA described in the MRV plan are clearly and explicitly delineated in
the plan and are consistent with the definitions in 40 CFR 98.449.
3 Identification of Potential Surface Leakage Pathways
As part of the MRV plan, the reporter must identify potential surface leakage pathways for C02 in the
MMA and the likelihood, magnitude, and timing of potential surface leakage of C02 through these
pathways pursuant to 40 CFR 98.448(a)(2). 30-30 identified the following as potential leakage pathways
in their MRV plan that required consideration:
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• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Leakage through the confining layer
• Leakage from Natural or Induced Seismicity
3.1 Leakage through Surface Equipment
The MRV plan states that 30-30 is designed for injecting acid gas containing H2S, and is therefore
designed and operated to minimize leakage points such as valves and flanges following industry
standards and best practices. The MRV plan states that H2S gas detectors are located around the facility
and the well site. These gas detectors trigger alarms at 10 parts per million (ppm) of H2S. Additionally, all
30-30 field personnel are required to wear H2S monitors which are triggered at 5 ppm of H2S. A shut-in
valve is located at the wellhead and is locally controlled by pressure, with a high pressure and low
pressure shut-off.
Additional safety features noted in this section of the MRV plan include Emergency Shutdown (ESD)
valves to isolate portions of the plant and pipeline; pressure relief valves along the pipeline to prevent
over pressurization; and flares to allow piping and equipment to be de-pressured rapidly.
The MRV plan states that with the level of monitoring at the 30-30 Facility and the Rattlesnake AGI #1
well, any release of H2S and C02 would be quickly identified, and the safety systems would quickly
minimize the volume of the release. It further states that the C02 injected into the Rattlesnake AGI #1 is
injected with H2S at a concentration of 10% (100,000 ppm). At this high level of H2S concentration,
even a small leakage would trigger personal and facility H2S monitors set to alarm at 5 ppm and 10 ppm
respectively.
Thus, the MRV plan provides an acceptable characterization of the C02 leakage that could be expected
through surface equipment.
3.2 Leakage from Existing Wells within MMA
Oil and Gas Operations within Monitoring Area
The MRV plan states that significant number of wells have historically been drilled within the area of the
Rattlesnake AGI #1 well. However, production has primarily been from the shallower San Andres
Formation in the Wasson Field. The San Andres Formation is separated from the Silurian-Devonian
interval by 4,720 feet in this area. The MRV plan states that a few wells have also been producing from
the Wolfcamp Formation. The Wolfcamp Formation is separated from the Siluro-Devonian interval by
1,800 feet. The MRV plan concludes that there are no penetrations of the injection interval within the
projected plume area of the Rattlesnake AGI #1 well.
The MRV plan also states that a review of the TRRC records for all the wells which penetrate the
injection interval within the MMA show that the wells were properly cased and cemented to prevent
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annular leakage of CChto the surface. The plugged wells are also adequately protected against migration
from the Devonian by the placement of the plugs within the wellbores. Additionally, the MRV plan states
that the Rattlesnake AGI #1 well was designed to prevent migration from the injection interval to the
surface through the casing and cement placed in the well, as shown in Figure 29 of the MRV plan. The
plan further states that Mechanical integrity tests ("MIT") required under TRRC rules are run annually to
verify the well and wellhead can hold the appropriate amount of pressure. If the MIT were to indicate a
leak, the well would be isolated and the leak mitigated quickly to prevent leakage to the atmosphere.
The MRV plan provides a map of all wells within the MMA in Figure 30. Figure 31 shows only those wells
which penetrate the injection interval within the MMA. The MMA review maps, a summary of all the
wells in the MMA and detailed wellbore schematics for those wells which penetrate the injection
interval are provided in Appendix F.
Future Drilling
The MRV plan states that potential leakage pathways caused by future drilling in the area are not
expected to occur, in particular noting that the deeper formations, such as the Devonian, have proven
to-date to be less productive or non-productive in this area, which is why the location was selected for
injection. Furthermore, the MRV plan states that any drilling permits issued by the TRRC in the area of
the Rattlesnake AGI #1 well include a list of formations for which oil and gas operators are required to
comply with TRRC Rule 13 (entitled "Casing, Cementing, Drilling, Well Control, and Completion
Requirements"), 16 TAC § 3.13. As stated in the MRV plan, TRRC Rule 13 requires oil and gas operators
to set steel casing and cement across and above all formations permitted for injection under TRRC Rule
9 or immediately above all formations permitted for injection under Rule 46 for any well proposed
within a one-quarter mile radius of an injection well. Additionally, Rule 13 requires operators to case
and cement across and above all potential flow zones and/or zones with corrosive formation fluids. The
MRV plan states that if any leakage were to be detected, the volume of C02 released will be quantified
based on the operating conditions at the time of release.
Groundwater Wells
The MRV plan states that there are seven groundwater wells located within the MMA, as identified by
the Texas Water Development Board. All the identified groundwater wells in the area have total depths
less than or equal to 265 feet, as shown in Figure 32 and Table 9 of the MRV plan. One of the wells is
located on the 30-30 facility property with a total depth of 119 feet and is operated by Stakeholder.
The surface and intermediate casings of the Rattlesnake AGI #1 well, as shown in Figure 29 of the MRV
plan, are designed to protect the shallow freshwater aquifers consistent with applicable TRRC
regulations and the GAU letter issued for this location. See GAU letter included within Appendix B of the
MRV plan. The wellbore casings and cements also serve to prevent C02 leakage to the surface along the
borehole.
Thus, the MRV plan provides an acceptable characterization of the C02 leakage that could be expected
through existing and future oil, gas, and groundwater wells.
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3.3 Leakage Through Faults and Fractures
The MRV plan states that faults were interpreted from roughly 9 square miles of 3D seismic indicated by
the purple outline in Figure 12 of the MRV plan. This interpreting revealed that faulting in this region
terminates vertically below the Pennsylvanian-age rock. Secondary confining shales within the
Wolfcampian and younger strata provide additional, redundant confining layers that would prevent C02
from migrating into freshwater aquifers. None of the mapped faults project above the Wolfcamp
formation; rather, they appear to terminate between the Strawn and the base of the Wolfcamp. The
MRV plan states that in the unlikely event the faults' sealing properties are compromised post-injection,
secondary confinement is provided by the tight limestones found within the overlying Mississippian
Lime formation and the shale layers found in the Atoka and Wolfcamp formations.
As seen in Figure 14 of the MRV plan, the largest fault found southeast (SE) of the Rattlesnake AGI #1
well terminates within the Atoka formation. Though it crosses the Silurian section, this fault thrusts the
Mississippian Lime upward against the Atoka shales. The tight reservoir characteristics of the
Mississippian Lime and shaley section of the Atoka create a confining environment vertically and
laterally to contain potential upward migration of buoyant fluids. Shales within the Wolfcamp formation
provide additional confining beds between overlying USDWs and the fault plane.
The MRV plan states that pressures will be kept significantly below the fracture gradient of the injection
and confining intervals. Therefore, 30-30 states that upward migration of injected gas through confining
bed fractures is unlikely.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through faults or fractures.
3.4 Leakage through the Confining Layer
The MRV plan states that the Silurian-Devonian injection zones have competent sealing rocks above and
below the porous sub-aerially exposed carbonate. The MRV plan states that the properties of the
overlying transgressive Woodford shale (widespread deposition, high illite clay and organic matter
composition, and low porosity and permeability) make an excellent sealing rock to the underlying
Silurian formation. Furthermore, tight Mississippian Lime of roughly 660 feet lay between Atoka and
Woodford shale formations, forming an impermeable upper seal to the injection interval. Above this
confining unit, correlative shales of the Wolfcamp, Abo and Tubb formations will prevent any upper fluid
migration. The MRV plan states that these impermeable shales are capped by hundreds of feet of the
regionally present Salado formation evaporites. The USDW lies above the sealing properties of the
formations outlined above, making stratigraphic migration of fluids into the USDW highly unlikely. The
MRV plan states that the low porosity and permeability of the underlying Montoya carbonate minimizes
the likelihood of downward migration of injected fluids. It also states that the relative buoyancy of
injected gas to the in-situ reservoir fluid makes migration below the lower confining layer unlikely.
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Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through confining layers.
3.5 Leakage From Natural or Induced Seismicity
The MRV plan states that the location of Rattlesnake AGI #1 is in an area of the Permian Basin that is
inactive from a seismicity perspective, whether induced or natural. A review of historical seismic events
on the USGS's Advanced National Seismic System site (from 1971 to present) and the Bureau of
Economic Geology's TexNet catalog (from 2017 to present), as shown in Figure 33 of the MRV plan,
indicates the nearest seismic event occurred more than 60 miles away.
The MRV plan states that a regional analysis of the probabilistic fault slip potential across the Permian
Basin (Snee & Zoback 2016) further demonstrates that the Rattlesnake AGI #1 well is located in a
seismically inactive area and confirms that this area has little to no potential for an induced seismicity
event. Therefore, 30-30 states that there is no indication that seismic activity poses a risk for loss of C02
to the surface within the MMA.
Furthermore, the MRV plan states that pressures will be kept significantly below the fracture gradient of
the injection and confining intervals. This lowers the risk of induced seismicity. Additionally, continuous
well monitoring combined with seismic monitoring will identify any operational anomalies associated
with a seismicity event.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through natural or induced seismicity.
4 Strategy for Detection and Quantifying Surface Leakage of CO2
and for Establishing Expected Baselines for Monitoring
40 CFR 98.448(a)(3) requires that an MRV plan contain a strategy for detecting and quantifying any
surface leakage of C02, and 40 CFR 98.448(a)(4) requires that an MRV plan include a strategy for
establishing the expected baselines for monitoring C02 surface leakage. Section 5 of the MRV plan
details 30-30's strategy for monitoring and quantifying potential C02 leakage, and section 6 of the MRV
plan details strategies for establishing baselines for evaluating potential C02 leakage. The MRV plan
explains that as the C02 stream injected at the 30-30 facility contains both H2S and C02, fixed and
personal H2S monitors will be 30-30's primary method for monitoring C02 leakage. The H2S will serve as
a proxy for C02. Additional approaches for detecting and quantifying surface leakage of C02 primarily
include visual inspections, well mechanical integrity tests (MITs), groundwater sampling, continuous
monitoring, and seismic monitoring. Monitoring will occur during the planned 17-year injection period,
or until cessation of injection operations, plus a proposed 5-year post-injection period. Table 10 of the
MRV plan, which has been reproduced below, provides a summary of potential leakage pathway(s) and
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their respective monitoring methods.
Leakage Pathway
Monitoring Method
Leakage from surface equipment
Fixed H2S monitors throughout the AGI facility
Daily visual inspections
Personal H2S monitors
Distributed Control System Monitoring (Volumes and Pressures)
Leakage through existing wells
Fixed H2S monitor at the AGI well
SCADA Continuous Monitoring at the AGI Well
Annual Mechanical Integrity Tests ("MIT") of the AGI Well
Visual Inspections
Quarterly C02 Measurements within AMA
Leakage through groundwater wells
Annual Groundwater Samples on Property
Leakage from future wells
H2S Monitoring during offset drilling operations
Leakage through faults and fractures
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage through confining layer
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage from natural or induced
seismicity
Seismic monitoring station to be installed
SCADA - Supervisory control and data acquisition
4.1 Detection of Leakage through Surface Equipment
As described in section 5 of the MRV plan, the M2S in the injectate serves as a proxy for the release of
C02. The MRV plan states that the 30-30 Facility and the Rattlesnake AGI #1 well are designed to handle
H2S through a facility design that minimizes leak points and corrosion points. Therefore, the MRV plan
states that C02 leakage from surface equipment is unlikely to occur and would be quickly detected and
addressed if it does occur. 30-30 and the Rattlesnake AGI #1 well site contain numerous H2S alarms, set
with a high alarm setpoint of 10 ppm of H2S. Additionally, all 30-30 field personnel are required to wear
H2S monitors, which trigger the alarm at 5 ppm H2S.
The MRV plan also states that 30-30 is continuously monitored through automated systems. Field
personnel also conduct daily visual field inspections of gauges, monitors and leak indicators such as
vapor plumes. The plan explains that the effectiveness of the internal and external corrosion control
program is monitored through the periodic inspection of the system, analysis of liquids collected from
the system, and inspection of the cathodic protection system. The MRV plan states that these
inspections, in addition to the automated systems, will allow 30-30 to quickly respond to any leakage
situation. Monitoring will occur for the duration of injection and the post-injection period. Should
leakage be detected, 30-30 will calculate the volume of C02 released based on operating conditions at
the time of the event, per 40 CFR §98.448(a)(5). The MRV plan states that the mass of any C02 released
through surface leakage would be calculated for the operating conditions at the time, including
pressure, flow rate, size of the leak point opening, and duration of the leak.
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Thus, the MRV plan provides adequate characterization of 30-30's approach to detect potential leakage
through surface equipment as required by 40 CFR 98.448(a)(3).
4.2 Detection of Leakage from Wells within the Monitoring Area
As described in section 5 of the MRV plan, 30-30 continuously monitors and collects injection volumes,
pressures, temperatures and gas composition data, through their SCADA systems, for the Rattlesnake
AGI #1 well. Rattlesnake AGI #1 has a pressure and temperature gauge placed in the injection stream at
its wellhead, and a pressure gauge on the casing annulus. The MRV plan states that a change to the
pressure on the annulus would indicate the presence of a possible leak. The MRV plan states that these
data are reviewed by qualified personnel and will follow response and reporting procedures when data
are outside acceptable performance limits. Furthermore, MITs performed annually would also indicate
the presence of a leak. Upon a negative MIT, the well would immediately be isolated and the leak
mitigated.
The MRV plan states that the ten offset penetrating wells within the MMA are adequately cased and
cemented to prevent potential leakage of CChfrom the Rattlesnake AGI #1 well plume. Additionally, the
plan states that the plugging of these wells was executed in a way to prevent migration. Details on these
procedures are provided in Appendix E of the MRV plan. As discussed in the MRV plan, TRRC Rule 13
would ensure that new wells in the field would be constructed in a manner to prevent migration from
the injection interval.
In addition to the fixed and personal monitors described previously, 30-30 will also establish and
operate an in-field monitoring program to detect any CO2 leakage within the AMA. This will include H2S
and CO2 monitoring at the AGI well site as well at a minimum, quarterly atmospheric monitoring near
identified penetrations within the AMA. Upon approval of the MRV and through the post-injection
monitoring period, 30-30 will have these monitoring systems in place. Additional monitoring will be
added as the AMA is updated over time.
The MRV plan states that, at the well site, H2S and CO2 concentrations will be monitored continuously
with fixed monitors that detect atmospheric concentrations of H2S and CO2. At penetrating well sites,
30-30 will similarly measure atmospheric concentrations of CO2 and H2S using mobile gas monitors. This
data will be recorded at least quarterly.
According to the MRV plan, 30-30 will also monitor the groundwater quality in fluids above the confining
interval by sampling the well on the facility property and analyzing the sample with a third-party
laboratory on an annual basis. Any significant changes to the water analysis would be investigated to
determine if such change was a result of leakage from the Rattlesnake AGI #1 well. The parameters to
be measured will include pH, total dissolved solids, total inorganic and organic carbons, density,
temperature and other standard laboratory measurements. Any significant differences in these
parameters from the baseline sample will be evaluated to determine if leakage of CChto the USDW may
have occurred.
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Thus, the MRV plan provides adequate characterization of 30-30's approach to detect potential leakage
through existing and future wells as required by 40 CFR 98.448(a)(3).
4.3 Detection of Leakage Through Faults or Fractures
As described in section 5 of the MRV plan, 30-30 continuously monitors the operations of the
Rattlesnake AGI #1 well through automated systems. The MRV plan states that any deviation from
normal operating conditions indicating movement into a potential pathway such as a fault or
breakthrough of the confining seal would trigger an alert. Any such alert would be reviewed by field
personnel and action taken to shut in the well, if necessary. Field H2S monitoring systems would alert
field personnel for any release of H2S/CO2 caused by such leakage.
Thus, the MRV plan provides adequate characterization of 30-30's approach to detect potential leakage
through faults and fractures as required by 40 CFR 98.448(a)(3).
4.4 Detection of Leakage through Confining Layers
As described in section 5 of the MRV plan, 30-30 plans to use SCADA continuous monitoring at the
Rattlesnake AGI #1 well in order to keep track of gas volumes and pressures that might be lost due to
leakage through the confining seal. Furthermore, the MRV plan states that fixed H2S monitors will be
used to detect and monitor potential leakage through the confining seal. Any deviation from normal
operating conditions indicating a breakthrough of the confining seal would trigger an alert. Any such
alert would be reviewed by field personnel and action taken to shut in the well, if necessary. Field H2S
monitoring systems would alert field personnel for any release of H2S/CO2 caused by such leakage.
Thus, the MRV plan provides adequate characterization of 30-30's approach to detect potential leakage
through the confining layers as required by 40 CFR 98.448(a)(3).
4.5 Detection of Leakage from Natural or Induced Seismicity
As described in section 5 of the MRV plan, 30-30 plans to install a seismic monitoring station in the
general area of the Rattlesnake AGI #1 well. The installation of this station would start upon approval of
the MRV plan, with an expected in-service date within six months after the commencement of the
installation project. This monitoring station will be tied into the Bureau of Economic Geology's TexNet
Seismic Monitoring Dystem. If a seismic event of 3.0 magnitude or greater is detected, 30-30 will review
the injection volumes and pressures at the Rattlesnake AGI #1 well to determine if any significant
changes occurred that would indicate potential leakage. Additionally, continuous well monitoring
combined with seismic monitoring will identify any operational anomalies associated with a seismicity
event.
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Thus, the MRV plan provides adequate characterization of 30-30's approach to detect potential leakage
through natural or induced seismicity as required by 40 CFR 98.448(a)(3).
4.6 Determination of Baselines and Quantification of Potential CO2 Leakage
Section 6 of the MRV plan outlines 30-30's methodology for determining expected baselines for
monitoring C02 surface leakage. 30-30 will use the existing SCADA monitoring systems to identify
changes from expected performance that may indicate leakage of CO2. The MRV plan states that the
mass of any C02 released would be calculated for the operating conditions at the time, including
pressure, flow rate, size of the leak point opening, and duration of the leak.
Visual Inspections
The MRV plan states that daily inspections will be conducted by field personnel at the 30-30 facility and
the Rattlesnake AGI #1 well. These inspections will aid with identifying and addressing issues timely to
minimize the possibility of leakage. If any issues are identified, such as vapor clouds or ice formations,
corrective actions would be taken to address such issues.
H2S Detection
The MRV plan implies that known H2S concentrations of the injectate will be used to determine
expected leakage relative to established baselines. As stated in the MRV plan, H2S will be initially
injected into the AGI well at a concentration of approximately ten (10) percent or 100,000 ppm. The
concentration will drop to approximately seven percent as additional volumes are added. H2S gas
detectors are located throughout the AGI facility and well site and are set to trigger the alarm at 10
ppm. Additionally, all field personnel are required to wear personal H2S monitors, which are set to
trigger the alarm at 5 ppm. Any alarm would trigger an immediate response to protect personnel and
verify that the monitors are working properly.
C02 Detection
The MRV plan states that any CO2 release would be accompanied by H2S, therefore, the H2S monitors at
the facility would also serve as a CO2 release warning system. In addition to the fixed and personal
monitors described previously, 30-30 states that it will also establish and operate an in-field monitoring
program to detect any CO2 leakage within the AMA and MMA. This will include H2S and CO2 monitoring
at the AGI well site as well as atmospheric monitoring near identified penetrations within the AMA.
Operational Data
The MRV plan explains that upon starting injection operations, baseline measurements of injection
volumes and pressures will be taken. Any significant deviations over time will be analyzed for indication
of potential leakage of CO2.
Continuous Monitoring
11
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The MRV plan states that the mass of C02 emitted by surface leakage and equipment leaks will not be
measured directly as the injection stream for this well contains H2S which would be extremely
dangerous for personnel to perform a direct leak survey. Any leakage would be detected and managed
as per Texas regulations and 30-30's TRRC approved H2S Contingency Plan. Gas detectors and
continuous monitoring systems would trigger an alarm upon a release. The mass of the CO2 released
would be calculated for the operating conditions at the time, including pressure, flow rate, size of the
leak point opening, and duration of the leak. 30-30 notes that 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. The MRV plan states that no C02 emissions should occur from venting because of the high H2S
concentrations. Blowdown emissions are sent to flares and would be reported as part of the required
reporting for the gas plant.
Groundwater Monitoring
The MRV plan states that an initial groundwater sample will be taken from the groundwater well on SO-
SO property and analyzed by a third-party laboratory upon the MRV plan's approval to establish the
baseline properties of the groundwater.
Given the methodologies listed above, 30-30 provides an acceptable approach for establishing C02
leakage monitoring baselines in accordance with 40 CFR 98.448(a)(4).
5 Considerations Used to Calculate Site-Specific Variables for the
Mass Balance Equation
5.1 Calculation of Mass of CO2 Received
According to the MRV plan, the C02 received for this injection well will be wholly injected and not mixed
with any other supplies of C02, thus the annual mass of C02 injected will equal the quantity of C02
received at the receiving flow meter. Therefore, in accordance with 40 CFR §98.444(a)(4), 30-30 will use
the mass of C02 injected as the mass of C02 received instead of using Equation RR-1 or RR-2.
30-30's approach to calculating the mass of C02 received is acceptable for the Subpart RR requirements.
5.2 Calculation of Mass of CO2 Injected
Section 7 of the MRV plan states that the mass of C02 injected will be calculated using Equation RR-5 in
accordance with 40 CFR §98.444(b). The flow rate 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 volumetric
flow at standard conditions by the C02 concentration in the flow and the density of C02 at standard
conditions, as follows:
12
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4
C02,u = ^ Qp,u *D * cco2pM
P = 1
Where:
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
QP,u = Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons per
quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682
Cco2,P,u = Quarterly C02 concentration measurement in flow for flow meter u in quarter p (wt.
percent C02, expressed as a decimal fraction).
p = Quarter of the year
u = Flow meter.
30-30 provides an acceptable approach to calculating the mass of C02 injected in accordance Subpart RR
requirements.
5.3 Mass of CO2 Produced
The MRV plan states that the Rattlesnake AGI #1 well is not part of an enhanced oil recovery project,
thus 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 as the injection stream for this well contains H2S which would be extremely
dangerous for personnel to perform a direct leak survey. Any leakage would be detected and managed
as a major upset event. Gas detectors and continuous monitoring systems would trigger an alarm upon
a release. The mass of the C02 released would be calculated for the operating conditions at the time,
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.
13
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In the unlikely event that C02 was released as a result of surface leakage, 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 follows:
X
C02e — ^ C02,x
X—l
Where:
C02 = 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
The MRV plan states that calculation methods from Subpart W will be used to calculate C02 emissions
from equipment located on the surface between the flow meter used to measure injection quantity and
the injection wellhead.
30-30 provides an acceptable approach for calculating the mass of C02 emitted by surface leakage under
the Subpart RR requirements.
5.5 Calculation of Mass of CO2 Sequestered
The MRV plan states that the mass of C02 sequestered in subsurface geologic formations will be
calculated based off Equation RR-12, 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
14
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C02F| = 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 plan further states that C02Fi will be calculated in accordance with Subpart W reporting of GHGs.
Because no venting would occur due to the high H2S concentrations of the injectate stream, the
calculations would be based on the blowdown emissions that would be sent to flares and would be
reported as part of the required GHG reporting for the gas plant.
The plan also states that calculation methods from Subpart W will be used to calculate C02 emissions
from equipment located on the surface between the flow meter used to measure injection quantity and
the injection wellhead.
30-30 provides an acceptable approach for calculating the mass of C02 sequestered under Subpart RR.
Overall, 30-30 provides an acceptable approach for the considerations used to calculate site-specific
variables for the mass balance equation as required by 98.448(a)(5).
6 Summary of Findings
The Subpart RR MRV plan for the 30-30 Facility meets the requirements of 40 CFR 98.448. The
regulatory provisions of 40 CFR 98.448, 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
30-30 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. 30-30 used CMG's GEM numerical simulation
software to determine the areal extent and density
drift of the C02 plume. Numerical simulation was also
used by 30-30 to predict the size and drift of the C02
plume. The MMA is defined as equal to or greater than
the area expected to contain the free-phase C02 plume
until the C02 plume has stabilized plus an all-around
buffer zone of at least one-half mile. The AMA is based
on the superimposition of a one-half mile buffer
around the anticipated plume location at the end of
injection in 2036 and the area of projected free-phase
C02 plume after 5 additional years.
15
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40 CFR 98.448(a)(2): Identification of
potential surface leakage pathways for C02
in the MMA and the likelihood, magnitude,
and timing, of surface leakage of C02
through these pathways.
Section 4 of the MRV plan identifies and evaluates
potential surface leakage pathways. The MRV plan
identifies the following potential pathways: leakage
from surface equipment, leakage through existing wells
within the MMA, leakage through faults and fractures,
leakage through natural or induced seismicity, leakage
from drilling through the MMA, and leakage through
the confining layer. The MRV plan analyzes the
likelihood, magnitude, and timing of potential surface
leakage through these pathways.
40 CFR 98.448(a)(3): A strategy for
detecting and quantifying any surface
leakage of C02.
Section 5 of the MRV plan describes strategies for how
the facility would detect C02 leakage to the surface,
such as H2S monitors, visual inspections, and SCADA
continuous monitoring of the Rattlesnake AGI #1 well.
Section 4 of the MRV plan describes a strategy for how
potential surface leakage would be quantified.
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.
30-30 will use visual inspections, H2S detection, C02
detection, operational data, continuous monitoring,
and groundwater monitoring to establish baselines for
monitoring potential C02 surface leakage.
40 CFR 98.448(a)(5): A summary of the
considerations you intend to use to
calculate site-specific variables for the mass
balance equation.
Section 7 of the MRV plan describes 30-30's approach
to determining the amount of C02 sequestered using
the Subpart RR mass balance equation, including as
related to calculation of total annual mass emitted
from equipment leakage.
40 CFR 98.448(a)(6): For each injection
well, report the well identification number
used for the UIC permit (or the permit
application) and the UIC permit class.
Section 1 of the MRV plan provides well identification
number for the Rattlesnake AGI #1 well. The MRV plan
specifies that the Rattlesnake AGI #1 well has been
issued 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 30-30 facility
baseline measurements of injection volumes and
pressures will be taken upon implementation of this
MRV plan. 30-30 will implement the MRV plan upon
receiving EPA approval.
16
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Appendix A: Final MRV Plan
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STAKEHOLDER
I!MIDSTREAM
Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
Rattlesnake AGI #1
Yoakum County, Texas
Prepared for Stakeholder Gas Services, LLC
San Antonio, TX
By
Lonquist Sequestration, LLC
Austin, TX
Version 3
September 2022
LONQUIST
SEQUESTRATION LLC
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INTRODUCTION
Stakeholder Gas Services, LLC ("Stakeholder") currently has a Class II acid gas injection ("AGI") permit, issued
by the Texas Railroad Commission ("TRRC") in November 2018, for the Rattlesnake AGI #1 well, API No. 42-
501-36998. This permit was originally issued to Santa Fe Midstream Permian, LLC, in 2018 and the asset was
subsequently acquired by Stakeholder in December of 2020. This permit currently authorizes Stakeholder to
inject up to 4,500 barrels per day ("bbls/d") of treated acid gas ("TAG") into the Devonian formation at a
depth of 11,000' to 12,000' with a maximum allowable surface pressure of 2,200 psi. Since being permitted,
injection has proceeded without incident. This AGI well is associated with Stakeholder's 30-30 gas treating
and processing plant ("30-30") located in a rural, sparsely populated area of Yoakum County, Texas,
approximately seven miles northwest of the town of Plains, as shown in Figure 1.
I t
H-
Ula
homa
STAKEHOLDER
MIDSTREAM
Mexlip
TT
:
1
t
L
Y
I
H
iti
l^vas
J L
riV
r\ fV
WES
T OIL F
IELD
Yoakum
ink Bas.n
Rattlesnake
AGI(RS#1)
¦
WASSON OIL
FIELD
° *
9
"S
W
i
|
Four Mi
| 1
Ji|—k s ¦/- 1 i
§
YbAKUM
GAINrS
^ Gaines
0 0.5 1 2 Miles
GEOROi
ALLEN
OIL
FIELD
# Stakeholder AGI Well
Figure 1 - Location of Rattlesnake AGI #3 Well
1
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Stakeholder 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, Stakeholder is also applying to the TRRC for an amendment to the
Rattlesnake AGI #1 well's Class II permit to increase its authorized injection volume and maximum allowable
surface injection pressure ("MASIP"). Approval of the permit amendment will allow Stakeholder to increase
the capacity of its existing 30-30 Facility, which removes H2S and C02 from natural gas production using amine
treating, as well as increase the injection well capacity for a future gas processing facility which is currently
under development by Stakeholder. Additionally, expanded capacity allows Stakeholder to potentially
provide future disposal in its AGI well for oil and gas waste derived TAG from similar third-party gas processing
facilities. Increased disposal capacity will allow for greater gas processing capacity in the region, ultimately
helping to reduce flaring and its associated emissions. Throughout this document, both in written reference
and in modeling inputs, Stakeholder has used the applied-for expanded permit capacity of 16 million standard
cubic feet per day ("MMSCF/d"). Stakeholder plans to inject C02 for approximately 14 more years.
2
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ACRONYMS AND ABBREVIATIONS
%
°c
°F
AMA
BCF
CH4
CMG
C02
E
EOS
EPA
ESD
FG
ft
GAU
GEM
GHGs
GHGRP
H2S
md
mi
MIT
MM
MMA
MCF
MMCF
MMSCF
Feet
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)
Groundwater Advisory Unit
Computer Modelling Group's GEM 2020.11
Greenhouse Gases
Greenhouse Gas Reporting Program
Hydrogen Sulfide
Millidarcy(ies)
Mile(s)
Mechanical Integrity Test
Million
Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet
-------
MSCF/D Thousand 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
4
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TABLE OF CONTENTS
INTRODUCTION 1
ACRONYMS AND ABBREVIATIONS 3
SECTION 1 - FACILITY INFORMATION 8
Reporter number 8
Underground Injection Control (UIC) Class II Permit 8
UIC Well Identification Number 8
SECTION 2- PROJECT DESCRIPTION 9
Regional Geology 10
Regional Faulting 15
Site Characterization 15
Stratigraphy and Lithologic Characteristics 15
Upper Confining Interval - Woodford Shale 16
Injection Interval - Fasken Formation 17
Lower Confining Zone - Fusselman Formation 21
Local Structure 21
Injection and Confinement Summary 26
Groundwater Hydrology 26
Description of the Injection Process 31
Current Operations 31
Planned Operations 32
Reservoir Characterization Modeling 32
Simulation Modeling 35
SECTION 3 - DELI NATION OF MONITORING AREA 39
Maximum Monitoring Area 39
Active Monitoring Area 40
SECTION 4- POTENTIAL PATHWAYS FOR LEAKAGE 42
Leakage from Surface Equipment 42
Leakage from Wells in the Monitoring Area 44
Oil and Gas Operations within Monitoring Area 44
Groundwater wells 48
Leakage Through Faults or Fractures 50
Leakage Through Confining Layers 51
Leakage from Natural or Induced Seismicity 51
SECTION 5 - MONITORING FOR LEAKAGE 54
Leakage from Surface Equipment 54
Leakage from Existing and Future Wells within Monitoring Area 55
Leakage through Faults, Fractures or Confining Seals 56
Leakage through Natural or Induced Seismicity 56
SECTION 6 - BASELINE DETERMINATIONS 57
Visual Inspections 57
H2S Detection 57
C02 Detection 57
Operational Data 57
Continuous Monitoring 57
Groundwater Monitoring 58
SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION 59
5
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Mass of C02 Received 59
Mass of C02 Injected 59
Mass of C02 Produced 60
Mass of C02 Emitted by Surface Leakage 60
Mass of C02 Sequestered 60
SECTION 8- IMPLEMENTATION SCHEDULE FOR MRV PLAN 62
SECTION 9 - QUALITY ASSURANCE 63
Monitoring QA/QC 63
Missing Data 63
MRV Plan Revisions 64
SECTION 10- RECORDS RETENTION 65
References 66
APPENDICES 67
LIST OF FIGURES
Figure 1 - Location of Rattlesnake AGI #1 well 1
Figure 2 - Illustrative overview of Rattlesnake AGI #1 and 30-30 Facility 9
Figure 3 - Regional Map of the Permian Basin 10
Figure 4 - Stratigraphic column of the Northwest Shelf 11
Figure 5 - Stratigraphic column depicting the composition of the Silurian group 12
Figure 6 - Thickness map of the Silurian system which composes the Fusselman and Wristen group 14
Figure 7 - Type Log (42-501-10238) with tops, confining and injection zones depicted 15
Figure 8 - Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994) 16
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays 18
Figure 10 - Rattlesnake AGI #1 open hole log (42-501-36998) 19
Figure 11 - Offset wells used for Formation Fluid Characterization 20
Figure 12 - Silurian Structure Map (subsea depths) 23
Figure 13 - Structural Northeast-Southwest Cross Section 24
Figure 14- Structural Northwest-Southeast Cross Section 25
Figure 15 - Northwest-Southeast Cross Section of aquifers in the Rattlesnake AGI #1 well area 27
Figure 16 - Potentiometric surfaces from wells completed in A Ogallala aquifer, B the Edwards-Trinity aquifer
and Cthe Dockum aquifer 28
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDB) 29
Figure 18 - Total dissolved solids in groundwater from the Dockum Aquifer 29
Figure 19 - Regional extent of the Edwards-Trinity freshwater aquifer 30
Figure 20 - Regional extent of the Ogallala freshwater aquifer 31
Figure 21 - 30-30 Facility Process Flow Diagram 32
Figure 22 - Permeability Distribution of Karst Limestone 34
Figure 23 - Areal View Gas Saturation Plume, 2036 (End of Injection) 37
Figure 24 - Areal View Gas Saturation Plume, 2779 (End of Density Drift) 38
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time 38
Figure 26 - Plume Boundary at End of Injection, Stabilized Plume, and Maximum Monitoring Area 40
Figure 27 - Active Monitoring Area 41
Figure 28 - Site Plan, 30-30 Facility 43
Figure 29 - Rattlesnake AGI #1 Wellbore Schematic 45
Figure 30 - Oil and Gas Wells within the MMA 46
6
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Figure 31 - Penetrating Oil and Gas Wells within the MMA 47
Figure 32 - Groundwater Wells within MMA 49
Figure 33 - Seismicity Review (TexNet - 06/01/2022) 52
Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI #1 location 53
LIST OF TABLES
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples 20
Table 2 - Fracture Gradient Assumptions 21
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and
Yoakum Counties, Texas 26
Table 4 - Gas Composition of 30-30 Facility outlet 31
Table 5 - Modeled Initial Gas Composition 33
Table 6 - CMG Model Layer Properties 34
Table 7 - All Offset SWDs included in the model 36
Table 8 - All Offset Producers included in the model 36
Table 9 - Groundwater Well Summary 50
Table 10 - Summary of Leakage Monitoring Methods 54
7
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SECTION 1 - FACILITY INFORMATION
This section contains key information regarding the Acid Gas and C02 injection facility.
Reporter number:
• Gas Plant Facility Name: 30-30 Gas Plant
• Greenhouse Gas Reporting Program ID: 574501
o Currently reporting under Subpart UU
• Operator: Stakeholder Gas Services, LLC
Underground Injection Control (UIC) 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 Rattlesnake AGI #1 well as a UIC Class II well. A Class II
permit was issued to Stakeholder under TRRC Rule 9 (entitled "Disposal into Non-Productive Formations")
and Rule 36 (entitled "Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas").
UIC Well Identification Number:
Rattlesnake AGI #1, API No. 42-501-36998, UIC #000117143.
8
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SECTION 2 - PROJECT DESCRIPTION
This Project Description discusses the geologic setting, planned injection volumes and process, and the
reservoir modeling performed for the Rattlesnake AGI #1 well. The Class II UIC permit was initially applied
for and received by Santa Fe Midstream Permian, LLC. The asset was acquired in 2020 by Stakeholder and
has been in operation since that time. Since the original application, Lonquist has revised and updated the
geology and the plume modeling within the reservoir in preparing this MRV Plan.
The Rattlesnake AGI #1 well is located and designed to protect against migration of C02 out of the injection
interval and to prevent surface releases. The injection interval for Rattlesnake AGI #1 is located over 4,720'
below the primary producing formation, the San Andres, in the area and 8,593' below the base of the lowest
useable quality water table, as shown in Figure 2. This well injects both H2S and C02, therefore the well and
the facility are designed to minimize any leakage to the surface.
STAKEHOLDER
TREATING & PROCESSING
PLANT
2,450'
LOWEST
WATER TABLE
DEPTH
5,500'
CASING DEPTH
Casing consists of
reinforced steel
and concrete
11,000'
INJECTION WELL
DEPTH
>8,500'
BELOW THE
WATER TABLE
Figure 2 - Illustrative overview of Rattlesnake AGI tt1 and 30-30 Facility
9
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Regional Geology
The Rattlesnake AGI #1 well is located on the southern portion of the Northwestern Shelf within the larger
Permian Basin as seen in Figure 3. The Northwestern Shelf is a broad marine shelf located in the northern
portion of the Permian Basin,
Basin
Matador Arch
Eastern
Shelf
f.. NEW MEXICO
Jtexas |
Delaware'^
Basin \
Ozona
, Arch
>Val Verde
' Basin
.Ouach/h
NJ
NEW
MEXICO
WO ml
100 Km
I I Permian Basin
Figure 3 - Regional Map of the Permian Basin. Red Star is approximate location of Rattlesnake AGI #1 well
Figure 4 depicts the stratigraphic column found at the Rattlesnake AGI #1 well location with red stars
referencing the injection formation and green stars indicating the productive intervals in the area. The
primary injection interval is found within the Wristen group, of Silurian-age, as seen in Figure 5. The TRRC
refers to this sequence under the general terms "Devonian", "Silurian-Devonian" or "Siluro-Devonian".
10
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Period
Epoch
Formation
General Lithology
Permian
Ochoan
Dewey Lake
Redbeds/Anhydrite
Rustler
Halite
Salado
Halite/Anhydrite
Guadalupian
Tansil
Anhydrite/Dolomite
Yates
Anhydrite/Dolomite
Seven Rivers
Dolomite/Anhydrite
Queen
Sandy Dolomite/Anhydrite/Sandstone
Grayburg
Dolomite/Anhydrite/Shale/Sandstone
Leonardian
~ San Andres
Dolomite/Anhydrite
Glorieta
Sandy Dolomite
Yeso
Paddock
Dolomite/Anhydrite/Sandstone
Blinebry
Tubb
Drinkard
Abo
Dolomite/Anhydrite/Shale
Wolfcampian
^ Wolfcamp
Limestone/Dolomite
Pennsylvanian
Virgilian
Cisco
Limestone/Dolomite
Missourian
Canyon
Limestone/Shale
Des Moinesian
Strawn
Limestone/Sandstone
Atokan
Bend
Limestone/Sandstone/Shale
Morrowan
Morrow
Mississippian
Mississippian Lime
Limestone
Devonian
Woodford
Shale
Silurian
-^Wristen Group
Dolomite/Limestone
^ Fusselman
Dolomite/Chert
Ordovician
Upper
Montoya
Dolomite/Chert
Middle
Simspson Gp
Limestone/Sandstone/Shale
Lower
Ellenburger
Dolomite
Figure 4 - Stratigraphic column of the North west Shelf. Red stars indicate injection interval. Green stars indicate productive
intervals.
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Mississippian
Chesterian
undivided
Meramecian
Osagian
Kinderhookian
Devonian
Upper
Woodford Shale
Middle
Lower
Thirtyone Fm.
Silurian
Pridolian
Wristen Gp.
~
Fasken
Fm.
Frame Fm.
Ludlovian
Wink Fm.
Wenlockian
Llandoverian
Fusselman Fm.
Ordovician
Upper
Montoya Fm.
Simpson Gp.
Middle
Lower
Ellenburger Fm.
Figure 5 - Stratigraphic column depicting the composition of the Silurian group. Red star indicates injection interval (Broadhead,
2005)
The Wristeri group was deposited in a basin platform setting across the northern half of the Permian Basin.
The depositional environment over Yoakum County during the Silurian period was a shallow inner platform,
the margin of which exists to the south, in southern Andrews County, Texas. The Silurian-age lithology on
the inner platform is dominated by grain-rich skeletal carbonates. Carbonate buildups are common within
the shallow inner platform, mainly skeletal wackestone, indicating a lower-energy deposition on the inner
platform. The carbonate shelf margin to the south acted as a barrier from basin-ward wave energy (Ruppel
and Holtz, 1994).
Depositional cycles within the inner platform indicate it was controlled by episodic sea level rise and fail,
resulting in sub-areal exposure and diagenesis. The diagenesis of the Silurian-age carbonate rocks initiated
12
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secondary porosity development and increased permeability. Dolomite and solution-related features are the
most prominent diagenetic characteristics found within the Silurian. The Wristen Group is composed of three
formations: Fasken, Frame, and Wink formations. The Frame and Wink formations are found near the ramp
boundary to the south, while the Fasken formation is found predominantly in the inner platform, where the
Rattlesnake AGI #1 well is located. The Fasken formation is predominately dolomite grading to limestone,
occurring as cycles, down section. This dolomitization is due in part to sub-areal exposure, during which
karsts and secondary porosity developed. Additional dolomitization was possible during successive sea level
fluctuations via movement of magnesium-rich solution through karsts and vugs, which acted as channels for
fluid flow (Ruppel and Holtz, 1994).
Figure 6 shows a regional isopach map of the Silurian (combined Fasken and Fusselman formations) with a
red star depicting the Rattlesnake AGI #1 well location. Thickness of the Silurian-age rock is approximately
1,000' at the Rattlesnake AGI #1 well location.
North of Andrews County there is little differentiation between the Fasken and Fusselman formations which
are both carbonate deposits with the potential for sub-areal exposure and porosity development. For
purposes of this MRV Plan, the combined Fasken and Fusselman formations are defined as the injection
interval, and the underlying Montoya formation serves as the lower confining unit.
13
-------
ThjChMSJ (ft)
W'Uin plait ttf iM'tm
M«l$COC« |4?t«U«IS
wiOtAI
4.0*1*4
Ttm
S kM>M
c«o«rTT
Figure 6- Thickness map of the Silurian system which composes the Fusselman and Wristen group
14
-------
Regional Faulting
A major uplift that began during the Pennsylvanian Period to the south, the Central Basin Platform, ceased
in the Early Permian (Wolfcampian), which caused a regional unconformity of the underlying formations
(Hoak, Sundberg, and Ortoleva). Faulting on the Northwest Shelf can be seen through high angle basement
faults that tend to die within the Pennsylvanian strata. These faults predominately represent contractional
(thrust) faults that were initiated during the Pennsylvanian as a result of regional tectonics. Hydrocarbon
traps within the Wristen group are primarily anticlinal structures dependent upon reservoir development
(Broadhead, 2005).
Site Characterization
The Rattlesnake AGI #1 well is located in Section 733, Block D, John H. Gibson Survey, in Yoakum County,
Texas. Stakeholder owns the 82.42-acre surface tract where the plant and Rattlesnake AGI #1 well are
located. The following discusses the geological character of this site.
Stratigraphy and Lithologic Characteristics
Figure 7 depicts an open hole log from an offset well (API No. 42-501-10238) to the Rattlesnake AGI #1 well
indicating the injection and primary upper confining zone. This well is approximately 1.8 miles to the
northwest of the Rattlesnake AGI #1 well, An offset well log was used to depict the upper confining intervals
as electric logs were only run in the Rattlesnake AGI #1 well across the injection zone.
15
-------
Upper Confining Interval - Woodford Shale
The Woodford is a late Devonian-age organic-rich shale deposited as a result of a widespread marine
transgression. The flooding event occurred over the majority of the Permian basin, which produced a low-
relief blanket-like shale deposit of the Woodford. Two major lithofacies found within the Woodford are black
shale and siltstone. Nutrient-rich surface waters promoted the decay of abundant organic matter within the
Woodford, resulting in a high total organic carbon ("TOC") percentage. The Woodford shale acts as the
primary source and sealant rock for the Wristen Group (Comer, 1991).
Figure 8 is a description of a core sample taken in Lea County, New Mexico just southwest of the Rattlesnake
AGI #1 well location. This sample is referenced as C9 in the reference map with the blue star representing
the Rattlesnake AGI #1 well. In the core description, black shale with abundant illitic clays is observed in the
upper section, and medium gray dolomitic siltstone found in the basal section. The mineralogic and lithologic
properties recorded in this description serve as excellent sealant characteristics to prohibit any injected fluids
from migrating above the injection interval.
The Woodford at the Rattlesnake AGI #1 well location is encountered at 10,973 ft and is approximately 63 ft
thick.
C9
Shell No. 5 Pacific Royalty
Lea County, New Mexico
Section 10.T15S-R37E
Elevation 3814 ft
X
Q
TOC
Weight
percent
1 2 3 4 5
—I I I I L_
GR i
C9 5
cs s
C9 7
Description
(ft)
35+
-12.200
Medium* to dark-gray limestone Lime mudstone with a few thin beds of brachiopod
wackestone and skeletal and pellet grainstone Some intervals highly fractured; all
fractures are filled, some with calcite, some with silica. Lowor contact not
preserved, probably conformable.
Green limestone. Clay rich. Lower contact not preserved, probably disconformablo.
Black shale. Parallel laminae Abundant fllitic clay; pyritic. Scattered grains of sift*
sized quartz, dolomite, and mica. Spores scattered or concentrated in thin laminae,
some spores replaced by pyrite, some by carbonate; sparse laminao of Radiolana;
rare burrows filled by chert, carbonate, and anhydrite Scarce veinlets filled with
calcite. Lower contact not preserved, probably conformable and abruptly gradatiorial.
I
| Boii»y
•Cochron
JRqCtMT
Medium-gray dolomitic siltstone. Abundant silt-sized anhedral and subnedral dolomite;
s»lt-sized quartz common Interbedded and interlaminated dark-gray shate and
medium-gray line-grained catcite grainstone, packs tone, and lime mudstone Wavy to
discontinuous bods near top; becomes more discontinuous, contorted, and mottled
downward; shales have parallel to wavy laminae. Pyritjc; micacoous. Sparse burrows;
rare Lmgula and wood fragments. Grades downward into lighter gray dolomitic
siltstone with fewer shale inter bods Lower contact not preserved, probably
disconfonrtablo.
Pale brownish pink crystalline dolostone. Vuggy.
^Medium-gray shale. Dolomitic; silty.
69+
Pale brownish-pink crystalline dolostone Vuggy.
»-12,400
l£
| Y00hum
I
I
I ~
' Coirct
Figure 8- Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994)
16
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Injection Interval - Fasken Formation
The Rattlesnake AGI #1 well reaches total depth in the Fasken/Fusselman formation (Silurian in age), directly
below the Woodford formation. Dolomites at the top of the Fasken formation underwent multiple leaching
and diagenetic episodes which developed secondary porosity. This is evidenced in offset wells by the practice
of only drilling through the top 30' of the Fasken, in anticipation of encountering the best reservoir quality.
In Figure 8, the uppermost Silurian section is described as 'vuggy dolostone' in the core description. Beds
below the top of the Fasken section may also have similar petrophysical attributes if exposed to multiple
diagenetic events. Solution-collapse and karst breccia horizons can be found within inner platform deposits,
some occurring as much as 100 ft below the Fasken top (Ruppel and Holtz, 1994).
Porositv/Permeabilitv Development
Porosity in the Fasken formation at the Rattlesnake AGI #1 well location is typically moldic and intercrystalline
associated with leaching of allochem-rich intervals. Porosity is directly related to these leaching events which
occurred during and post-deposition, resulting in vugs and karst-like features. Figure 9 provides reservoir
information from core data within fields in the Wristen buildup and platform carbonate play. The average
porosity of these cores is 7.1% with an average permeability of 45.28 millidarcies (Ruppel and Holtz, 1994).
The porosity and permeability described in the offset core data indicate the Fasken formation provides
sufficient accessible pore space for the amount of fluid injection proposed.
Using the above values as reference points, the Rattlesnake AGI #1 porosity log (API No. 42-501-36998) was
evaluated. Figure 10 is the product of the petrophysical analysis performed on the open hole logs run within
the injection interval at the Rattlesnake AGI #1 well. A permeability curve was generated from the effective
porosity curve using the table in Figure 9 to establish the porosity-permeability relationship. In Figure 10,
the majority of the injection interval's porosity and permeability is found at the top of the Fasken formation,
which correlates with the diagenetic processes described above. These curves are extrapolated to the
injection site and used to establish reservoir characteristics in the plume model.
17
-------
Wristen
Fusselman
Buildups and
Thirtyone
Thirtyone
Shallow Platform
Platform
Ramp
Deep-Water
Carbonate play
Carbonate play
Carbonate play
Chert play
Porosity (%>
Numbe/ o' data points
33
30
16
35
Mean
7,93
7. to
e.4i
14,85
Mnimum
1.00
2.70
3.50
2.00
Maximum
17,70
14.00
0.50
30.00
Standard devation
4.01
2.67
1.75
6.76
Permeability (md)
dumber ot (Jala points
21
24
12
33
Mean
11.61
45.28
1.51
9.56
Minimum
0.60
2.90
0.40
1.00
Maximum
84.80
400.00
30.00
100.00
Standard deviation
22.48
99.17
8.36
22.23
Initial water saturation {%)
Number oi data points
24
28
10
31
Mean
26.96
31.55
24.70
31.46
Mmmnum
10.00
20.00
16.00
10.00
Maximum
50.00
55.00
40.00
45.00
Standard deviation
9.31
10.4b
7.39
8.33
Residua) oil saturation {%)
Number a', data points
8
13
5
22
Mean
34.06
30.54
21.30
29.17
Minimum
30.00
20.00
9.00
14.00
Maximum
50.00
35.00
35.00
48.20
Standard devation
6.99
4.61
11.66
9.76
Oil viscosity (op)
Number oi data points
11
12
5
21
Mean
0.69
1.10
0.33
0.68
Mrnmum
0.13
0.32
0.04
0.07
Maximum
1.08
2.00
1.00
1.03
Standard devation
0.81
0.75
0.40
0.42
Oil formation volume factor
Number oi data points
21
22
6
32
Mean
1.57
1.22
1.65
1.50
Mnirnum
1.05
1.05
1.31
1.30
Maximum
1.91
1.55
1.66
1.73
Standard deviation
0.28
0.14
0.48
0.16
Bubble-point pressure (psi)
Number of data points
9
9
5
19
Mean
2.272
1,055
3.750
2.752
Minimum
798
450
2.660
1.755
Maximum
4.C50
2,600
4,440
4.655
Standard devation
1.300
689
756
667
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays (Ruppel and Holtz, 1994)
-------
Low Perm
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
0
[PLJ]=11036.9
Figure 10- Rattlesnake AG I #1 open hole log (42-501-36998) with effective porosity (green) and permeability (black)
Formation Fluid
Four wells were identified through a review of chemical analyses of oil-field brines from the U.S. Geological
Survey National Produced Waters Geochemical Database v2.1 within the Devonian, Silurian-Devonian, or
Fusselman formations within 20 miles of the Rattlesnake AGI #1 well. The location of these wells is shown in
Figure 11. Water chemistry analyses conducted on oil-field brines in Gaines County, as reported to the Texas
19
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Water Development Board, provided additional data on Devonian and Silurian reservoir fluids. Results from
the synthesis of these two sources are provided in Table 1. The fluids have greater than 20,000 parts per
million ("ppm") total dissolved solids, therefore these aquifers are considered saline. These analyses indicate
the in-situ reservoir fluid of the Devonian, Silurian, and Fusselman formations are compatible with the
proposed injection fluids.
Figure 11 - Offset wells used for Formation Fluid Characterization
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples
Average
Low
High
Total Dissolved Solids (ppm)
41,428
23,100
55,953
pH
7,2
7.0
7.3
Sodium (ppm)
12,458
7,426
15,948
Calcium (ppm)
1,759
1,010
2,320
Chlorides (ppm)
23,423
12,810
31,930
Fracture Pressure Gradient
Fracture pressure gradient was estimated using Eaton's equation. Eaton's equation is commonly accepted
as the standard practice for the determination of fracture gradients. Poisson's ratio ("v"), overburden
gradient ("OBG"), and pore gradient ("PG") are all variables that can be changed to match the site-specific
injection zone. Through literature review and industry standards, we are able to determine the expected
20
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fracture gradient. First, 1.05 psi/ft and 0.465 psi/ft were assumed for both the overburden and pore
gradients, respectively. These values are considered best practice values when there are no site-specific
numbers available. For limestone/dolomite rock, the Poisson's ratio to be assumed to be 0.3 through
literature review (Molina, Vilarras, Zeidouni 2016). Using these values in the equation below, a fracture
gradient of 0.72 psi/ft was calculated. A 10% safety factor was then applied to this number resulting in
maximum allowed bottom hole pressure of 0.64 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.
For the upper confining interval, a similar fracture gradient as the limestone was calculated. Shale has an
increased chance to vertically fracture if the injection interval is fractured (Molina, Vilarras, Zeidouni 2016),
so assuming a Poisson's ratio equal to the injection interval was used as a conservative estimate. The lower
confining zone was assumed to be of a similar matrix to that of the injection interval, with the key difference
being that the formation is much tighter (lower porosity/permeability). The Poisson's ratio was assumed to
be slightly higher in this rock. As seen in Table 2, the fracture gradient is slightly higher than the upper zones.
Table 2 - Fracture Gradient Assumptions
Injection Interval
Upper Confining
Lower Confining
Overburden Gradient (psi/ft)
1.05
1.05
1.05
Pore Gradient (psi/ft)
0.465
0.465
0.465
Poisson's Ratio
0.30
0.30
0.31
Fracture Gradient psi/ft
0.72
0.72
0.73
FG +10% Safety Factor (psi/ft)
0.64
0.64
0.66
The following steps were taken to calculate fracture gradient:
FG = —-—(OBG - PG) + PG
1 — v
0.3
FG = 1_Q3(1-05 - °-465) + °-465 = °-72
FG with SF = 0.72 x (1 - 0.1) = 0.64
Lower Confining Zone - Montoya Formation
The low-permeability Montoya Formation is a tight limestone/dolomite that will act as the lower confining
unit for the injection interval. Figure 10 shows the decreasing trend in porosity of the limestone rock in the
lower section that was not exposed to leaching diagenesis. Porosity in the lower section can range from 2-
3% with permeabilities below 1 millidarcy. The Rattlesnake AGI #1 well drilled 6' into the Montoya formation,
but the section was not logged. The Montoya is anticipated to be roughly 250' thick. These petrophysical
characteristics represent ideal sealing properties to prohibit any migration of injected fluid outside of the
injection interval.
Local Structure
Regional structure in the area of the Rattlesnake AGI #1 well is dictated by carbonate buildups and structural
events causing anticlinal to synclinal features throughout the area. The Rattlesnake AGI #1 well is specifically
located at the base of a syncline with anticlinal features to the northeast, south, and east. Figure 12 is a
21
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structure map of the Silurian formation of subsea depths with the star representing the location of the
Rattlesnake AGI #1 well. The red and blue lines represent the cross-section reference lines.
Faulting can be seen to the south and east of the Rattlesnake AGI #1 well location. These faults were
interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure 12. Many of
these faults are minor, with offsets less than 50'. The nearest large fault is found southeast of the Rattlesnake
AGI #1 well and has an offset of roughly 120'. None of these faults project above the Wolfcamp formation,
rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. Production is
associated with a hydrocarbon trap set up by the larger fault to the southeast, indicating the fault is vertically
sealing in nature. If, in the unlikely event the faults' sealing properties are compromised post-injection,
secondary confinement is provided by the tight limestones found within the overlying Mississippian Lime
formation along with shale layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the
largest fault found southeast of the Rattlesnake AGI #1 well, terminates within the Atoka formation. Though
it crosses the Silurian section, this fault thrusts the Mississippian Lime upward against the Atoka shales. The
tight reservoir characteristics of the Mississippian Lime and shaley section of the Atoka create a confining
environment vertically and laterally to contain potential upward migration of buoyant fluids. Shales within
the Wolfcamp formation provide additional confining beds between overlying USDWs and the fault plane.
Figures 13 and 14 are north-south and west-east structural cross sections showing the structural dips. As
seen in these figures, the Woodford formation is laterally present above the injection interval, alleviating risk
of erosion of the upper sealant formation.
Larger versions of Figures 11, 12, 13 and 14 are provided in Appendix A.
22
-------
-------
-------
NW
3T?w'
42501105700000
1-667
TEXAS CRUDE OIL CO
+
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
42501358340000
ROBERTS UNIT
2
APACHE
42501335110000
CORNELL UNIT
3019D
EXXON MOBIL
SE
asr
MONTOYA [PUJ
25
-------
Injection and Confinement Summary
The lithologic and petrophysical characteristics of the Faskeri and Fusseiman formations at the Rattlesnake
AGI #1 well location indicate the formations have sufficient thickness, porosity, permeability, and lateral
continuity to accept the proposed injection fluids. The Woodford formation shale at the Rattlesnake AGI #1
well has low permeability and is of sufficient thickness and lateral continuity to serve as the upper confining
zone. Beneath the injection interval, the low permeability, low porosity Montoya formation is unsuitable for
fluid migration and serves as the lower confining zone. Deeper, laterally continuous formations, including the
Simpson Group, provide additional confinement.
Groundwater Hydrology
Yoakum County falls within the boundary of the Sandy Land Underground Water Conservation District. Three
aquifers are identified by the Texas Water Development Board's Aquifers of Texas report in the vicinity of the
proposed Rattlesnake AGI #1 well: the Dockum Aquifer, Edwards-Trinity Aquifer, and Ogallala Aquifer
(George, Mace and Petrossian, 2011). Table 3 references the aquifers' positions in geologic time and the
associated geologic formations. A schematic cross section in Figure 15, near the proposed Rattlesnake AGI
#1 well, illustrates the structure and stratigraphy of these water-bearing formations. Groundwater flow
direction is the same for the three aquifers, generally from northwest to southeast, Figure 16 (Teeple, et al.,
2021).
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and Yoakum Counties, Texas
(Teeple, et al. 2021)
Era
Period
Epoch or series
Geologic unit group
or formation
Lithologic descriptions
Hydrogeologic unit
Cenozoic
Tertiary
Pliocene
Ogallala Formation
Gravel, sand, silt,
and clay
High Plains
aquifer system
(Ogallala aquifer)
Miocene
Mesozoic
Cretaceous'
Comanchean
Series
Washita Group2
Shale and limestone
Edwards-T rinity
(High Plains)
aquifer system
Fredericksburg Group
Clay, shale, and
limestone
Trinity Group
Sand and gravel
Triassic
Upper
Dockum Group
Sillstone, mudstone,
shale, and sandstone
Dockum aquifer
26
-------
Figure 15- NW-SE Cross Section of aquifers in the Rattlesnake AG! #1 well area (George, Mac and Petrossian, 2011)
27
-------
IOCKLEV COI NTY 8 103°0'
/ •
HOC KLEV COl.Vn
"J \^J! In* • •• •Hv4. •
V , " •. A " *
r I J ' *1 nnvaJ^Sil'
/ • • t / • 'I** * i» 1
K.-.'- l\i^\\s>* I
lY\ 3| ~7 . 1
/ ' <8 jX • /• *> / ~**. i' >!
[ <. OTvKsl ,. • ,
icuiNfu" fr;—7
i if _ \ »V*^r"
C 1Q3°D' ,K
rrir
33°20' I
I ~
L-'
Y0AKUM
»v \ | x COUNTY
©#xr /
/ fMiu \ ~'
y .<
l«s
f Mjch
\ / n*L"IMkt jif
v^' (
ftpy ' ' v x liruu^lfcUi x
~ ' j
artr'
32"4G'
-HOCKLEY COUNTY
0 5 10 (SMILES
1 . 1 r i1 1
0 5 tO T5 KILOMETERS
Base modified tram U S Geological Survey 1 250 000-scale to 1 2,000.000-scale digital data.
Universal Transverse Mercator projection, ione 13
North American Datum of 15&3
Groundwater-level altitude, in
leal above North American
Vertical Oatum of 1988
|^m" >3,750
Hj- 3,500
3,250
3,000
<2,750
EXPLANATION
Study area boundary
Edwards-Trinity I High Plains} nquilor downdip enfant
Underground water conservation district boundary
Llano Estacado Underground Water Conservation District
Sandy Land Underground Water Conservation District
South Plains Underground Water Conservation District
Potenriometric contour Shows altitude at
which water level would have stood in
tightly cased wells. Contour interval is
100 feel Datum it North American
Vertical Datum of 1988 Dashed where
mlerred.
Groundwater How pallia Dashed where
interred
• Groundwater tevol measurement (Payne
and others. 2020)
Figure 16 - Potentiometric surfaces from wells completed in A, Ogallala aquifer, B, the Edwards-Trinity aquifer and C, the Dockum
aquifer (George, Mace and Petrossian, 2011).
The Dockum Aquifer is the oldest of the three aquifers, formed from Triassic-age Dockum Group sediments,
and underlies the Cretaceous Trinity and Fredericksburg Groups (Teeple, et al., 2021). Figure 17 shows the
subsurface and outcrop extent of the Dockum Aquifer. As shown in Figure 18, the total dissolved solids in
western Yoakum County exceed 5,000 milligrams per liter ("mg/L"), therefore the aquifer is considered
brackish.
28
-------
Dockum
Aquifer
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDBj
Figure 18 - Total dissolved solids in groundwater from the Dockum Aquifer (Ewing et at, 2008)
The Edwards-Trinity Aquifer is a collection of Cretaceous age sediments - primarily the Trinity Group Antlers
formation sandstone and limestones of the Fredericksburg Group, specifically the Comanche Peak and
Edwards formations. Figure 19 shows the subsurface and outcrop extent of the Edwards-Trinity Aquifer.
Freshwater infiltration to this aquifer is primarily from the overlying Ogallala Aquifer (George, Mace and
Petrossian, 2011).
29
-------
The Ogallala aquifer consists of sand, gravel, clay and silt sediments (George, Mace and Petrossian, 2011) and
produces the majority of the freshwater for Yoakum County. Figure 20 shows the subsurface and outcrop
extent of the Ogallala Aquifer.
The base of the deepest aquifer is separated from the injection interval by approximately 8,600' of rock,
including 576' of Salado salt. Though unlikely for reasons outlined in the confinement and potential leaks
sections, if migration of injected fluid did occur above the Woodford Shale, thousands of feet of tight
sandstone, limestone, shale, salt and anhydrite beds occur between the injection interval and the lowest
water-bearing aquifer.
30
-------
The TRRC's Groundwater Advisory Unit ("GAU") identified the base of Underground Sources of Drinking
Water ("USDW") at 375' at the location of the Rattlesnake AGI #1 well. Therefore, there is approximately
10,661' 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
Rattlesnake AGI #1 well is provided in Appendix B.
Description of the Injection Process
Current Operations
The 30-30 Facility and its associated Rattlesnake AGI #1 well began operating in March of 2019. Since
operations began, 258 million cubic feet ("MMCF") of treated acid gas ("TAG") has been injected, which
equates to 12,316 metric tons of C02. Over the life of the injection period, the average daily injection rate
has been 223 MSCF/d. The approximate current composition of the TAG stream is as follows;
Table 4 - Gas Composition of 30-30 Facility outlet
Component
Mol %
C02
89.68%
H2S
9.20%
Other
1.12%
31
-------
The 30-30 Facility is designed to compress, treat, and process natural gas produced from the surrounding
counties in Texas and New Mexico. The gas is dehydrated to remove the water content, then processed to
separate natural gas liquids which are then sold, along with the pipeline quality natural gas, to various
customers. TAG is then directly routed from the plant amine regen system to the Rattlesnake AGI #1 well.
The facility is manned 24 hours per day, 7 days per week.
Planned Operations
Stakeholder anticipates increasing the amount of CO2 injected into Rattlesnake AGI #1 well from the current
rate up to 16 MMSCF/d. Additional growth is expected both at Stakeholder facilities and regionally as rising
sour gas production and flaring reduction mandates create the need for additional CO2 and H2S disposal
capacity. Stakeholder plans to inject into this AGI well for another 14 years for a total of 17 years from the
start of injection in 2019.
Figure 21 shows a high-level view of the current process flow plus the prospective additional operations over
time.
Amine Regen
System
>96% C02
1,090-1,150 psig
CO, Offta ke
13% H2S, 87% COj
1,400-2,200 psig
AGI
Compression
Prospective Facilities
Meter
er XV
Meter
&
XV
A
l_
"l
I
-L
596-13% HjS, 87%-
95% C02
1,400-2,500 psig
Injection
Pumps
XV
Current Operation
AGI
Well
Figure 21 - 30-30 Facility Process Flow Diagram
Reservoir Characterization Modeling
The modeling software used to evaluate this project was Computer Modelling Group's GEM 2020.11 ("GEM")
simulator. Computer Modelling Group ("CMG") has put together one of the most accurate and technically
sound reservoir simulation software packages for conventional, unconventional, and secondary recovery.
GEM utilizes equation-of-state ("EOS") algorithms along with some of the most advanced computational
methods to evaluate compositional, chemical, and geochemical processes and characteristics to produce
highly accurate and reliable simulation models for carbon injection and storage. The GEM model is
recognized by the EPA for use in area of review delineation modeling as listed in the Class VI Well Area of
Review Evaluation and Corrective Action Guidance document.
The Silurian (Fasken/Fusselman) formation is the target formation for Rattlesnake AGI #1 well. The Petra
software package was used to create the geologic model of the target formation. The faulting and geologic
structure was then imported into GEM and used to create contours for the model grid.
Porosity and permeability estimates were determined using the porosity log from the Rattlesnake AGI #1
well and a petrophysical analysis was performed to correlate porosity values by depth with core porosities
32
-------
as shown in the Holtz paper. The Coates permeability equation was then used to calculate permeability with
depth. Both porosity and permeability are assumed to be laterally homogeneous in the reservoir.
The reservoir is assumed to be at hydrostatic equilibrium and initially saturated with 100% brine. An infinite
acting reservoir was created to simulate boundary conditions. The gas injectate is composed of H2S, CO2,
CH4, and other components as shown in Table 5. Core data from literature review was used to determine
residual gas saturation (Ruppel and Holtz, 1994). The modeled composition only takes into consideration the
carbon dioxide and hydrogen sulfide as they comprise nearly 99% of total stream. For the initial injection
period, these compositions are normalized up to 100%. For the proposed additional injection period, it is
expected that a larger portion of the gas added is carbon dioxide, changing the composition to ~93% CO2 and
~7% H2S.
Table 5 - Modeled Initial Gas Composition
Measured Current
2019-2024 Model
2024-2036 Model
Component
Composition (mol%)
Composition (mol%)
Composition (mol%)
Carbon Dioxide (C02)
89.678
90.696
92.921
Hydrogen Sulfide (H2S)
9.200
9.304
7.079
Methane (CI)
0.303
0
0
Ethane (C2)
0.058
0
0
Propane (C3)
0.108
0
0
N-Butane (NC4)
0.025
0
0
Hexane Plus (C6+)
0.628
0
0
Core data from literature review was used to determine relative permeability curves between carbon dioxide
and the connate brine within the Silurian-Devonian carbonates (Ruppel and Holtz, 1994). The key inputs
used in the model include an irreducible water saturation of 25% and a maximum residual gas saturation of
21%.
The grid contains 141 blocks in the x-direction (E-W) and 201 blocks in the y-direction (N-S), totaling 28,341
grid blocks per layer. The grid blocks are each 150' by 150' by layer thickness as specified in Table 6. This
results in the grid being 21,150' by 30,150' totaling just over a 23-square mile area (14,640 acres). Each layer
in the model was determined by identifying higher permeability zones as targets for injection from the logs
and assigning each high permeability and intermediary low permeability zone its own layer. One zone was
identified as being a karst limestone (layers 2-7). Due to the "karsted" nature of this rock, it was determined
that most of the injectate would flow into this zone. Therefore, the karst limestone was further split into
layers by permeability to provide higher resolution and more accurately simulate which layer will have more
gas flow into it. Figure 22 provides a detailed breakdown of the "karsted" rock.
33
-------
Permeability Distribution of Karst Zone
2
3
4
l—
(D
_l
5
6
7
1 10 100 1000
Permeability (mD)
Figure 22 - Permeability Distribution of Karst Limestone
In total, there are sixteen (16) layers in the model, representing ten (10) layers of pay and six (6) layers of
intermediary low permeability zones. The properties of each of these layers are summarized in Table 6
below.
Table 6 - CMG Model Layer Properties
Layer #
Top (ft)
Thickness (ft)
Permeability (mD)
Porosity
1
11,037
71
1
2.8%
2
11,108
57
47
8.0%
3
11,165
19
223
11.9%
4
11,184
16
15
6.3%
5
11,200
39
70
9.2%
6
11,238
11
228
12.3%
7
11,249
21
49
8.3%
8
11,270
251
2
3.7%
9
11,520
46
9
5.6%
10
11,566
13
3
4.3%
11
11,579
19
17
6.5%
12
11,597
14
2
3.9%
13
11,611
103
13
6.0%
14
11,714
46
2
3.7%
15
11,759
67
23
6.1%
16
11,826
125
2
3.6%
34
-------
Simulation Modeling
The primary objectives of the model simulation were to:
1) Estimate the maximum areal extent and density drift of the acid gas plume after injection
2) Assess the impact of offset saltwater disposal ("SWD") well injection on density drift of the plume
3) Assess the impact of offset producing wells on the density drift of the plume
4) Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone
5) Assess the likelihood of the acid gas plume migrating into potential leak pathways
The reservoir is assumed to be an aquifer filled with 100% brine. The salinity of the formation is estimated
to be 53,000 ppm (Texas Water Development Board, 1972). The acid gas stream is primarily composed of
C02 and H2S as stated previously. Core data was used to help generate relative permeability curves. Cores,
from the literature reviews previously discussed, that most closely represent the vuggy carbonate seen in
this region were identified and the Corey-Brooks equations were used to develop the curves. The lowest
residual gas saturation found in the cores was then used for a conservative estimate of plume size. From
offset injection well analysis, the initial reservoir pressure was determined to be 5,132 psi which is equivalent
to a 0.465 psi/ft pressure gradient. The fracture gradient of the injection zone was estimated to be 0.72
psi/ft, which was determined using Eaton's equation. A 10% safety factor was then applied to this number,
putting the maximum bottom-hole pressure allowed in the model at 0.64 psi/ft which is equivalent to 7,064
psi.
The model also takes into account offset saltwater disposal ("SWD") injection volumes within five (5) miles
of the Rattlesnake AGI #1 well. These SWDs create a pressure front that push the plume further up-dip of
the formation. A total of twenty (20) offset wells currently injecting into the target formation were identified.
Eleven (11) of these offset SWDs were out of the confines of the grid, but were still accounted for in the
model. Nine (9) salt-water disposals were modeled within the boundaries of the 23-square-mile grid. Two
(2) of these offset injectors are currently only permitted (not drilled) but were assumed to start active
injection within the first year of the model. Both permits were simulated at the forecasted injection rate
schedule for 30 years. These forecasts were provided by the operators of these wells. Historical injection
rates of each of the other existing wells were analyzed and projected into the model. This simulation includes
the effect of water injection on the density drift of the plume and bottom hole pressure.
Further review of the area revealed production wells in the Silurian-Devonian formation that could impact
the density drift of the plume by creating a "pressure sink". A "pressure sink" is an area of lower pressure
caused by the production of formation fluids. To simulate this effect, nine (9) production wells were grouped
together and their respective production rates combined into a single well to add more conservatism into
the model. These producers were forecasted an additional 15 years to simulate their potential economic
lifespan. This simulation includes the effect of fluid production on the density drift of the plume and bottom
hole pressure. Overall, the "pressure sink" has little effect on the density drift and, as discussed below, the
plume never reaches the producing wells.
The model runs for a total of 814 years, starting in 1965 with the beginning of offset production until the
calculated stabilization of the plume in 2779. The injection of TAG from Rattlesnake AGI #1 is modeled from
the beginning of injection in 2019 through the planned 14 years of future injection. The model also includes
the 57 years of historical plus 15 years of forecasted future oil and gas production.
Additionally, historical monthly injection rates of all nearby SWDs were incorporated into the model to
simulate any additional near-wellbore pressure increase that may occur due to offset injection. The
35
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modelling of the saltwater injection begins in 1984 when the first offset SWD well became operational. The
SWDs to the North were grouped into four (4) separate groups to simulate their combined effect on the
density drift of the plume. All offset injection wells and their groupings are included in Table 7. All offset
production wells are listed in Table 8.
Table 7 - All Offset SI/l/Ds included in the model
Grouping
API
Well Name
Well#
42-501-32511
SAWYER, DESSIE
1
42-501-02068
WEST, M. M.
2
Group 1
42-501-02053
NORTH CENTRAL OIL CO. "A"
1
42-501-01453
SMITH, EDS. HEIRS "B"
1
42-501-02059
SMITH, ED "C"
1W
Group 2
42-501-30051
JOHNSON
2
42-501-30001
JOHNSON
ID
Group 3
42-501-37066
MISS KITTY SWD 669
1W
42-501-36650
RUSTY CRANE 604
1W
Group 4
42-501-36745
SUNDANCE 642
1
42-501-33887
WINFREY 602
3WD
42-501-37252
Miller SWD
7
42-501-37367
BLONDIE 704
1W
42-501-37206
BRUSHY BILL 707
1WD
42-501-36622
WISHBONE FARMS 710
1W
Standalone
42-501-35834
ROBERTS UNIT
2
42-501-33297
STATE ELMORE
1
42-501-10238
SHEPHERD SWD
1
42-501-33511
CORNELL UNIT
3019D
42-501-32868
WILLARD UNIT
1WD
Table 8 - All Offset Producers included in the model
API
Well Name
Well #
42-501-10046
ELLIOTT, C.A.
2
42-501-10079
RANDALL, E
32
42-501-337932
RANDALL, E
40
42-501-33885
RANDALL, E
41L
42-501-34016
RANDALL, E
43 L
42-501-34017
RANDALL, E.
45 L
42-501-34023
RANDALL, E
42L
42-501-34024
RANDALL, E
44
42-501-35418
RANDALL, E
46
Rattlesnake AGI #1 came online in 2019 and the model simulated its historical monthly injection rates until
2024. After this initial period, it is conservatively assumed that the injection rate increases to the maximum
permitted rate of 16 MMSCF/d for the remainder of the active injection period in 2036. At this point, the
36
-------
Rattlesnake AGI #1 well stops injection while the offset SWD injectors continue operations for thirty more
years. Density drift then occurs until plume stabilizes, which was determined to be 814 years from the start
of the model in 1965. Stabilization of the plume is determined to occur when the model shows no further
lateral movement horizontally or vertically. The plume boundary is then defined by a weighted average gas
saturation in the aquifer of 3%.
The maximum plume extent during the 17-year Rattlesnake injection period is shown in Figure 23. The final
extent after 743 years of density drift after injection ceases is shown in Figure 24. The extensive time of the
modeled density drift of the plume is driven by the buoyant forces of the gas, the permeability/porosity of
the rock, and the residual gas saturation. Initially, the karsted region takes on most of the injection, but due
to the buoyant forces, it is slowly pushed up higher into the less permeable layers of the injection interval.
These lower permeable layers, increase the amount of time it takes for the plume to reach its maximum areal
extent. As all the inputs to the model were based on the most conservative approach, the maximum extent
of the plume will likely be smaller and the effective impact on reaching potential leakage pathways will be
minimal as the amount of CO2 at those far extents will be small.
State Elmore
Brushy Bills 707
Shepherd SWD
Rattlesnake AGI Plume
Global Mote froction(CQ2) 2036-Jqn-Ol K Plone: 2 of 16
-0.70
¦ -060
1050
o.
-
0.20
Group 2 Group 4 Group 3 Group 1
Blondie 704
Mi ter SWD
Rattlesnake AGI
Willard Unit
Roberts Unit
Production Wells
Cornell Unit
Figure 23 - AreaI View Gas Saturation Plume, 2036 (End of Injection)
37
-------
Brushy Bills 707
19,215'
Miller SWD
6,900'
Blondie 704
Production Wells
Rattlesnake AGI
Willard Unit
Roberts Unit
Cornell Unit
Group 2 Group 4 Group 3 Group 1
State Elmore
Shepherd SWD
1.00-—
!¦
090
080
-070
-060
-
t
-030
020
Rattlesnake AGI Plume
Global Mole Fractlon{C02) 2779-Doc-OI K Plane: 2 of 16
Figure 24- Area! View Gas Saturation Plume, 2779 (End of Density Drift)
Figure 25 shows the surface injection rate and bottom hole pressure over the injection period and the period
of density drift after injection ceases. The bottomhole pressure increases the most as the injection rate
reaches its peak, reaching a maximum pressure of 5,413 psi. This buildup of 280 psi keeps the bottomhole
pressure well below the fracture pressure of 7,064 psi. The maximum surface pressure associated with the
maximum bottomhole pressure reached is 2,494 psi.
16.000,000
I" 14.000,000
£ 12,000,000
= 10,000,000
o
¦ 8,000,000
O
6,000,000
£
a 4,000,000
s 2.000,000
o
s
r
r
ltttf.ll
ij/"
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049 2051 2053 2055
5400 I
6370 J
S340 |
5310 b
O
5280 ®
T3
5250 ®
w
5220 c
at
5190 9*
v>
5160 —
— Rattlesnake AGI, Gas Rate SC - Daily
— Rattlesnake AGI, Well Bottom-hole Pressure
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time
38
-------
SECTION 3 - DELINATION OF MONITORING AREA
This section discusses the delineation of Maximum Monitoring Area ("MMA") and Active Monitoring Area
("AMA") as described in EPA 40 CFR §98.448(a)(l).
Maximum Monitoring Area
The MMA is defined as equal to or greater than the area expected to contain the free-phase C02 plume until
the C02 plume has stabilized plus an all-around buffer zone of at least one-half mile. 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 takes into account the
following considerations:
• 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 adequately predict the density drift of the plume
Acid gas injectate was analyzed by a third-party vendor to determine the initial composition used in the
model. The report is provided in Appendix C. The molar composition of the gas is primarily C02 with some
H2S and CH4. The change in molar composition was also incorporated into the model as future predominantly
C02 streams are added for injection. As discussed in Section 2, the gas was injected into the Silurian
formation, specifically, the Fasken/Fusselman formation. The geomodel was created based off the rock
properties seen in the Fasken/Fusselman.
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 2036, the areal
expanse of the plume will be 1,052 acres. The maximum distance between the wellbore and the edge of the
plume is approximately 0.87 miles to the southeast. After 743 additional years of density drift, the areal
extent of the plume is 2,177 acres with a maximum distance to the edge of the plume of approximately 1.35
miles to the southeast.
Figure 26 shows the plume boundary at the end of injection, the stabilized plume boundary and the MMA.
39
-------
f
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
6 Stabilized Plune
i
1/2-Mile Naxinua Monitoring Area CMHA)
Stakeholder Midstream
Yoakum Co., TX
Il J i
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PCS:
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Figure 26 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area
Active Monitoring Area
The initial AMA will cover a 14-year monitoring period. This period equates to the time of expected future
injection. The AMA will be established by superimposing the area based on a half-mile buffer around the
anticipated plume location at the end of injection (2036) with the area of the projected free-phase C02 plume
at five additional years (2041). In this case, the plume boundary in 2041 is within the plume at 2036 plus a
half-mile buffer. By 2036 at the latest, a revised MRV plan will be submitted to define a new AMA. Figure 27
shows the area covered by the AMA.
Larger size versions of Figures 26 and 27 are provided in Appendix D.
40
-------
ID
1 Inch = 0.51 Mile
1:32,000 m
&
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
& 19-Year Plume
wi th
1/Z-Hile Active Monitoring Area (AHA)
Stakeholder Midstream
Yoakum Co.. TX
PCS: NADB3 TX-NC FIPS 4202
-------
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE
This section identifies the potential pathways for C02 to leak to the surface within the MMA and the
likelihood, magnitude and timing of such leakage. The potential leakage pathways are:
• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Leakage through the confining layer
• Leakage from Natural or Induced Seismicity
Leakage from Surface Equipment
The surface facilities at the 30-30 Facility are designed for injecting acid gas containing H2S, and therefore
minimize leakage points such as valves and flanges following industry standards and best practices. H2S gas
detectors are located around the facility and the well site. These gas detectors trigger alarms at 10 parts per
million ("ppm"). Additionally, all Stakeholder field personnel are required to wear H2S monitors which are
triggered at 5 ppm of H2S. A shut-in valve is located at the wellhead and is locally controlled by pressure,
with a high pressure and low pressure shut-off.
The facilities have been designed and constructed with additional safety systems to provide for safe
operations. These systems include Emergency Shutdown ("ESD") valves to isolate portions of the plant and
pipeline, pressure relief valves along the pipeline to prevent over pressurization, and flares to allow piping
and equipment to be de-pressured rapidly under safe and controlled operating conditions in the event of a
leak. Figures 28 and 29 display the facility safety plot plan, taken from the 30-30 H2S Contingency Plan, and
show the location of the H2S monitors in the vicinity of the plant and the Rattlesnake AGI #1 well. Should
Stakeholder construct additional C02 facilities, as indicated in Figure 21, a separate meter will be installed for
the additional stream in order to comply with the 40 CFR §98.448(a)(5) measurement. As this meter will be
in close proximity to the existing facilities, it will utilize the existing monitoring programs discussed previously.
Additionally, C02 monitors will be installed near the new meter and tied into the facility monitoring systems.
42
-------
Figure 28 - Site Plan, 30-30 Facility
43
-------
With the level of monitoring at the 30-30 Facility and the Rattlesnake AGI #1 well, any release of H2S and C02
would be quickly identified, and the safety systems would quickly minimize the volume of the release. The
C02 injected into the Rattlesnake AGI #1 is injected with H2S at a concentration of 10% (100,000 ppm). At
this high level of H2S concentration, even a small leakage would trigger personal and facility H2S monitors set
to alarm at 5 ppm and 10 ppm respectively. If any leakage were to be detected, the volume of C02 released
will 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).
A larger scale version of Figure 28 is provided in Appendix E.
Leakage from Existing Wells within MMA
Oil and Gas Operations within Monitoring Area
A significant number of wells have historically been drilled within the area of the Rattlesnake AGI #1 well,
however production has primarily been from the shallower San Andres formation in the Wasson Field. The
San Andres is separated from the Silurian-Devonian interval by 4,720' in this area. In addition to the primary
San Andres production, a few wells have produced from the Wolfcamp. The Wolfcamp is separated from the
Siluro-Devonian interval by is 1,800'. Within the projected plume area of the Rattlesnake AGI #1 well, there
are no penetrations of the injection interval. There are ten wells within the MMA that penetrate the
injection interval.
A review of the TRRC records for all of the wells which penetrate the injection interval within the MMA,
shows the wells were properly cased and cemented to prevent annular leakage of C02 to the surface. The
plugged wells are also adequately protected against migration from the Devonian by the placement of the
plugs within the wellbores. Additionally, the Rattlesnake AGI #1 well was designed to prevent migration from
the injection interval to the surface through the casing and cement placed in the well, as shown in Figure 29.
Mechanical integrity tests ("MIT") required under TRRC rules are run annually to verify the well and wellhead
can hold the appropriate amount of pressure. If the MIT were to indicate a leak, the well would be isolated
and the leak mitigated quickly to prevent leakage to the atmosphere.
A map of all wells within the MMA is shown in Figure 30. Figure 31 shows only those wells which penetrate
the injection interval within the MMA. The MMA review maps, a summary of all the wells in the MMA and
detailed wellbore schematics for those wells which penetrate the injection interval are provided in Appendix
F.
44
-------
Base of USDW@375'
Rustler @ 2,345'
Salado @ 2,443'
Yates @ 3,019'
Seven Rivers @ 3,440'
dH
Grayburg @ 4; 190'
San Andres @ 4,465'
DV Tool @ 4,275'
DV Tool @5,591'
Glorieta @ 6,316'
Clearfork @ 6,492'
Wichita @ 8,628'
12,500' -
13,000' -
15,500' -
GK
Upper Wolfcamp @ 9,239'
Strawn @ 10,030'
Atoka @ 10,230'
Woodford @ 10,973'
Devonian @ 11,036'
Wristen@ 11,268'
Fusselman@ 11,538' Ci)
Montoya @ 11,974'
¦
ir
DV Tool @9,575'
Packer @ 10,966'
TD@ 11,980'
KB:
N/A
BHF:
NA
GL:
3,627'
Spud:
5/27/2018
Casing/Tubing Information
Label
1
2
3
4
Type
Surface
Intermediate
Production
Tubing
OD
13-3/8"
9-5/8"
7"
3-1/2"
Weight
48
40
29
9,2
WT
.330
.395
.408
NA
Grade
H40/J55 STC
L- 80 BTC
L80 LTC
2535 Vam Top
L80 Vam Top:
G3 Vam Top'
Hole Size
17-1/2"
12-1/4"
8 3/4
6"
Depth Set
504'
5.498'
11,014'
10,966'
TOC
Surface
Surface
Surface
NA
Volume
510 sks
2,135 sks
760 sks
NA
LONQUIST & CO. LLC
PETROLEUM
ENER6Y
ENGINEERS
ADVISORS
HOUSTON'CALGARY
AUSTIN I WICHITA I DENVER
Stakeholder Midstream
Country: USA
Location: 33.07884, -103.904514
API No: 42-501-36998
Rattlesnake No. 1
State/Province: Texas
Site:
County/Parish: Yoakum
Survey:
Well Type/Status: AG I
Texas License F-9147
RRC District No:
Project No: LS 128
Date: 5/27/2022
12912 Hill Country Blvd Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Reviewed: SLP
Approved: SLP
Figure 29 - Rattlesnake AG! #1 Well bore Schematic
45
-------
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LONQUIST & CO LLC
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46
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Figure 31 - Penetrating Oil and Gas Wells within the MMA
47
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Future Drilling
Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations, such as the Devonian, have proven to-date to be less productive or non-productive in this area,
which is why the location was selected for injection. Furthermore, any drilling permits issued by the TRRC in
the area of the Rattlesnake AGI #1 well include a list of formations for which oil and gas operators are
required to comply with TRRC Rule 13 (entitled "Casing, Cementing, Drilling, Well Control, and Completion
Requirements"). 16 TAC § 3.13. By way of example, see the Rattlesnake AGI #1 well drilling permit provided
in Appendix B. The Devonian is among the formations listed for which operators in Yoakum County (where
the Rattlesnake #1 is located) are required to comply with TRCC Rule 13 (Appendix B, pg. 5). TRRC Rule 13
requires oil and gas operators to set steel casing and cement across and above all formations permitted for
injection under TRRC Rule 9 or immediately above all formations permitted for injection under Rule 46 for
any well proposed within a one-quarter mile radius of an injection well. In this instance, any new well
permitted and drilled to the Rattlesnake AGI #1 well's injection zone, and located within a one-quarter mile
radius of the Rattlesnake AGI #1 well, will be required under TRRC Rule 13 to set steel casing and cement
above the Rattlesnake AGI #1 well injection zone. Additionally, Rule 13 requires operators to case and
cement across and above all potential flow zones and/or zones with corrosive formation fluids. The TRRC
maintains a list of such known zones by TRRC district and county and provides that list with each drilling
permit issued, which is also shown in the above-mentioned permit in Appendix B.
If any leakage were to be detected, the volume of C02 released will be quantified based on the operating
conditions at the time of release.
Groundwater wells
There are seven groundwater wells located within the MMA, as identified by the Texas Water Development
Board. All of the identified groundwater wells in the area have total depths less than or equal to 265', as
shown in Figure 32 and Table 9. One of the wells is located on the 30-30 facility property with a total depth
of 119'and is operated by Stakeholder.
The surface and intermediate casings of the Rattlesnake AGI #1 well, as shown in Figure 29, are designed to
protect the shallow freshwater aquifers consistent with applicable TRRC regulations and the GAU letter
issued for this location. See GAU letter included within Appendix B. The wellbore casings and cements also
serve to prevent C02 leakage to the surface along the borehole.
A larger scale version of Figure 32 is provided in Appendix F.
48
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-------
Table 9 - Groundwater Well Summary
State Well ID
Owner Name
Primary Use Well Depth Data Source
370449
Frances Barbini
Irrigation
237
SDRDB
443840
Frances Jean Barbini
Irrigation
250
SDRDB
482963
Santa Fe Midstream Permian
Industrial
119
SDRDB
510854
FRANCIS BARNINI
Irrigation
255
SDRDB
520249
Thomas Durham
Irrigation
264
SDRDB
543433
FRANCIS BARBIDI
Irrigation
240
SDRDB
84760
TEXACO PRODUCING INC
TWDB BW
Leakage Through Faults and Fractures
Faults were interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure
12. Faulting in this region terminates vertically below the Pennsylvanian-age rock. Secondary confining
shales within the Wolfcampian and younger strata provide additional, redundant confining layers that would
prevent C02from migrating into freshwater aquifers. None of the mapped faults project above the Wolfcamp
formation; rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. If, in
the unlikely event the faults' sealing properties are compromised post-injection, secondary confinement is
provided by the tight limestones found within the overlying Mississippianan Lime formation and the shale
layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the largest fault found SE of the
Rattlesnake AGI #1 well, terminates within the Atoka formation. Though it crosses the Silurian section, this
fault thrusts the Mississippian Lime upward against the Atoka shales. The tight reservoir characteristics of
the Mississippian Lime and shaley section of the Atoka create a confining environment vertically and laterally
to contain potential upward migration of buoyant fluids. Shales within the Wolfcamp formation provide
additional confining beds between overlying USDWs and the fault plane.
Should an unmapped fault exist within the plume boundary, the offset would be below 3D seismic resolution.
The offset would be less than the thickness of the Woodford shale, juxtaposing the Woodford against itself,
preventing vertical migration.
Fractures and subsequent subaerial exposure are responsible for porosity development within the injection
intervals. Open hole logs show little to no porosity development indicating the Woodford or Mississippian
Lime were not exposed at this location. Upward migration of injected gas through confining bed fractures is
unlikely.
50
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Leakage Through the Confining Layer
The Silurian-Devonian injection zones have competent sealing rocks above and below the porous sub-aerially
exposed carbonate. The properties of the overlying transgressive Woodford shale (widespread deposition,
high illite clay and organic matter composition, and low porosity and permeability) make an excellent sealing
rock to the underlying Silurian formation. Tight Mississippian Lime of roughly 660 ft, lay between Atoka and
Woodford shale formations, forming an impermeable upper seal to the injection interval. Above this
confining unit, correlative shales of the Wolfcamp, Abo and Tubb formations will prevent any upper fluid
migration. These impermeable shales are capped by hundreds of feet of the regionally present Salado
formation evaporites. The USDW lies above the sealing properties of the formations outlined above, making
stratigraphic migration of fluids into the USDW highly unlikely. The underlying low porosity and permeability
Montoya carbonate minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injected gas to the in-situ reservoir fluid makes migration below the lower confining layer
unlikely.
Leakage from Natural or Induced Seismicitv
The location of Rattlesnake AGI #1 is in an area of the Permian Basin that is inactive from a seismicity
perspective, whether induced or natural. A review of historical seismic events on the USGS's Advanced
National Seismic System site (from 1971 to present) and the Bureau of Economic Geology's TexNet catalog
(from 2017 to present), as shown in Figure 33, indicates the nearest seismic event occurred more than 60
miles away.
A regional analysis of the probabilistic fault slip potential across the Permian Basin (Snee & Zoback 2016), as
seen in Figure 34, further demonstrates that the Rattlesnake AGI #1 well is located in a seismically inactive
area and confirms that this area has little to no potential for an induced seismicity event.
Therefore, there is no indication that seismic activity poses a risk for loss of C02 to the surface within the
MMA.
Pressures will be kept significantly below the fracture gradient of the injection and confining intervals.
Additionally, continuous well monitoring combined with seismic monitoring will identify any operational
anomalies associated with a seismicity event.
51
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LLANO E S TAC A DO
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52
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Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI ft1 location (Snee & Zobak 2016)
53
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SECTION 5 - MONITORING FOR LEAKAGE
This section discusses the strategy that Stakeholder 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). 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. Table 10 summarizes the
monitoring of potential leakage pathways to the surface. Monitoring will occur during the planned 17-year
injection period, or cessation of injection operations, plus a proposed 5-year post-injection period.
• Leakage from surface equipment
• Leakage through existing and future wells within MMA
• Leakage through faults , fractures or confining seals
• Leakage through natural or induced seismicity
Because the acid gas injection stream also contains H2S, any leakage would be detected by the H2S alarms
located around the facility and would be quickly addressed which would minimize the release of C02 into the
atmosphere.
Table 10- Summary of Leakage Monitoring Methods
Leakage Pathway
Monitoring Method
Leakage from surface equipment
Fixed H2S monitors throughout the AGI facility
Daily visual inspections
Personal H2S monitors
Distributed Control System Monitoring (Volumes and Pressures)
Leakage through existing wells
Fixed H2S monitor at the AGI well
SCADA Continuous Monitoring at the AGI Well
Annual Mechanical Integrity Tests ("MIT") of the AGI Well
Visual Inspections
Quarterly C02 Measurements within AMA
Leakage through groundwater wells
Annual GroundwaterSamples on Property
Leakage from future wells
H2S Monitoring during offset drilling operations
Leakage through faults and fractures
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage through confining layer
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage from natural or induced
seismicity
Seismic monitoring station to be installed
54
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Leakage from Surface Equipment
As the 30-30 Facility and the Rattlesnake AGI #1 well are designed to handle H2S, leakage from surface
equipment is unlikely to occur and would be quickly detected and addressed. The facility design minimizes
leak points through the equipment used and the type of connections are designed to minimize corrosion
points. The H2S in the injectate serves as a proxy for the release of C02. The facility and well site contain a
number of H2S alarms, set with a high alarm setpoint of 10 ppm of H2S, which are shown in Figure 28 above.
Additionally, all Stakeholder field personnel are required to wear H2S monitors, which trigger the alarm at 5
ppm H2S.
The AGI facility is continuously monitored through automated systems. In addition, field personnel conduct
daily visual field inspections of gauges, monitors and leak indicators such as vapor plumes. The effectiveness
of the internal and external corrosion control program is monitored through the periodic inspection of the
system, analysis of liquids collected from the line, and inspection of the cathodic protection system. These
inspections, in addition to the automated systems, allow Stakeholder to quickly respond to any leakage
situation. Monitoring will occur for the duration of injection and the post-injection period. 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).
Pressures and flowrates 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 at the time, including pressure, flow rate, size of the leak point opening, and duration
of the leak.
Leakage from Existing and Future Wells within MMA
Stakeholder continuously monitors and collects injection volumes, pressures, temperatures and gas
composition data, through their SCADA systems, for the Rattlesnake AGI #1 well. This data is reviewed by
qualified personnel and will follow response and reporting procedures when data is outside acceptable
performance limits. Rattlesnake AGI #1 has a pressure and temperature gauge placed in the injection stream
at its wellhead, and a pressure gauge on the casing annulus. A change of pressure on the annulus would
indicate the presence of a possible leak. Mechanical integrity tests ("MITs") performed annually would also
indicate the presence of a leak. Upon a negative MIT, the well would immediately be isolated and the leak
mitigated.
The ten offset penetrating wells within the MMA are adequately cased and cemented to prevent potential
leakage of C02 from the Rattlesnake AGI #1 well plume. Additionally, the plugged wells were done so in a
way to prevent migration of C02 as provided in Appendix E. As discussed previously, Rule 13 would ensure
that new wells in the field would be constructed in a manner to prevent migration from the injection interval.
In addition to the fixed and personal monitors described previously, Stakeholder will also establish and
operate an in-field monitoring program to detect any C02 leakage within the AMA. The scope of work will
include H2S and C02 monitoring at the AGI well site as well as minimum, quarterly atmospheric monitoring
near identified penetrations within the AMA. Upon approval of the MRV and through the post-injection
monitoring period, Stakeholder will have these monitoring systems in place. Additional monitoring will be
added as the AMA is updated over time.
At the well site, H2S and C02 concentrations will be monitored continuously with fixed monitors that detect
55
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atmospheric concentrations of H2S and C02. At penetrating well sites, Stakeholder will similarly measure
atmospheric concentrations of C02 and H2S using mobile gas monitors. This data will be recorded at least
quarterly.
Groundwater Quality Monitoring
Stakeholder will monitor the groundwater quality in fluids above the confining interval by sampling the well
on the facility property and analyzing the sample with a third-party laboratory on an annual basis. Any
significant changes to the water analysis would be investigated to determine if such change was a result of
leakage from the Rattlesnake AGI #1 well. The parameters to be measured will include pH, total dissolved
solids, total inorganic and organic carbons, density, temperature and other standard laboratory
measurements. Any significant differences in these parameters from the baseline sample will be evaluated
to determine if leakage of C02 to the USDW may have occurred.
Leakage through Faults, Fractures or Confining Seals
Stakeholder continuously monitors the operations of the Rattlesnake AGI #1 well through automated
systems. Any deviation from normal operating conditions indicating movement into a potential pathway
such as a fault or breakthrough of the confining seal would trigger an alert. Any such alert would be reviewed
by field personnel and action taken to shut in the well, if necessary. Field H2S monitoring systems would alert
field personnel for any release of H2S/C02 caused by such leakage.
Leakage through Natural or Induced Seismicitv
While the likelihood of a natural or induced seismicity event is extremely low, Stakeholder plans to install a
seismic monitoring station in the general area of the Rattlesnake AGI #1 well. The installation of this station
would start upon approval of the MRV plan, with an expected in-service data within six months after the
commencement of the installation project. This monitoring station will be tied in to the Bureau of Economic
Geology's TexNet Seismic Monitoring system. If a seismic event of 3.0 magnitude or greater is detected,
Stakeholder will review the injection volumes and pressures at the Rattlesnake AGI #1 well to determine if
any significant changes occur that would indicate potential leakage.
56
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SECTION 6 - BASELINE DETERMINATIONS
This section identifies the strategies Stakeholder will undertake to establish the expected baselines for
monitoring C02 surface leakage per 40 CFR §98.448(a)(4). Stakeholder will use the existing SCADA monitoring
systems to identify changes from expected performance that may indicate leakage of C02.
Visual Inspections
Daily inspections will be conducted by field personnel at the 30-30 Facility and the Rattlesnake AGI #1 well.
These inspections will aid with identifying and addressing issues timely to minimize the possibility of leakage.
If any issues are identified, such as vapor clouds or ice formations, corrective actions would be taken to
address such issues.
H2S Detection
H2S will be initially injected into the AGI well at a concentration of approximately ten (10) percent or 100,000
ppm. The concentration will drop to approximately seven (7) percent as additional volumes are added. H2S
gas detectors are located throughout the AGI facility and well site and are set to trigger the alarm at 10 ppm.
Additionally, all field personnel are required to wear personal H2S monitors, which are set to trigger the alarm
at 5 ppm. Any alarm would trigger an immediate response to protect personnel and verify that the monitors
are working properly. If monitors are working correctly, immediate actions would be taken to secure the
facility and mitigate potential leaks.
CO2 Detection
Any C02 release would be accompanied by H2S and therefore the H2S monitors at the facility would also serve
as a C02 release warning system. In addition to the fixed and personal monitors described previously,
Stakeholder will also establish and operate an in-field monitoring program to detect any C02 leakage within
the AMA. The scope of work will include H2S and C02 monitoring at the AGI well site as well as atmospheric
monitoring near identified penetrations within the AMA.
Operational Data
Upon starting injection operations, baseline measurements of injection volumes and pressures will be taken.
Any significant deviations over time will be analyzed for indication of leakage of C02.
Continuous Monitoring
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as per Texas regulations and Stakeholder's TRRC-
approved H2S Contingency Plan. Gas detectors and continuous monitoring systems would trigger an alarm
upon a release. The mass of the C02 released would be calculated for the operating conditions at the time,
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.
57
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No C02 emissions will occur from venting because of the high H2S concentrations. Blowdown emissions are
sent to flares and would be reported as part of the required reporting for the gas plant.
Groundwater Monitoring
An initial sample will be taken from the groundwater well on Stakeholder's property, identified as Well #
482963 in Table 9 above, upon approval of Stakeholder's MRV and prior to increasing injection. The sample
will be analyzed by a third-party laboratory to establish the baseline properties of the groundwater.
58
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SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE
EQUATION
This section identifies how Stakeholder will calculate the mass of C02 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the C02 emissions from equipment leaks and vented
emissions of C02 between the injection flow meter and the injection well, per 40 CFR §98.448(a)(5).
Mass of CO2 Received
Per 40 CFR §98.443, the mass of C02 received must be calculated using the specified C02 received equations
"unless you follow the procedures in 40 CFR §98.444(a)(4)." 40 CFR §98.444(a)(4) states that "if the C02 you
receive is wholly injected and is not mixed with any other supply of C02, you may report the annual mass of
C02 injected that you determined following the requirements under paragraph (b) of this section as the total
annual mass of C02 received instead of using Equation RR-1 or RR-2 of this subpart to calculate C02 received."
The C02 received for this injection well is wholly injected and not mixed with any other supply and the annual
mass of C02 injected will equal the amount received. Any future streams would be metered separately before
being combined into the calculated stream.
Mass of CO2 Injected
Per 40 CFR §98.444(b), since the flow rate 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:
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 (metric tons per
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682
Cco2,P,u = Quarterly C02 concentration measurement in flow for flow meter u in quarter p (wt. percent
C02, expressed as a decimal fraction)
p = Quarter of the year
u = Flow meter
4
p = 1
where:
quarter)
59
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Mass of CO2 Produced
The Rattlesnake AGI #1 well is not part of an enhanced oil recovery project; therefore, no C02 will be
produced.
Mass of CO2 Emitted by Surface Leakage
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as a major upset event. Gas detectors and continuous
monitoring systems would trigger an alarm upon a release. The mass of the C02 released would be calculated
for the operating conditions at the time, 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 C02 was released as a result 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:
C02 = 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 from subpart W will be used to calculate C02 emissions from equipment located on
the surface between the flow meter used to measure injection quantity and the injection wellhead
Mass of CO2 Sequestered
The mass of C02 sequestered in subsurface geologic formations will be calculated based off Equation RR-12,
as this well will not actively produce oil or natural gas or any other fluids, as follows:
X
X=1
Where:
CO 2 — C02i C02e C02fi
Where:
60
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C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year
CO21 = 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
CO 2fi - 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
CO 2fi will be calculated in accordance with Subpart W reporting of GHGs. Because no venting would occur
due to the high H2S concentrations of the injectate stream, the calculations would be based on the blowdown
emissions that would be sent to flares and would be reported as part of the required GHG reporting for the
gas plant.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
61
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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN
The Rattlesnake AGI #1 well currently reports GHGs under Subpart UU, but Stakeholder has elected to submit
an MRV plan under, and otherwise comply with, Subpart RR. The MRV plan will be implemented upon
receiving EPA approval. The Annual Subpart RR Report will be filed on March 31st of the year following the
reporting year.
62
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SECTION 9 - QUALITY ASSURANCE
This section identifies how Stakeholder plans to manage quality assurance and control, to meet the
requirements of 40 CFR §98.444.
Monitoring QA/QC
C02 Injected
• The flow rate of the C02 being injected will be measured with a volumetric flow meter, consistent
with industry best practices. These flow rates will be compiled quarterly.
• The composition of the C02 stream will be measured upstream of the volumetric flow meter with a
continuous gas composition analyzer or representative sampling consistent with industry best
practices.
• The gas composition measurements of the injected stream will be averaged quarterly.
• The C02 measurement equipment will be calibrated according to manufacturer recommendations.
C02 Emissions from Leaks and Vented Emissions
• Gas detectors will be operated continuously, except for maintenance and calibration.
• Gas detectors will be calibrated according to manufacturer recommendations and API standards.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
Measurement Devices
• Flow meters will be continuously operated except for maintenance and calibration.
• Flow meters will be calibrated according to the requirements in 40 CFR §98.3(i).
• Flow meters will be operated per an appropriate standard method as published by a consensus-
based standards organization.
• Flow meter calibrations will be traceable to the National Institute of Standards and Technology
(NIST).
All measured volumes of C02 will be converted to standard cubic meters at a temperature of 60 degrees
Fahrenheit and an absolute pressure of 1 atmosphere.
Missing Data
In accordance with 40 CFR §98.445, Stakeholder 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 C02 injected is missing, the amount will be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.
• Fugitive C02 emissions from equipment leaks from facility surface equipment will be estimated and
reported per the procedures specified in subpart W of 40 CFR §98.
63
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MRV Plan Revisions
If any of the changes outlined in 40 CFR §98.448(d) occur, Stakeholder will revise and submit an amended
MRV plan within 180 days to the Administrator for approval.
64
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SECTION 10 - RECORDS RETENTION
Stakeholder will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
three years and include:
• Quarterly records of the C02 injected
o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the C02 stream
• Annual records of the information used to calculate the C02 emitted by surface leakage from leakage
pathways.
• Annual records of information used to calculate C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
65
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References
Broadhead, Ronald E., 2005. Regional Aspects of the Wristen petroleum system, southeastern New Mexico:
New Mexico Bureau of Geology and Mineral Resources Open File Report, no. 485.
Comer, John B., 1991. Stratigraphic Analysis of the Upper Devonian Woodford Formation, Permian Basin,
West Texas and Southeastern New Mexico: Bureau of Economic Geology Report of Investigations, no. 201.
George, Peter G., Mace, Robert E., and Petrossian, Rima, 2011. Aquifers of Texas: Texas Water Development
Board Report, no 380.
Hoak, T., Sundberg, K., and Ortoleva, P. Overview of the Structural Geology and Tectonics of the Central Basin
Platform, Delaware Basin, and Midland Basin, West Texas and New Mexico: Department of Energy Open File
Report.
Molina, Oscar, Vilarras, Victor, and Zeidouni, Mehdi, 2016. Geologic carbon storage for shale gas recovery:
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18.
Ruppel, Stephen C. and Holtz, Mark H., 1994. Depositional and Diagenetic Facies Patterns and Reservoir
Development in Silurian and Devonian Rocks of the Permian Basin: Bureau of Economic Geology Report of
Investigations, no. 216.
Snee, Jens-Erik Lund and Zoback, Mark D., 2016. State of stress in the Permian Basin, Texas and New Mexico:
Implications for induced seismicity.
Teeple, Andrew P., Ging, Patricia B., Thomas, Jonathan V., Wallace, David S., and Payne, Jason D., 2021.
Hydrogeologic Framework, Geochemistry, Groundwater-Flow System, and Aquifer Hydraulic Properties Used
in the Development of a Conceptual Model of the Ogallala, Edwards-Trinity (High Plains), and Dockum
Aquifers In and Near Gaines, Terry, and Yoakum Counties, Texas: USGS Scientific Investigations Report 2021-
5009.
66
-------
APPENDICES
-------
APPENDIX A-GEOLOGY
APPENDIX A-l: SILURIAN STRUCTURE MAP
APPENDIX A-2: NE-SW CROSS SECTION
APPENDIX A-3: NW-SE CROSS SECTION
APPENDIX A-4: FORMATION FLUID SAMPLE WELL MAP
-------
-------
mi
LONQU 1ST
SEQUESTRATION L
Stakeholder Midstream
-------
42501105700000
1-667
TEXAS CRUDE OIL CO
42501358340000
ROBERTS UNIT
2
APACHE
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
-------
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
Formation Fluid Sample Wells
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
| DENVER
• COLLEGE STATION |
[ BATON ROUGE • EDMONTON
-J- Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
-------
APPENDIX B -TRRC FORMS Rattlesnake AG I #1
APPENDIX B-l: UIC CLASS II ORDER
APPENDIX B-2: GAU GROUNDWATER PROTECTION DETERMINATION
APPENDIX B-3: DRILLING PERMIT
APPENDIX B-4: COMPLETION REPORT
-------
Christi Craddick, Chairman
Ryan Sitton, Commissioner
Wayne Christian, Commissioner
B-1
Danny Sorrells
Assistant Executive Director
Director, Oil and Gas Division
Leslie Savage
Assistant Director, Technical Permitting
Railroad Commission of Texas
OIL AND GAS DIVISION
PERMIT TO DISPOSE OF NON-HAZARDOUS OIL AND GAS WASTE BY INJECTION INTO A
POROUS FORMATION NOT PRODUCTIVE OF OIL AND GAS
PERMIT NO. 15848
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024
DOCKET NO. 8A-0312019
Authority is granted to inject Non-Hazardous Oil and Gas waste into the well identified herein in accordance
with Statewide Rule 9 of the Railroad Commission of Texas and based on information contained in the
application (Form W-14) dated March 12, 2018 for the permitted interval of the DEVONIAN formation and
subject to the following terms and special conditions:
RATTLESNAKE AGI (000000) LEASE
WASSON FIELD
YOAKUM COUNTY, DISTRICT 8A
WELL II
DENTIFIC ATION AND P]
ERMIT PA]
RAMET]
ERS:
Well No.
API No.
UIC Number
Permitted
Fluids
Top
Interval
(feet)
Bottom
Interval
(feet)
Maximum
Liquid
Daily
Injection
Volume
(BBL/day)
Maximum
Gas Daily
Injection
Volume
(MCF/day)
Maximum
Surface
Injection
Pressure
for Liquid
(PSIG)
Maximum
Surface
Injection
Pressure
for Gas
(PSIG)
1
50136998
000117143
C02, and
H2S
11,000
12,000
4,500
N/A
N/A
2,200
SPECIAL CONDITIONS:
Well No.
API No.
Special Conditions
1
50136998
1. Open hole completions shall have a plug back depth no deeper than the bottom of the
permitted injection interval.
2. The operator shall provide to the UIC section an annotated electric log, and a mud log if
available, of the subject well with the top(s) and bottom(s) of the permitted formation
indicated on the log. Top and bottom of the authorized injection interval may be modified
based on electric log or mud log indications of the top and bottom of the permitted
formations.
1701 NORTH CONGRESS AVENUE * POST OFFICE BOX 12967 * AUSTIN. TEXAS 78711-2967 * PHONE: 512/463-6792* FAX: 512/463-6780
TDD 800/735-2989 OR TDY 512/463-7284 * AN EQUAL OPPORTUNITY EMPLOYER* http://www.rrc.texas.gov
-------
STANDARD CONDITIONS:
1. Injection must be through tubing set on a packer. The packer must be set no higher than 100 feet above the
top of the permitted interval.
2. The District Office must be notified 48 hours prior to:
a. running tubing and setting packer;
b. beginning any work over or remedial operation;
c. conducting any required pressure tests or surveys.
3. The wellhead must be equipped with a pressure observation valve on the tubing and for each annulus.
4. Prior to beginning injection and subsequently after any work over, an annulus pressure test must be
performed. The test pressure must equal the maximum authorized injection pressure or 500 psig, whichever
is less, but must be at least 200 psig. The test must be performed, and the results submitted in accordance
with the instructions of Form H-5.
5. The injection pressure and injection volume must be monitored at least monthly and reported annually on
Form H-10 to the Commission's Austin office.
6. Within 30 days after completion, conversion to disposal, or any work over which results in a change in well
completion, a new Form W-2 or G-l must be filed to show the current completion status of the well. The
date of the disposal well permit, and the permit number must be included on the new Form W-2 or G-l.
7. Written notice of intent to transfer the permit to another operator by filing Form P-4 must be submitted to
the Commission at least 15 days prior to the date of the transfer.
8. This permit will expire when the Form W-3, Plugging Record, is filed with the Commission. Furthermore,
permits issued for wells to be drilled will expire three (3) years from the date of the permit unless drilling
operations have commenced.
Provided further that, should it be determined that such injection fluid is not confined to the approved interval, then
the permission given herein is suspended and the disposal operation must be stopped until the fluid migration from
such interval is eliminated. Failure to comply with all of the conditions of this permit may result in the operator
being referred to enforcement to consider assessment of administrative penalties and/or the cancellation of the
permit.
APPROVED AND ISSUED ON November 14. 2018.
Injection-Storage Permits Unit
IN-HOUSE AMENDMENT TO CORRECT THE RATE.
Note: This document will only be distributed electronically.
PERMIT NO. 15848
Page 2 of 2
-------
GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit
Form GW-2
B-2
Date Issued:
31 August 2017
GAU Number:
179154
Attention:
SANTA FE MIDSTREAM
API Number:
5700 GRANITE PARKWAY
County:
YOAKUM
PLANO, TX 75024
Lease Name:
Roberts Unit
Operator No.:
748093
Lease Number:
Well Number:
Total Vertical Depth:
Latitude:
Longitude:
Datum:
019212
1
11000
33.049990
-102.903464
NAD27
Purpose:
New Drill
Location:
Survey-Gibson, J H/Poole, J T; Block-D; Section-733
To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:
The interval from the land surface to a depth of 375 feet must be protected.
Note: Unless stated otherwise, this recommendation is intended to apply only to the subject well and not for area-wide use.
This recommendation is for normal drilling, production, and plugging operations only. It does not apply to saltwater disposal
operation into a nonproductive zone (RRC Form W-14).
This determination is based on information provided when the application was submitted on 08/30/2017. 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.gov
Rev. 02/2014
-------
APINa 42-501-36998
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
APPLICATION FOR PERMIT TO DRILL, RECOMPLETE, OR RE-ENTER
This facsimile W-l was generated electronically from data submitted to the RRC.
A certification of the automated data is available in the RRC's Austin office.
FORM W-l 07/2004
Drilling Permit #
839303
SWR Exception Case/Docket No.
Permit Status: Approved
B-3
1. RRC Operator No.
748093
2. Operator's Name (as shown on form P-5, Organization Report)
SANTA FE MIDSTREAM PERMIAN LLC
3. Operator Address (include street, city, state, zip):
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
4. Lease Name
RATTLESNAKE AGI
5. Well No.
1
GENERAL INFORMATION
6. Purpose of filing (mark ALL appropriate boxes): Ix] New Drill EH Recompletion EH Reclass EH Field Transfer EH Re-Enter
EH Amended EH Amended as Drilled (BHL) (Also File Form W-1D)
7. Wellbore Profile (mark ALL appropriate boxes): 0 Vertical EH Horizontal (Also File Form W-1H) EH Directional (Also File Form W-1D) EH Sidetrack
8. Total Depth
12000
9. Do you have the right to develop the [x] - | |
minerals under any right-of-way ?
10. Is this well subject to Statewide Rule 36 (hydrogen sulfide area)? IS Yes EH \0
SURFACE LOCATION AND ACREAGE INFORMATION
11. RRC District No.
8A
12. County I—, ,—, ,—, ,—¦
YOAKUM 13. Surface Location LXI Land 1—1 Bay/Estuary 1—1 Inland Waterway 1—1 Offshore
14. This well is to be located miles in a NW direction from DENVER CITY which is the nearest town in the county of the well site.
15. Section 16. Block 17. Survey 18. Abstract No.
733 D GIBSON, J H A-89
19. Distance to nearest lease line:
200 ft-
20. Number of contiguous acres in
lease, pooled unit, or unitized tract: 640
21. Lease ]
22. Survey
'erpendiculars: 200 ft from the NORTH line and 200 ft froi
nt
nt
ie WEST line.
PprppiiHii^iilars" 200 ft from the NORTH line and 200 ft froi
le WEST line.
23. Is this a pooled unit? EH Yes B No 24. Unitization Docket No:
25. Are you applying for Substandard Acreage Field? EH Yes (attach Form W-1A) S No
FIELD INFORMATION List all fields of anticipated completion including Wildcat. List one zone per line.
26. RRC
District No.
27. Field No.
28. Field Name (exactly as shown in RRC records)
29. Well Type
30. Completion Depth
31. Distance to Nearest
Well in this Reservoir
32. Number of Wells on
this lease in this
Reservoir
8A
95397001
WASSON
Injection Well
12000
0.00
1
8A
95399400
WASSON, NORTH (SAN ANDRES)
Injection Well
12000
0.00
1
BOTTOMHOLE LOCATION INFORMATION is required for DIRECTIONAL, HORIZONTAL, AND AMENDED AS DRILLED PERMIT APPLICATIONS
Remarks
[FILER Apr 16, 2018 5:16 PM]: Filing for an acid gas injection well.
Certificate:
I certify that information stated in this application is true and complete, to the
best of my knowledge.
Jessica Risien, Regulatory Compliance
Specialist Apr 25, 2018
Name of filer Date submitted
(281)8729300 jrisien@ntglobal.com
Phone E-mail Address (OPTIONAL)
RRC Use Only Data Validation Time Stamp: Apr 27, 2018 10:36 AM( As Approved' Version )
Page 1 of 1
-------
NOTE: Acreages shown hereon ere based on Information provided by others.
This plat represents a staked well location and does not represent a boundary survey.
The Information shown does not meet the current TBPLS minimum standards for boundary
surveys. Limited field measurements were acquired. Lease and tract line Information is
compiled from record information and additional sources.
NOTES:
1)
2)
3-J
ALL BEARINGS. DISTANCES ANO COORDINATES SHOWN
HEREON WERE DERIVED FROM <3. P S. OBSERVATIONS
CONVERTED TO THE TEXAS COORDINATE SYSTEM,
NORTH CENTRAL ZONE (NAD 1993). US FOOT AND ARE
REFERENCED TO THE LOCAL GNSS RTK NETWORK.
THE PROPOSED WELL LOCATION IS SITUATED N 37~W -
7.3 MILES FROM DENVER CITY, TX.
THE PROPOSED WELL LOCATION IS SITUATED SOW FROM
THE NSL AND 200 FROM THE WSL.
6
5°X'
rC-< liw
SECTION 704. BLOCK D
J. H. GIBSON SURVEY-
ABSTRACT NO. 1144
YOAKUM COUNTY. TX
704
733
RA TTLESMAKE AGf No.
(PROPOSED)
.0^
SURFACE L OCA T/ON
NAD 83, TX-NC, U.S. FT.
NORTH/NG/Y; 7093713.4ST
EASTING/X 619409-13"
LATITUDE (DDJ- 33.05134722°
LONGITUDE (DO)- -102.90450555*
NAD 27, TX-NC, US- FT,
NORTHfNG/Y: 546285.34*
EAST/NG/X; 344968.61'
LA TTTUDE (DO)- 33.05124473"
LONGITUDE (DO)- -102.90401331°
SURFACEELEVA T/ON- 3627.05-
732
*
83^8
2
5>^0
S
Af /=>&?AfMA/LLG
rtATTL£SA/j4/C£-s4G/A/o. 7
*/.M. G/&SOA/ SURWEK
SEGT/OA/ 733, &LOC/C0
yOAKt/AS GCHSA/TX TjEXAS
m Y aHcmws80i*a,7x:7B>
IhtebkityRk
i ] Positions, llc
-------
Railroad Commission of Texas
PERMIT TO DRILL, RE-COMPLETE, OR RE-ENTER ON REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
CONDITIONS AND INSTRUCTIONS
Permit Invalidation. It is the operator's responsibility to make sure that the permitted location complies with Commission density and
spacing rules in effect on the spud date. The permit becomes invalid automatically if, because of a field rule change or the drilling of another
well, the stated location is not in compliance with Commission field rules on the spud date. If this occurs, application for an exception to
Statewide Rules 37 and 38 must be made and a special permit granted prior to spudding. Failure to do so may result in an allowable not being
assigned and/or enforcement procedures being initiated.
Notice Requirements. Per H.B 630, signed May 8,2007, the operator is required to provide notice to the surface owner no later than the
15th business day after the Commission issues a permit to drill. Please refer to subchapter Q Sec. 91.751-91.755 of the Texas Natural
Resources Code for applicability.
Permit expiration. This permit expires two (2) years from the date of issuance shown on the original permit. The permit period will not
be extended.
Drilling Permit Number. The drilling permit number shown on the permit MUST be given as a reference with any notification to the
district (see below), correspondence, or application concerning this permit.
Rule 37 Exception Permits. This Statewide Rule 37 exception permit is granted under either provision Rule 37 (h)(2)(A) or 37(h)(2)(B).
Be advised that a permit granted under Rule 37(h)(2)(A), notice of application, is subject to the General Rules of Practice and Procedures
and if a protest is received under Section 1.3, "Filing of Documents," and/or Section 1.4, "Computation of Time," the permit may be deemed
invalid.
Before Drilling
Fresh Water Sand Protection. The operator must set and cement sufficient surface casing to protect all usable-quality water, as defined by
the Railroad Commission of Texas (RRC) Groundwater Advisory Unit (GWAU). Before drilling a well, the operator must obtain a letter from
the Railroad Commission of Texas stating the depth to which water needs protection, Write: Railroad Commission of Texas, Groundwater
Advisory Unit (GWAU), P.O. Box 12967, Austin, TX 78711-3087. File a copy of the letter with the appropriate district office.
Accessing the Well Site. If an OPERATOR, well equipment TRANSPORTER or WELL service provider must access the well site from a
roadway on the state highway system (Interstate, U.S. Highway, State Highway, Farm-to-Market Road, Ranch-to-Market Road, etc.), an
access permit is required from TxDOT. Permit applications are submitted to the respective TxDOT Area Office serving the county where the
well is located.
Water Transport to Well Site. If an operator intends to transport water to the well site through a temporary pipeline laid above
ground on the state's right-of-way, an additional TxDOT permit is required. Permit applications are submitted to the respective
TxDOT Area Office serving the county where the well is located.
^NOTIFICATION
The operator is REQUIRED to notify the district office when setting surface casing, intermediate casing, and production casing, or when
plugging a dry hole. The district office MUST also be notified if the operator intends to re-enter a plugged well or re-complete a well into a
different regulatory field. Time requirements are given below. The drilling permit number MUST be given with such notifications.
During Drilling
Permit at Drilling Site : A copy of the Form W-l Drilling Permit Application, the location plat, a copy of Statewide Rule 13
alternate surface casing setting depth approval from the district office, if applicable, and this drilling permit must be kept at the
permitted well site throughout drilling operations.
*Notification of Setting Casing : The operator MUST call in notification to the appropriate district office (phone number shown the
on permit) a minimum of eight (8) hours prior to the setting of surface casing, intermediate casing, AND production casing. The
individual giving notification MUST be able to advise the district office of the drilling permit number.
*Notification of Re-completion/Re-entry : The operator MUST call in notification to the appropriate district office (phone number
shown on permit) a minimum of eight (8) hours prior to the initiation of drilling or re-completion operations. The individual giving
notification MUST be able to advise the district office of the drilling permit number.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 1 of 5
-------
Completion and Plugging Reports
Hydraulic Fracture Stimulation using Diesel Fuel: Most operators in Texas do not use diesel fuel in hydraulic fracturing fluids.
Section 322 of the Energy Policy Act of 2005 amended the Underground Injection Control (UIC) portion of the federal Safe Drinking Water
Act (42 USC 300h(d)) to define "underground Injection" to EXCLUDE " ...the underground injection of fluids or propping agents (other
than dieselfluels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities." (italic and underlining
added.) Therefore, hydraulic fracturing may be subject to regulation under the federal UIC regulations if diesel fuel is injected or used as a
propping agent. EPA defined "diesel fuel" using the following five (5) Chemical Abstract Service numbers: 68334-30-5 Primary Name: Fuels,
diesel; 68476-34-6 Primary Name: Fuels, diesel, No. 2; 68476-30-2 Primary Name: Fuel oil No. 2; 68476-31-3 Primary Nmae: Fuel oil, No.
4; and 8008-20-6 Primary Name: Kerosene. As a result, an injection well permit would be required before performing hydraulic fracture
stimulation using diesel fuel as defined by EPA on any well in Texas. Hydraulic fracture stimulation using diesel fuel as defined by EPA on a
well in Texas without an injection well permit could result in enforcement action.
Producing Well: Statewide Rule 16 states that the operator of a well shall file with the Commission the appropriate completion report
within thirty (30) days after completion of the well or within ninety (90) days after the date on which the drilling operation is completed,
whichever is earlier. Completion of the well in a field authorized by this permit voids the permit for all other fields included in the permit
unless the operator indicates on the initial completion report that the well is to be a dual or multiple completion and promptly submits an
application for multiple completion. All zones are required to be completed before the expiration date on the existing permit. Statewide Rule
40(d) requires that upon successful completion of a well in the same reservoir as any other well previously assigned the same acreage,
proration plats and P-15s (if required) must be submitted with no double assignment of acreage.
Dry or Noncommercial Hole : Statewide Rule 14(b)(2) prohibits suspension of operations on each dry or non-commercial well without
plugging unless the hole is cased and the casing is cemented in compliance with Commission rules. If properly cased, Statewide Rule 14(b)(2)
requires that plugging operations must begin within a period of one (1) year after drilling or operations have ceased. Plugging operations must
proceed with due diligence until completed. An extension to the one-year plugging requirement may be granted under the provisions stated in
Statewide Rule 14(b)(2).
Intention to Plug : The operator must file a Form W-3 A (Notice of Intention to Plug and Abandon) with the district office at least five (5)
days prior to beginning plugging operations. If, however, a drilling rig is already at work on location and ready to begin plugging operations,
the district director or the director's delegate may waive this requirement upon request, and verbally approve the proposed plugging
procedures.
*Notification of Plugging a Dry Hole : The operator MUST call in notification to the appropriate district office (phone number shown on
permit) a minimum of four (4) hours prior to beginning plugging operations. The individual giving the notification MUST be able to advise
the district office of the drilling permit number and all water protection depths for that location as stated in the Texas Commission on
Environmental Quality letter.
DIRECT INQUIRIES TO: DRILLING PERMIT SECTION, OIL AND GAS DIVISION
PHONE
(512) 463-6751
MAIL:
PO Box 12967
Austin, Texas, 78711-2967
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 2 of 5
-------
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
PERMIT TO DRILL, DEEPEN, PLUG BACK, OR RE-ENTER ON A REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
PERMIT NUMBER
839303
DATE PERMIT ISSUED OR AMENDED
04/27/2018
DISTRICT
8A
API NUMBER
42-501-36998
FORM W-l RECEIVED
04/25/2018
COUNTY
YOAKUM
TYPE OF OPERATION
New Drill
WELLBORE PROFILE(S)
Vertical
ACRES
640.0
OPERATOR 748093
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
NOTICE
This permit and any allowable assigned may
be revoked if payment for fee(s) submitted to
the Commission is not honored.
District Office Telephone No:
(806) 698-6509
LEASE NAME
RATTLESNAKE AGI
WELL NUMBER
1
LOCATION
7.3 miles NW direction from DENVER CITY
TOTAL DEPTH
12000
Section, Block and/or
SECTION 733 BLOCK D ABSTRACT 89
SURVEY GIBSON, J H
DISTANCE TO SURVEY LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST LEASE LINE
200.0
DISTANCE TO LEASE LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST WELL ON LEASE
See FIELD(s) Below
FIELD(s) and LIMITATIONS:
* SEE FIELD DISTRICT FOR REPORTING PURPOSES *
FIELDNAME ACRES DEPTH WELL# DIST
LEASE NAME NEAREST LEASE NEAREST WELL
WASSON "640!0 12000 1 8A
RATTLESNAKE AGI 200 0 0.0
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
WASSON, NORTH (SAN ANDRES) "64o!o 12000 1 8A
RATTLESNAKE AGI 200.0 0.0
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 3 of 5
-------
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
THE FOLLOWING RESTRICTIONS APPLY TO ALL FIELDS
This well shall be completed and produced in compliance with applicable special field or statewide spacing and density rules. If this well is
to be used for brine mining, underground storage of liquid hydrocarbons in salt formations, or underground storage of gas in salt formations,
a permit for that specific purpose must be obtained from Environmental Services prior to construction, including drilling, of the well in
accordance with Statewide Rules 81, 95, and 97.
This well must comply to the new SWR 3.13 requirements concerning the isolation of any potential flow zones and zones with corrosive
formation fluids. See approved permit for those formations that have been identified for the county in which you are drilling the well in.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 4 of 5
-------
Railroad Commission of Texas
Oil and Gas Division
SWR #13 Formation Data
YOAKUM (501) COUNTY
l-'oniiiilioii
Koniiirks
Order
I.ITcc(i\c
Diilo
RED BED-SANTA ROSA
1
01/01/2014
YATES
2
01/01/2014
SAN ANDRES
high flows, H2S, corrosive
3
01/01/2014
GLORIETA
4
01/01/2014
CLEARFORK
Active C02 Flood
5
01/01/2014
WICHITA
6
01/01/2014
LEONARD
7
01/01/2014
WOLFCAMP
8
01/01/2014
PENNSYLVANIAN
9
01/01/2014
STRAWN
10
01/01/2014
MISSISSIPPIAN
11
01/01/2014
DEVONIAN
12
01/01/2014
DEVONIAN-SILURIAN
13
01/01/2014
The above list may not be all inclusive, and may also include formations that do not intersect all wellbores. The listing order of the Formation
information reflects the general stratigraphic order and relative geologic age. This is a dynamic list subject to updates and revisions. It is the
operator's responsibility to make sure that at the time of spudding the well the most current list is being referenced. Refer to the RRC website
at the following address for the most recent information, http://www.rrc.texas.gov/oil-gas/compliance-enforcement/rule-13-geologic-
formation-info
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 5 of 5
-------
B-4
RAILROAD COMMISSION OF TEXAS Form G-1
1701 N. Congress Status: Approved
P.O. Box 12967 Date: 07/25/2019
Austin, Texas 78701-2967 Tracking No.: 205926
GAS WELL BACK PRESSURE TEST, COMPLETION OR RECOMPLETION REPORT, AND LOG
OPERATOR INFORMATION
Operator Name: santa fe midstream permian llc Operator No.: 748093
Operator Address: 5830 granite pkwy ste 1025 plano, tx 75024-0000
WELL INFORMATION
API No.: 42-501-36998
County: YOAKUM
Well No.: 1
RRC District No.: 8A
Lease Name: RATTLESNAKE AG I
Field Name: WASSON
RRC Gas ID No.: 286838
Field No.: 95397001
Location: Section: 733, Block: D, Survey: GIBSON, J H, Abstract: 89
Latitude:
Longitude:
This well is located 7.3 miles in a nw
direction from Denver city,
which is the nearest town in the county.
FILING INFORMATION
Purpose of filing: Well Record Only
Type of completion: New Well
Well Type: Active UIC
Completion or Recompletion Date: 08/31/2018
Type of Permit
Date Permit No.
Permit to Drill, Plug Back, or Deepen
04/27/2018 839303
Rule 37 Exception
Fluid Injection Permit
O&G Waste Disposal Permit
11/14/2018 15848
Other:
COMPLETION INFORMATION
ISpud date: 07/16/2018
Date of first production after rig released: 08/31/2018 I
Date plug back, deepening, recompletion, or Date plug back, deepening, recompletion, or
drilling operation commenced: 07/16/2018
drilling operation ended: 08/31/2018
Number of producing wells on this lease in
Distance to nearest well in lease &
this field (reservoir) including this well:
1 reservoir (ft.): 0.0
Total number of acres in lease: 640.00
Elevation (ft.): 3627 GR
Total depth TVD (ft.): 11980
Total depth MD (ft.):
Plug back depth TVD (ft.): 11980
Plug back depth MD (ft.):
Was directional survey made other than
Rotation time within surface casing (hours): 72.0
inclination (Form W-12)? Yes
Is Cementing Affidavit (Form W-15) attached? Yes
Recompletion or reclass? No
Multiple completion? No
Type(s) of electric or other log(s) run: Combo of Induction/Neutron/Density/Sonic
Electric Log Other Description:
Location of well, relative to nearest lease boundaries Off Lease: No
of lease on which this well is located:
200.0 Feet from the North Line and
200 0 Feet from the West Line of the
rattlesnake agi Lease.
FORMER FIELD (WITH RESERVOIR) & GAS ID OR OIL LEASE NO.
Field & Reservoir
Gas ID or Oil Lease No. Well No. Prior Service Type
Page 1 of4
-------
G1: N/A
PACKET: N/A
FOR NEW DRILL OR RE-ENTRY, SURFACE CASING DEPTH DETERMINED BY:
GAU Groundwater Protection Determination Depth (ft.): 2025.0 Date: 01/12/2018
SWR 13 Exception Depth (ft.):
GAS MEASUREMENT DATA
I Date of test: Gas measurement method(s):
Gas production during test (MCF):
Was the well preflowed for 48 hours? No
Orif. or 24 hr. Coeff.
Run Line Choke Orif. Or Choke Static Pm or Diff
No. size Size (in.) (in.) Choke (in.) (hw)
Flow
Temp Temp. Gravity
(°F) (l-tt) (hg)
Compress
(Fpv)
Volume
(MCF/day)
N/A
FIELD DATA AND PRESSURE CALCULATIONS
Gravity (dry gas):
Gas-Liquid Hydro Ratio (CF/Bbl):
Avg. shut in temp. (°F):
Gravity (liquid hydrocarbons) (Deg. API):
Gravity (mixture): Gmix=
Bottom hole temp, and depth: °F@ ft
Run No. Time of Run (Min.)
Choke Size (in.) Wellhead Pressure (PSIA) Wellhead Flow Temp (°F )
N/A
CASING RECORD
Casing Hole Setting Multi - Multi - Cement Slurry Top of TOC
Type of
Size
Size
Depth Stage Tool Stage Shoe Cement Amount Volume Cement Determined
Row Casing
(in.)
(in.)
(ft.)
Depth (ft.) Depth (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
1 Surface
13 3/8
17 1/2
504
c
510
687.5
0
Circulated to Surface
3 Intermediate
9 5/8
12 1/4
5498
5498
c
485
797.0
4275
Circulated to Surface
2 Intermediate
13 3/8
17 1/2
5498
4275
c
1650
3045.0
0
Circulated to Surface
6 Conventional Production
7
8 3/4
11023
WELL
60
337.0
9575
Calculation
LOCK
5 Conventional Production
7
8 3/4
11023
5591
PREM
380
906.5
0
Circulated to Surface
PLUS
4 Conventional Production
7
8 3/4
11023
9575
PREM
380
906.5
5591
Calculation
PLUS
LINER RECORD
Cement
Slurry
Top of
TOC
Liner Hole
Liner
Liner
Cement
Amount
Volume
Cement
Determined
Row Size (in.) Size (in.)
Top (ft.)
Bottom (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
N/A
TUBING RECORD
Row
Size (in.)
Depth Size (ft.)
Packer Depth (ft.)/Type
1
3 1/2
10966
10966 / HALLIBURTON
BWD
PRODUCING/INJECTION/DISPOSAL INTERVAL
Row
Open hole?
From (ft.)
To (ft.)
1
Yes
L 11025
11980
Page 2 of4
-------
ACID, FRACTURE, CEMENT SQUEEZE,
CAST IRON BRIDGE PLUG, RETAINER, ETC.
Was hydraulic fracturing treatment performed? No
Is well equipped with a downhole actuation
sleeve? No
If yes, actuation pressure (PSIG):
Production casing test pressure (PSIG) prior to
Actual maximum pressure (PSIG) during hydraulic
hydraulic fracturing treatment:
fracturing:
Has the hydraulic fracturing fluid disclosure been
reported to FracFocus disclosure registry (SWR29)?
No
Row Type of Operation Amount and Kind of Material Used Depth Interval (ft.)
N/A
FORMATION RECORD
Is formation
Formations Encountered Depth TVD (ft.) Depth MP (ft.) isolated? Remarks
YATES
Yes
3019.0
Yes
SAN ANDRES - HIGH FLOWS, H2S,
Yes
4465.0
Yes
CORROSIVE
GLORIETA
Yes
6316.0
Yes
CLEARFORK - ACTIVE C02 FLOOD
Yes
6492.0
Yes
WICHITA
Yes
8628.0
Yes
UPPER WOLFCAMP
Yes
9239.0
Yes
STRAWN
Yes
10030.0
Yes
ATOKA
Yes
10230.0
Yes
WOODFORD
Yes
10973.0
Yes
DEVONIAN
Yes
11036.0
No
DISPOSAL
WRISTEN
Yes
11268.0
No
DISPOSAL
FUSSELMAN
Yes
11538.0
No
DISPOSAL
MONTOYA
Yes
11974.0
No
DISPOSAL
RED BED-SANTA ROSA
No
No
NOT IN AREA
LEONARD
No
No
NOT IN AREA
WOLFCAMP
No
No
NOT IN AREA
PENNSYLVANIAN
No
No
NOT IN AREA
STRAWN
No
No
NOT IN AREA
MISSISSIPPIAN
No
No
NOT IN AREA
Do the producing interval of this well produce H2S with a concentration in excess of 100 ppm (SWR 36)? No
s the completion being downhole commingled (SWR 10)? No
REMARKS
NEW WELL PUTTING ON SCHEDULE.
Page 3 of4
-------
OPERATOR'S CERTIFICATION
Printed Name: Karen Zornes
Title:
Telephone No.: (281) 872-9300
Date Certified: 06/25/2019
Page 4 of4
-------
APPENDIX C - GAS COMPOSITION
-------
C-1
1 rv » n,,
natural Gas Analysis
www.permianls.com
575.397.3713 2609 W Marland HobbS NM 88240
11093G
30/30 Acid Gas
Sample Point Code
Sample Point Name
C6+ Gas Analysis Report
30/30 Acid Gas
Sample Point Location
Laboratory Services
Date Sampled
2021048523
1781
E Benavides - Spot
Source Laboratory
Lab File No
Container Identity
Sampler
USA
USA
USA
Texas
District
Area Name
Field Name
Facility Name
Nov 16, 2021
Nov 16, 2021
Nov 19, 2021 09:59
Nov 19, 2021
Date Effective
System Administrator
Ambient Temp (°F)
Flow Rate (Mcf)
Analyst
Date Received
21 @ 129
Press PSI @ Temp °F
Source Conditions
Date Reported
Stakeholder Midstream
30/30
Operator
Lab Source Description
Component
Normalized
Mol %
Un-Normalized
Mol %
GPM
H2S (H2S)
9.2000
9.2
Nitrogen (N2)
0.0000
0
C02 (C02)
89.6780
98.775
Methane (CI)
0.3030
0.331
Ethane (C2)
0.0580
0.063
0.0150
Propane (C3)
0.1080
0.118
0.0300
I-Butane (IC4)
0.0000
0
0.0000
N-Butane (NC4)
0.0250
0.027
0.0080
I-Pentane (IC5)
0.0000
0
0.0000
N-Pentane (NC5)
0.0000
0
0.0000
Hexanes Plus (C6+)
0.6280
0.686
0.2710
TOTAL
100.0000
109.2000
0.3240
Method(s): Gas C6+ - GPA 2261, Extended Gas - GPA 2286, Calculations - GPA 2172
Analyzer Information
Device Type: Gas Chromatograph Device Make: Shimadzu
Device Model: GC-2014 Last Cal Date: Nov 14, 2021
Gross Heating Values (Real, BTU/ft3)
14.696 PSI @ 60.00 A°F 14.65 PSI @ 60.00 A°F
Dry Saturated Dry Saturated
98.7 98.00 98.4 97.7
Calculated Total Sample Properties
GPA2145-16 Calculated at Contract Conditions
Relative Density Real Relative Density Ideal
1.5042 1.4956
Molecular Weight
43.3157
C6 - 60.000%
C6+ Group Properties
Assumed Composition
C7 - 30.000%
C8 - 10.000%
Field H2S
92000 PPM
PROTREND STATUS: DATA SOURCE:
Passed By Validator on Nov 21, 2021 Imported
PASSED BY VALIDATOR REASON:
Close enough to be considered reasonable.
VALIDATOR:
Dustin Armstrong
VALIDATOR COMMENTS:
OK
Nov 22, 2021 7:57 a
Powered By ProTrend -www.criticalcontrol.com
Page 1 of 1
-------
APPENDIX D - MONITORING AREA MAPS
APPENDIX D-l: MMA MAP
APPENDIX D-2: AMA MAP
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
1560
-------
APPENDIX E - FACILITY SAFETY PLOT PLANS
-------
PLANT NORTH
LEGEND
•
FIRE EXTINGUISHER
~
SCBA/ESCAPE PACK
~
WIND SOCK
®
LEL/H2S MONITOR
ESD BUTTON
H
STROBE LIGHTS
HORN
E-1
r
i| 1 | |—1 l\ 71 1 k 1 A 1 \ W—1 / \ 1 1
—\
JKI 1 IMINAKY 1 ()l>
pn/ic\A/
0
NO.
05/11 / 22
DATE
INITIAL RELEASE K C V 1 C V V
REVISION DESCRIPTION
KLD
BY
BEC
FCE
JB
CLIENT
CHAR1S ENGINEERING. LLC
"IX ENG. FIRM NO. F-1B8B4
MIDLAND. IX
STAKEHOLDER
MIDSTREAM
CLIENT ;
PROJECT ;
TITLE :
STAKEHOLDER MIDSTREAM
30-30 GAS PLANT
SAFETY EQUIPMENT PLOT PLAN
1" = 50'—0"
DATE
5/11/22
ME—PLNP—AOOO—0004
A
-------
APPENDIX F - MMA/AMA REVIEW MAPS
APPENDIX F-l: PLUME BOUNDARY AT END OF INJECTION, STABILIZED PLUME BOUNDARY AND MAXIMUM
MONITORING AREA MAP
APPENDIX F-2: ACTIVE MONITORING AREA MAP
APPENDIX F-3: OIL AND GAS WELLS WITHIN THE MMA MAP
APPENDIX F-4: OIL AND GAS WELLS WITHIN THE MMA LIST
APPENDIX F-5: INJECTION INTERVAL PENETRATING WELLS WITHIN THE MMA MAP
APPENDIX F-6: GROUNDWATER WELLS WITHIN THE MMA
APPENDIX F-7: WELLBORE SCHEMATICS FOR INJECTION INTERVAL PENETRATING WELLS
-------
A-1143
A-545
A-1866
A-572
A-£ 58
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
A-1314
A-549
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
J Plume Boundary at End of Injection
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-2
Rattlesnake AGI No. 1 SHL
1 Active Monitoring Area Boundary
1 9-Year Plume
J Plume Boundary at End of Injection
Abstract
Note: All coordinates shown are in NAD83 (DD).
MAP EXTENT
~
-------
A-1866
A-1314
iiiiiiiiij
36998 l\
RATTLESNAKE AGI NO
33.0513499,1
-102.90450576
00000
32541
00261
32531
00000
iiiiiiiiii
00000"
00000
00262
000
\ 00645 •
00050
00643s
00644
00000
33349.
33530
00057
33173
32702
34984\
32065
00059
33172
33531
A-1484
33531'
32703
33351
32064
,00061
00000
00060
00058
32704
33 no 3
00065
00068
00064
^067 ^
32945
32975
32077
32075
: 30600
32076
36156
00267
00266
00066 3271 i
00063
02992
02991
02990
02989 35820
A-1816
34878
32070
36155
36151 30604 35791 30602
30606
JO fyy
36152
35821
30630
32072
36153
30601
30605
35794
35793 30598
36150
30603
36048
36154
35180
35703
35701
35705
30000
=3058.4;
32270
33065
1:34099;
00755
30583
30629
35961'
34797
56428 00000
• °l
36098
-34023 •
00768J
34124
30580
36327
33843
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
+ Rattlesnake AC I No. 1 SHL
| ~ ~ ™ 1/2-Mile Buffer from Max. Plume Extent (MMA)
I ~ Z Z Z Combined Maximum Plume Extent
1 Stabilized Plume
I ~ ~ ~ Z Plume Boundary at End of Injection
Abstract
Lateral (21)
API (42-501-...) SHL Status - Type (Count)
O Horizontal Surface Location (21)
• Active - Oil (93)
Active - Injection/Disposal (21)
•» Active - Injection/Disposal from Oil (22)
X Plugged - Oil (69)
^ Plugged - Gas (1)
Plugged- Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal (3)
TA - Injection/Disposal from Oil (7)
"0" Dry Hole (6)
o Permitted Location (2)
0 Canceled/Abandoned Location (6)
X Expired Permit (7)
API (42-501-...) BHL Status - Type (Count)
• Active - Oil (11)
•A Active - Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal from Oil (1)
o Permitted Location (4)
X Expired Permit (3)
Sou rce:
1.) Oil/Cas Well SHL Data: DI-2022
2.) Oil/Cas Well BHL Data: DI-2022
3.) Oil/Cas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD). *
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
1
A-1531
A-1064
A-87
A-1483
A-1641
A-499
VI55 !
i .-1777
A
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
F-4
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101829
DENVER UNIT
2215W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5300
5300
2215W
4250101835
DENVER UNIT
2207
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5185
5185
2207
4250130914
DENVER UNIT
2222
OCCIDENTAL PERMIAN LTD.
Active - Oil
2222
4250101832
DENVER UNIT
2201W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5190
5190
2201W
4250101826
DENVER UNIT
2203
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2203
4250101319
ROBERTS UNIT
4532W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5200
5200
4532W
4250130629
ROBERTS UNIT
4535
APACHE CORPORATION
Active - Oil
5280
5280
4535
4250130583
ROBERTS UNIT
4525
APACHE CORPORATION
Active - Oil
5286
5286
4525
4250101318
ROBERTS UNIT
4541
APACHE CORPORATION
TA - Injection/Disposal from Oil
5240
5240
4541
4250101889
ROBERTS UNIT
3614
APACHE CORPORATION
Plugged - Oil
5180
5180
3614
4250130598
Roberts Unit
3647
APACHE CORPORATION
Plugged - Oil
5281
5281
3647
4250130603
ROBERTS UNIT
3626
APACHE CORPORATION
Plugged - Oil
5289
5289
3626
4250102992
ROBERTS UNIT
3612W
APACHE CORPORATION
Plugged - Oil
5226
5226
3612W
4250100066
ROBERTS UNIT
3532
APACHE CORPORATION
Plugged - Oil
5231
5231
3532
4250101886
ROBERTS UNIT
3631
APACHE CORPORATION
Plugged - Oil
3631
4250101885
ROBERTS UNIT
3641
APACHE CORPORATION
Plugged - Oil
5212
5212
3641
4250100068
ROBERTS UNIT
3521
APACHE CORPORATION
Plugged - Oil
5225
5225
3521
4250100064
ROBERTS UNIT
3541
APACHE CORPORATION
Plugged - Oil
5264
5264
3541
4250102014
ROBERTS UNIT
2443
APACHE CORPORATION
Plugged - Oil
5226
5226
2443
4250100050
ROBERTS UNIT
1654
APACHE CORPORATION
Plugged - Oil
5198
5198
1654
4250133531
ROBERTS UNIT
2443A
Active - Injection/Disposal
5325
5325
2443A
4250133502
ROBERTS UNIT
2527A
Plugged - Oil
5308
5308
2527A
4250100000
C. A. ELLIOTT
6
AMERICAN LIBERTY OIL CO
Plugged - Oil
5229
5229
6
4250100000
C. A. ELLIOTT
7
AMERICAN LIBERTY AND ATLANTIC
Active - Oil
5182
5182
7
4250100000
GEO CLEVELAND
1
DELFERN OIL CO
Dry Hole
5071
5071
1
4250100000
JAMES H. LYNN
1614
AMERICAN LIBERTY
Active - Oil
5169
5169
1614
4250100000
J. H. LYNN
1634
AMERICAN LIBERTY
Active - Oil
5160
5160
1634
4250100000
A. T. MORRIS
1
ATLANTIC
Active - Oil
5235
5235
1
4250100000
A. T. MORRIS
2
AMERICAN LIBERTY OIL CO
Plugged - Oil
5179
5179
2
4250100000
W.J. CARPENTER
1642
AMERICAN LIBERTY OIL COMPANY
Plugged - Oil
5183
5183
1642
4250100000
E.S.SMITH
1
CREAT WESTERN FROD
Dry Hole
5216
5216
1
4250130607
ROBERTS UNIT
3546
Active - Oil
3546
4250135958
DENVER UNIT
2247
OCCIDENTAL PERMIAN LTD.
Active - Oil
2333
2333
2247
4250131542
DENVER UNIT
2229
SHELL OIL COMPANY
Dry Hole
2409
2409
2229
4250101320
ROBERTS UNIT
4543
APACHE CORPORATION
Active - Injection/Disposal from Oil
5120
5120
4543
4250137301
MILLER
8H
AMTEX ENERGY, INC.
Active - Oil
5157
5157
8H
4250137304
MILLER 732 C
10H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
10H
4250137305
MILLER 732 D
11H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
11H
4250101888
ROBERTS UNIT
3634W
APACHE CORPORATION
Plugged - Oil
5160
5160
3634W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101031
ROBERTS UNIT
3534W
APACHE CORPORATION
Plugged - Oil
5164
5164
3534W
4250101828
DENVER UNIT
2208
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5170
5170
2208
4250101032
ROBERTS UNIT
3544
APACHE CORPORATION
Plugged - Oil
5170
5170
3544
4250101841
DENVER UNIT
2206
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5177
5177
2206
4250101842
ROBERTS UNIT
3643W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3643W
4250101035
ROBERTS UNIT
3533W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3533W
4250132704
ROBERTS UNIT
2615
APACHE CORPORATION
Active - Oil
5180
5180
2615
4250100261
ROBERTS UNIT
1643W
APACHE CORPORATION
Plugged - Oil
5180
5180
1643W
4250101323
ROBERTS UNIT
4542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
4542W
4250102989
ROBERTS UNIT
3642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
3642W
4250102991
ROBERTS UNIT
3622W
APACHE CORPORATION
Plugged - Oil
5185
5185
3622W
4250132417
MILLER
3
AMTEX ENERGY, INC.
Active - Oil
5186
5186
3
4250101025
ROBERTS UNIT
2613W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5188
5188
2613W
4250101887
ROBERTS UNIT
3644
APACHE CORPORATION
Active - Injection/Disposal from Oil
5189
5189
3644
4250101830
DENVER UNIT
2214WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5190
5190
2214WC
4250101103
ROBERTS UNIT
3621
APACHE CORPORATION
Plugged - Oil
5190
5190
3621
4250101024
ROBERTS UNIT
2623
APACHE CORPORATION
Plugged - Oil
5190
5190
2623
4250101023
ROBERTS UNIT
2622W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5190
5190
2622W
4250101022
ROBERTS UNIT
2632
APACHE CORPORATION
Active - Oil
5190
5190
2632
4250101019
ROBERTS UNIT
2621
APACHE CORPORATION
Active - Oil
5190
5190
2621
4250101030
ROBERTS UNIT
3524W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5193
5193
3524W
4250101829
DENVER UNIT
2205
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5195
5195
2205
4250101836
DENVER UNIT
2213WC
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5200
5200
2213WC
4250101833
DENVER UNIT
2202WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5200
5200
2202WC
4250134099
DENVER UNIT
2239WC
OCCIDENTAL PERMIAN LTD.
Dry Hole
5200
5200
2239WC
4250132717
ROBERTS UNIT
3531A
APACHE CORPORATION
TA - Injection/Disposal
5200
5200
3531A
4250101014
ROBERTS UNIT
2624W
APACHE CORPORATION
Plugged - Oil
5200
5200
2624W
4250101028
ROBERTS UNIT
3523
APACHE CORPORATION
Plugged - Oil
5205
5205
3523
4250101102
ROBERTS UNIT
3611
APACHE CORPORATION
Plugged - Oil
5206
5206
3611
4250101827
DENVER UNIT
2209W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5210
5210
2209W
4250101015
2643
TEXACO INCORPORATED
Active - Injection/Disposal from Oil
5210
5210
2643
4250100266
ROBERTS UNIT
3522W
APACHE CORPORATION
Plugged - Oil
5211
5211
3522W
4250132632
MILLER
5
AMTEX ENERGY, INC.
Active - Oil
5213
5213
5
4250100057
ROBERTS UNIT
2512W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5213
5213
2512W
4250101890
ROBERTS UNIT
3624W
APACHE CORPORATION
Plugged - Oil
5214
5214
3624W
4250101033
ROBERTS UNIT
3543W
APACHE CORPORATION
Plugged - Oil
5215
5215
3543W
4250101012
ROBERTS UNIT
2634W
APACHE CORPORATION
Plugged- Injection/Disposal from Oil
5215
5215
2634W
4250101734
ROBERTS UNIT
2442
APACHE CORPORATION
Plugged - Oil
5215
5215
2442
4250101020
ROBERTS UNIT
2611W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5215
5215
2611W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100067
ROBERTS UNIT
3531
APACHE CORPORATION
Plugged - Oil
5216
5216
3531
4250101013
ROBERTS UNIT
2614W
APACHE CORPORATION
Plugged - Oil
5216
5216
2614W
4250101844
ROBERTS UNIT
3623W
APACHE CORPORATION
Plugged - Oil
5217
5217
3623W
4250131869
ROBERTS UNIT
A3534W
APACHE CORPORATION
Plugged - Oil
5220
5220
A3534W
4250102990
ROBERTS UNIT
3632W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5220
5220
3632W
4250100262
ROBERTS UNIT
1644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5220
5220
1644W
4250132858
DENVER UNIT
2235
OCCIDENTAL PERMIAN LTD.
Shut-In - Oil
5225
5225
2235
4250100058
ROBERTS UNIT
2544W
APACHE CORPORATION
Plugged - Oil
5225
5225
2544W
4250130584
ROBERTS UNIT
4520
APACHE CORPORATION
Active - Oil
5230
5230
4520
4250130630
ROBERTS UNIT
3535
APACHE CORPORATION
Active - Oil
5230
5230
3535
4250100063
ROBERTS UNIT
3542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5230
5230
3542W
4250132076
ROBERTS UNIT
3627
APACHE CORPORATION
Active - Oil
5230
5230
3627
4250100267
ROBERTS UNIT
3512W
APACHE CORPORATION
Plugged - Oil
5233
5233
3512W
4250101016
ROBERTS UNIT
2642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5234
5234
2642W
4250134716
DENVER UNIT
2242
OCCIDENTAL PERMIAN LTD.
Active - Oil
5236
5236
2242
4250100061
ROBERTS UNIT
2524W
APACHE CORPORATION
Plugged - Oil
5238
5238
2524W
4250101021
ROBERTS UNIT
2633
APACHE CORPORATION
Plugged - Oil
5240
5240
2633
4250101011
ROBERTS UNIT
2644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5241
5241
2644W
4250132541
FUTCH
1
AMTEX ENERGY, INC.
Active - Oil
5244
5244
1
4250101026
ROBERTS UNIT
2612W
APACHE CORPORATION
Plugged - Oil
5245
5245
2612W
4250100059
ROBERTS UNIT
2513W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5246
5246
2513W
4250132531
MILLER
4
AMTEX ENERGY, INC.
Plugged - Oil
5248
5248
4
4250132687
ROBERTS UNIT
2635
APACHE CORPORATION
Plugged - Oil
5248
5248
2635
4250131656
DENVER UNIT
2232WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2232WC
4250131791
DENVER UNIT
2231
SHELL OIL COMPANY
Canceled/Abandoned Location
5250
5250
2231
4250134118
DENVER UNIT
2238
OCCIDENTAL PERMIAN LTD.
Active - Oil
5250
5250
2238
4250101342
ROBERTS UNIT
APACHE CORPORATION
Plugged - Gas
5250
5250
4250132269
ROBERTS UNIT
3601
APACHE CORPORATION
Plugged - Oil
5250
5250
3601
4250101843
ROBERTS UNIT
3633W
APACHE CORPORATION
Plugged - Oil
5250
5250
3633W
4250130608
ROBERTS UNIT
3545
APACHE CORPORATION
Active - Oil
5250
5250
3545
4250132077
ROBERTS UNIT
3617
APACHE CORPORATION
Active - Oil
5250
5250
3617
4250134963
DENVER UNIT
2244WC
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal
5251
5251
2244WC
4250100060
ROBERTS UNIT
2514
APACHE CORPORATION
Plugged - Oil
5251
5251
2514
4250101459
DENVER UNIT
2211
OCCIDENTAL PERMIAN LTD.
Active - Oil
5252
5252
2211
4250132521
DENVER UNIT
2233W
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal from Oil
5253
5253
2233W
4250135211
DENVER UNIT
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5253
5253
2241
4250101837
DENVER UNIT
2212W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5255
5255
2212W
4250132793
MILLER
6
AMTEX ENERGY, INC.
Active - Oil
5258
5258
6
4250132356
MILLER
1
AMTEX ENERGY, INC.
Active - Oil
5260
5260
1
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101017
ROBERTS UNIT
2641
APACHE CORPORATION
Active - Oil
5260
5260
2641
4250101825
DENVER UNIT
2204W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5264
5264
2204W
4250132416
MILLER
2
AMTEX ENERGY, INC.
Active - Oil
5269
5269
2
4250100065
ROBERTS UNIT
3511W
APACHE CORPORATION
Plugged - Oil
5270
5270
3511W
4250101018
ROBERTS UNIT
2631
APACHE CORPORATION
Active - Oil
5270
5270
2631
4250130600
ROBERTS UNIT
3645
APACHE CORPORATION
Active - Oil
5273
5273
3645
4250130580
ROBERTS UNIT
4536
APACHE CORPORATION
Active - Oil
5279
5279
4536
4250130599
ROBERTS UNIT
3646
APACHE CORPORATION
Active - Oil
5279
5279
3646
4250130602
ROBERTS UNIT
3635
APACHE CORPORATION
Active - Oil
5283
5283
3635
4250132997
DENVER UNIT
2208WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5284
5284
2208WC
4250130601
ROBERTS UNIT
3636
APACHE CORPORATION
Active - Oil
5286
5286
3636
4250132174
SHEPHERD
1
YOUNG, MARSHALL R., OIL CO.
Dry Hole
5286
5286
1
4250130604
ROBERTS UNIT
3625
APACHE CORPORATION
Active - Oil
5287
5287
3625
4250130912
DENVER UNIT
2224
OCCIDENTAL PERMIAN LTD.
Active - Oil
5288
5288
2224
4250130911
DENVER UNIT
2225
OCCIDENTAL PERMIAN LTD.
Active - Oil
5290
5290
2225
4250130609
ROBERTS UNIT
4530
APACHE CORPORATION
Active - Oil
5291
5291
4530
4250130605
ROBERTS UNIT
3616
APACHE CORPORATION
Plugged - Oil
5291
5291
3616
4250130606
ROBERTS UNIT
3615
APACHE CORPORATION
Active - Oil
5293
5293
3615
4250133172
ROBERTS UNIT
2523
CONOCOPHILLIPS COMPANY
Plugged - Oil
5295
5295
2523
4250132739
CLEVELAND
1
HIGHLAND PRODUCTION COMPANY
Plugged - Oil
5300
5300
1
4250133064
DENVER UNIT
2238
SHELL WESTERN E&P INC.
Canceled/Abandoned Location
5300
5300
2238
4250132927
DENVER UNIT
2236
OCCIDENTAL PERMIAN LTD.
Active - Oil
5300
5300
2236
4250133065
DENVER UNIT
2237
SHELL WESTERN E&P INC.
Expired Permit
5300
5300
2237
4250132270
ROBERTS UNIT
4540
APACHE CORPORATION
Active - Oil
5300
5300
4540
4250132414
ROBERTS UNIT
3523A
APACHE CORPORATION
Active - Injection/Disposal
5300
5300
3523A
4250132712
ROBERTS UNIT
3537
APACHE CORPORATION
Plugged - Oil
5300
5300
3537
4250132722
ROBERTS UNIT
3547
APACHE CORPORATION
Active - Oil
5300
5300
3547
4250132945
ROBERTS UNIT
3541A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3541A
4250132975
ROBERTS UNIT
3641A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3641A
4250132711
ROBERTS UNIT
3620
APACHE CORPORATION
Active - Oil
5300
5300
3620
4250133527
ROBERTS UNIT
2518
APACHE CORPORATION
Active - Oil
5300
5300
2518
4250132714
ROBERTS UNIT
2637
APACHE CORPORATION
Plugged - Oil
5300
5300
2637
4250133351
ROBERTS UNIT
2526
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2526
4250132703
ROBERTS UNIT
2516
APACHE CORPORATION
Plugged - Oil
5300
5300
2516
4250133348
ROBERTS UNIT
2533
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2533
4250132702
ROBERTS UNIT
2515
APACHE CORPORATION
Active - Oil
5300
5300
2515
4250133350
ROBERTS UNIT
2525
APACHE CORPORATION
Active - Oil
5300
5300
2525
4250133498
ROBERTS UNIT
2532
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2532
4250133173
ROBERTS UNIT
2522
APACHE CORPORATION
Active - Oil
5300
5300
2522
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250133499
ROBERTS UNIT
2527
TEXACO PRODUCING INC.
Dry Hole
5300
5300
2527
4250133530
ROBERTS UNIT
2507
APACHE CORPORATION
Active - Oil
5300
5300
2507
4250132685
ROBERTS UNIT
2638
APACHE CORPORATION
Plugged - Oil
5302
5302
2638
4250133349
ROBERTS UNIT
2517
APACHE CORPORATION
Active - Oil
5302
5302
2517
4250132718
ROBERTS UNIT
3532A
APACHE CORPORATION
Active - Injection/Disposal
5304
5304
3532A
4250132713
ROBERTS UNIT
2625
APACHE CORPORATION
Active - Oil
5308
5308
2625
4250133502
ROBERTS UNIT
2527A
APACHE CORPORATION
Plugged - Oil
5308
5308
2527A
4250132716
ROBERTS UNIT
3526
APACHE CORPORATION
Active - Oil
5309
5309
3526
4250100645
ROBERTS UNIT
1624W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5309
5309
1624W
4250130913
DENVER UNIT
2223
OCCIDENTAL PERMIAN LTD.
Active - Oil
5310
5310
2223
4250132686
ROBERTS UNIT
2636
APACHE CORPORATION
Active - Oil
5310
5310
2636
4250101457
DENVER UNIT
2210
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5325
5325
2210
4250133529
ROBERTS UNIT
2508
APACHE CORPORATION
Plugged - Oil
5325
5325
2508
4250133531
ROBERTS UNIT
2443A
APACHE CORPORATION
Active - Injection/Disposal
5325
5325
2443A
4250133528
ROBERTS UNIT
2511
APACHE CORPORATION
Active - Oil
5325
5325
2511
4250135912
ROBERTS UNIT
3771W
APACHE CORPORATION
Active - Injection/Disposal
5330
5330
3771W
4250132075
ROBERTS UNIT
3637
APACHE CORPORATION
Active - Oil
5330
5330
3637
4250132063
ROBERTS UNIT
2705
APACHE CORPORATION
Active - Oil
5330
5330
2705
4250135793
ROBERTS UNIT
3672
APACHE CORPORATION
Active - Oil
5334
5334
3672
4250135819
ROBERTS UNIT
3674W
APACHE CORPORATION
Active - Injection/Disposal
5336
5336
3674W
4250135792
ROBERTS UNIT
3671
APACHE CORPORATION
Active - Oil
5339
5339
3671
4250135820
ROBERTS UNIT
3675W
APACHE CORPORATION
Active - Injection/Disposal
5341
5341
3675W
4250135818
ROBERTS UNIT
3633RW
APACHE CORPORATION
Active - Injection/Disposal
5344
5344
3633RW
4250135790
ROBERTS UNIT
3647R
APACHE CORPORATION
Active - Oil
5345
5345
3647R
4250100768
CORNELL UNIT
3107W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5350
5350
3107W
4250130915
DENVER UNIT
2221
OCCIDENTAL PERMIAN LTD.
Active - Oil
5350
5350
2221
4250136048
ROBERTS UNIT
3634RW
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3634RW
4250135908
ROBERTS UNIT
3678W
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3678W
4250132072
ROBERTS UNIT
3525
APACHE CORPORATION
Active - Oil
5350
5350
3525
4250135915
ROBERTS UNIT
3626R
APACHE CORPORATION
Active - Oil
5350
5350
3626R
4250132281
ROBERTS UNIT
2446
APACHE CORPORATION
Active - Oil
5350
5350
2446
4250132064
ROBERTS UNIT
2704
APACHE CORPORATION
Active - Oil
5350
5350
2704
4250132280
ROBERTS UNIT
2445
APACHE CORPORATION
Plugged - Oil
5350
5350
2445
4250135791
ROBERTS UNIT
3670
APACHE CORPORATION
Active - Oil
5351
5351
3670
4250135794
ROBERTS UNIT
3673
APACHE CORPORATION
Active - Oil
5352
5352
3673
4250135821
ROBERTS UNIT
3676W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3676W
4250135914
ROBERTS UNIT
3681W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3681W
4250100643
ROBERTS UNIT
1634W
APACHE CORPORATION
Plugged - Oil
5353
5353
1634W
4250135796
ROBERTS UNIT
3669
APACHE CORPORATION
Active - Oil
5356
5356
3669
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100644
ROBERTS UNIT
1614
APACHE CORPORATION
Plugged - Oil
5356
5356
1614
4250135913
ROBERTS UNIT
3680W
APACHE CORPORATION
Active - Injection/Disposal
5357
5357
3680W
4250135705
ROBERTS UNIT
3752
APACHE CORPORATION
Active - Oil
5360
5360
3752
4250135822
ROBERTS UNIT
3677W
APACHE CORPORATION
Active - Injection/Disposal
5362
5362
3677W
4250134984
ROBERTS UNIT
2626W
APACHE CORPORATION
Active - Injection/Disposal
5364
5364
2626W
4250135701
ROBERTS UNIT
3667
APACHE CORPORATION
Active - Oil
5365
5365
3667
4250132070
ROBERTS UNIT
3536
APACHE CORPORATION
Active - Oil
5370
5370
3536
4250132065
ROBERTS UNIT
2703
APACHE CORPORATION
Active - Oil
5370
5370
2703
4250100755
CORNELL UNIT
3101W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5373
5373
3101W
4250135703
ROBERTS UNIT
3668
APACHE CORPORATION
Active - Oil
5380
5380
3668
4250135229
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5388
5388
2240
4250136152
ROBERTS UNIT
3682W
APACHE CORPORATION
Active - Injection/Disposal
5397
5397
3682W
4250131539
DENVER UNIT
2230
SHELL OIL COMPANY
Canceled/Abandoned Location
5400
5400
2230
4250136327
ROBERTS UNIT
4547
APACHE CORPORATION
Active - Oil
5400
5400
4547
4250136154
ROBERTS UNIT
3624RW
APACHE CORPORATION
Active - Injection/Disposal
5400
5400
3624RW
4250136155
ROBERTS UNIT
3683W
APACHE CORPORATION
Active - Injection/Disposal
5402
5402
3683W
4250136156
ROBERTS UNIT
3686
APACHE CORPORATION
Active - Oil
5404
5404
3686
4250134797
CORNELL UNIT
3194
XTO ENERGY INC.
Active - Oil
5405
5405
3194
4250135696
CORNELL UNIT
113
XTO ENERGY INC.
Active - Oil
5406
5406
113
4250136150
ROBERTS UNIT
3684
APACHE CORPORATION
Active - Oil
5421
5421
3684
4250133629
CORNELL UNIT
3156
XTO ENERGY INC.
Active - Oil
5425
5425
3156
4250135961
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Active - Oil
5425
5425
2246
4250135960
DENVER UNIT
2249
OCCIDENTAL PERMIAN LTD.
Active - Oil
5431
5431
2249
4250136153
ROBERTS UNIT
3623RW
APACHE CORPORATION
Active - Injection/Disposal
5439
5439
3623RW
4250135353
CORNELL UNIT
107
XTO ENERGY INC.
Active - Oil
5450
5450
107
4250135528
ROBERTS UNIT
3549
APACHE CORPORATION
Active - Oil
5452
5452
3549
4250136151
ROBERTS UNIT
3685
APACHE CORPORATION
Active - Oil
5463
5463
3685
4250135963
DENVER UNIT
2252
OCCIDENTAL PERMIAN LTD.
Active - Oil
5476
5476
2252
4250136434
ROBERTS UNIT
263H
APACHE CORPORATION
Expired Permit
5500
5500
263H
4250136433
ROBERTS UNIT
262H
APACHE CORPORATION
Expired Permit
5500
5500
262H
4250136098
CORNELL UNIT
110
XTO ENERGY INC.
Active - Injection/Disposal
5510
5510
110
4250133615
ROBERTS UNIT
2442A
APACHE CORPORATION
TA - Injection/Disposal
5516
5516
2442A
4250135180
ROBERTS UNIT
3534B
APACHE CORPORATION
Active - Injection/Disposal
5517
5517
3534B
4250136428
CORNELL UNIT
124
XTO ENERGY INC.
Active - Oil
5532
5532
124
4250134878
ROBERTS UNIT
3548
APACHE CORPORATION
Active - Oil
5550
5550
3548
4250135966
DENVER UNIT
2251
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2251
4250135962
DENVER UNIT
2250
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2250
4250135356
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Expired Permit
5600
5600
2246
4250135959
DENVER UNIT
2248
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2248
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250135210
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250135211
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2241
4250134710
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250101845
ROBERTS UNIT
3613
APACHE CORPORATION
Active - Oil
7000
7000
3613
4250110083
RANDALL, E.
36
EXXON CORP.
Plugged - Oil
8595
8595
36
4250110046
ELLIOTT, C.A.
2
MCCLURE OIL COMPANY, INC.
Plugged - Oil
9000
9000
2
4250136692
MISS KITTY 704-669
3XH
RILEY EXPLORATION OPG CO, LLC
Expired Permit
9000
9000
3XH
4250133793
RANDALL, E.
39
XTO ENERGY INC.
Active - Oil
9000
9000
39
4250137375
RIP WHEELER 705-668
5XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
5XH
4250137358
RIP WHEELER 705-668
1XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
1XH
4250133843
ELLIOTT
1
DELTA C02, LLC
Plugged - Oil
9050
9050
1
4250134124
RANDALL, E
46
EXXON CORP.
Canceled/Abandoned Location
9100
9100
46
4250133792
RANDALL, E.
40
XTO ENERGY INC.
Plugged - Oil
9591
9591
40
4250110079
RANDALL, E.
32
EXXON CORP.
Plugged - Oil
9615
9615
32
4250135418
RANDALL, E.
46
XTO ENERGY INC.
Active - Oil
9650
9650
46
4250134023
RANDALL, E.
42
XTO ENERGY INC.
Active - Oil
9660
9660
42
4250134016
RANDALL, E.
43
XTO ENERGY INC.
Active - Oil
9740
9740
43
4250132388
RANDALL, E.
38
EXXON CORP.
Canceled/Abandoned Location
10300
10300
38
4250137302
MILLER 732 B
9H
AMTEX ENERGY, INC.
Active - Oil
5183
10662
9H
4250136432
ROBERTS UNIT
261 H
APACHE CORPORATION
Active - Oil
5151
11117
261 H
4250136998
RATTLESNAKE AGI
1
SANTA FE MIDSTREAM PERMIAN LLC
Active - Injection/Disposal
11980
11980
1
4250137252
MILLER SWD
7
AMTEX ENERGY, INC.
Permitted Location
13000
13000
7
4250136984
MADCAP 731-706
1XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5261
13274
1XH
4250137127
MISS KITTY A 669-704
25XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5321
13428
25XH
4250137287
MISS KITTY A 669-704
4XH
RILEY PERMIAN OPERATING CO, LLC
Shut-In - Oil
5340
13452
4XH
4250137236
MISS KITTY 669-704
2XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5317
13622
2XH
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well Penetrators
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
1
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-5
+ Rattlesnake AGI No. 1 SHL
I '
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
API (42-501-...) SHL Status - Type (Count)
• Active - Oil (4)
Active - Injection/Disposal (1)
Plugged - Oil (4)
® Permitted Location (1)
Sou rce:
1.) Oil/Gas Well SHL Data: DI-2022
2.) Oil/Gas Well BHL Data: DI-2022
3.) Oil/Gas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD).
1560
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Groundwater Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
F-6
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
+ Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
SDRDB Groundwater Wells [TWDB-2022]
Proposed Use (Labeled with Well Report No.)
A Industrial (1)
Irrigation (5)
TWDB Groundwater Wells [TWDB-2022]
Well Type (Labeled with State Well No.)
¦ Withdrawal of Water (1)
Sou rce:
1.) SDRDB Groundwater Well SHL Data: TWDB-2022
2.) TWDB Groundwater Well SHL Data: TWDB-2022
3.) Brackish Groundwater Well SHL Data: TWDB-2022
* Note: All coordinates shown are in NAD83 (DD). *
1560
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Cement Plug #9
@7'-1,013'
Cement Plug #8
@ 1,730'- 1,800'
Cement Plug #7
@ 2,031' - 2,100
Cement Plug #6
@2,430'-2,500'
Cement Plug #5
@2,660'-2,719'
Cement Plug #4
@2,790'-2,860'
Cement Plug #3
@3,172'-3,239'
Cement Plug #2
@3,765'-3,831'
Cement Plug #1
@ 3,900'-3,960'
Perfs @ 8,231
8,396', 8,420'
8,447', 8,462'
Casing Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
4-1/2"
Depth Set
2,134'
9,601'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-10079
RRC District No: 8-A
Drawn: KAS
E. Randall No. 32
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18231
Date: 05/31/2022
Approved: SLP
-------
Cement Plug #5
@ 0' - 458'
Cement Plug #4
@2,070'-2,295'
Cement Plug #3
@2,780'- 3,009'
Cement Plug #2
@4,450'-4,870'
Cement Plug #1
@5,184'-5,266'
Perfs@ 9,496'-9,516'
TD@ 9,591'
PBTD @ 9,560'
DV Tool ® 4,522'
DV Tool @ 5,676'
Casing Information
Label
1
3
Type
Surface
Production
OD
9-5/8"
5-1/2"
Weight
36 lb/ft
UNK
Depth Set
2,162'
9,569'
Hole Size
12-1/4"
7-7/8"
TOC
Surface
2,350'
Volume
880 sks
5,450 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-337932
RRC District No: 8-A
Drawn: KAS
E. Randall No. 40
State/Province: Texas
Spud Date: 12/04/1992
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
A
Perfs (5) 9,536' - 9,540'
SI
[S
: . I
DV Tool @ 5,968'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54 lb/ft
36 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,129'
5,606'
9,699'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
1,790 sks
2,910 sks
1,590 sks
2-3/8" Tubing & Packer Set @ 9,331'
TD @ 9,700'
PBTD @ 9,654'
MD
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-33885
RRC District No: 8-A
Drawn: KAS
E. Randall No. 41L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,533' - 9,553'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,167'
5,830'
9,658'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
440'
1,800'
Volume
1,530 sks
3,500 sks
1,050 sks
DV Tool ® 7,414'
2-3/8" Tubing & Packer Set @ 8,970'
TD @ 9,660' \-(3)
PBTD @ 9,623' W
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34023
RRC District No: 8-A
Drawn: KAS
E. Randall No. 42L
State/Province: Texas
Spud Date: 07/01/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Li;.
Perfs @ 9,550' - 9,538'
9,603'-9,610'
sf.
.... «¦
*'¦ •-
4/?
¦A ¦
" B ¦'
" ¦ /
?
, 4' i
,
"4
t" '
'*¦ ?r
. v.
> .¦
"A
' 'i
;
¦ 'v
„ .: '
4* •"
/
CIBP ® 8,917'
CIBP @ 9,590'
TD @ 9,740'
PBTD @ 8,917'
rv@
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,166'
5,902'
9,735'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
2,000'
Volume
1,530 sks
3,505 sks
967 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-34016
RRC District No: 8-A
Drawn: KAS
E. Randall No. 43L
State/Province: Texas
Spud Date: 04/08/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs @ 8,762' - 8,782'
(Sqz w/100 sx)
Perfs @8,822'-8,831'
(Sqz w/ 75 sx)
Perfs @ 9,562' - 9,570'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
29 lb/ft
Depth Set
2,158'
5,904'
9,620'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,600'
Volume
1,450 sks
5,190 sks
1,100 sks
DV Tool ® 7,482'
2-3/8" Tubing & Packer Set @ 9,552'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34024
RRC District No: 8-A
Drawn: KAS
E. Randall No. 44
State/Province: Texas
Spud Date: 08/09/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,565' - 9,575'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,175'
5,898'
9,615'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,500'
Volume
1,530 sks
3,525 sks
1,170 sks
DV Tool ® 7,508'
2-3/8" Tubing Set @ 9,580'
Packer Set (5) 9,394'
TD @ 9,684'
PBTD @ 9,593'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34017
RRC District No: 8-A
Drawn: KAS
E. Randall No. 45L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
Perfs (5) 9,504' - 9,512'
TD @ 9,650'
PBTD @ 9,594'
Casing/Tubing
Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
5-1/2"
Weight
24 lb/ft
17 lb/ft
Depth Set
2,120'
9,650'
Hole Size
11"
7-7/8"
TOC
Surface
Surface
Volume
900 sks
3,400 sks
DV Tool ® 8,656' & 8,674'
2-7/8" Tubing & Packer Set @ 9,184'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy, Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-35418
RRC District No: 8-A
Drawn: KAS
E. Randall No. 46
State/Province: Texas
Spud Date: 05/23/2007
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
u
Cement Plug #4
@48'-60'
Cement Plug #3
@ 270' - 450'
Cement Plug #1
@7,549'-8,000'
Perfs @ 8,292' - 8,428'
Cement Plug #2
@3,273'-3,439'
Top of Cut @ 750'
Top of Cut @ 1,439'
TD ® 9,645'
v@
Casing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
5-1/2"
Depth Set
300'
3,200'
9,610'
TOC
Surface
Surface
Surface
Volume
400 sks
300 sks
425 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Bonanza Oil Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-10046
RRC District No: 8-A
Drawn: KAS
C.A. Elliott No. 2
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18875
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
w
if.
II
: .
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
48 lb/ft
40 lb/ft
26 lb/ft
28 lb/ft
Depth Set
500'
5,500'
10,695'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
350 sks
1,705 sks
1,635 sks
3-1/2" Tubing & Packer Set @ 10,650'
MD
TD @ 13,000'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Amtex Energy, Inc.
Country: USA
Location: Section 732, Block D
API No: 42-501-37252
RRC District No: 7-C
Drawn: KAS
Miller SWD No. 7 (Permitted)
State/Province: Texas
Spud Date: 08/09/1995
Field: Wasson
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
Permit Number: 16637
Date: 05/31/2022
Approved: SLP
-------
Appendix B: Submissions and Responses to Requests for Additional
Information
-------
STAKEHOLDER
I!MIDSTREAM
Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
Rattlesnake AGI #1
Yoakum County, Texas
Prepared for Stakeholder Gas Services, LLC
San Antonio, TX
By
Lonquist Sequestration, LLC
Austin, TX
Version 3
September 2022
LONQUIST
SEQUESTRATION LLC
-------
INTRODUCTION
Stakeholder Gas Services, LLC ("Stakeholder") currently has a Class II acid gas injection ("AGI") permit, issued
by the Texas Railroad Commission ("TRRC") in November 2018, for the Rattlesnake AGI #1 well, API No. 42-
501-36998. This permit was originally issued to Santa Fe Midstream Permian, LLC, in 2018 and the asset was
subsequently acquired by Stakeholder in December of 2020. This permit currently authorizes Stakeholder to
inject up to 4,500 barrels per day ("bbls/d") of treated acid gas ("TAG") into the Devonian formation at a
depth of 11,000' to 12,000' with a maximum allowable surface pressure of 2,200 psi. Since being permitted,
injection has proceeded without incident. This AGI well is associated with Stakeholder's 30-30 gas treating
and processing plant ("30-30") located in a rural, sparsely populated area of Yoakum County, Texas,
approximately seven miles northwest of the town of Plains, as shown in Figure 1.
I t
H-
Ula
homa
STAKEHOLDER
MIDSTREAM
Mexlip
TT
:
1
t
L
Y
I
H
iti
l^vas
J L
riV
r\ fV
WES
T OIL F
IELD
Yoakum
ink Bas.n
Rattlesnake
AGI(RS#1)
¦
WASSON OIL
FIELD
° *
9
"S
W
i
|
Four Mi
| 1
Ji|—k s ¦/- 1 i
§
YbAKUM
GAINrS
^ Gaines
0 0.5 1 2 Miles
GEOROi
ALLEN
OIL
FIELD
# Stakeholder AGI Well
Figure 1 - Location of Rattlesnake AGI #3 Well
1
-------
Stakeholder 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, Stakeholder is also applying to the TRRC for an amendment to the
Rattlesnake AGI #1 well's Class II permit to increase its authorized injection volume and maximum allowable
surface injection pressure ("MASIP"). Approval of the permit amendment will allow Stakeholder to increase
the capacity of its existing 30-30 Facility, which removes H2S and C02 from natural gas production using amine
treating, as well as increase the injection well capacity for a future gas processing facility which is currently
under development by Stakeholder. Additionally, expanded capacity allows Stakeholder to potentially
provide future disposal in its AGI well for oil and gas waste derived TAG from similar third-party gas processing
facilities. Increased disposal capacity will allow for greater gas processing capacity in the region, ultimately
helping to reduce flaring and its associated emissions. Throughout this document, both in written reference
and in modeling inputs, Stakeholder has used the applied-for expanded permit capacity of 16 million standard
cubic feet per day ("MMSCF/d"). Stakeholder plans to inject C02 for approximately 14 more years.
2
-------
ACRONYMS AND ABBREVIATIONS
%
°c
°F
AMA
BCF
CH4
CMG
C02
E
EOS
EPA
ESD
FG
ft
GAU
GEM
GHGs
GHGRP
H2S
md
mi
MIT
MM
MMA
MCF
MMCF
MMSCF
Feet
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)
Groundwater Advisory Unit
Computer Modelling Group's GEM 2020.11
Greenhouse Gases
Greenhouse Gas Reporting Program
Hydrogen Sulfide
Millidarcy(ies)
Mile(s)
Mechanical Integrity Test
Million
Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet
-------
MSCF/D Thousand 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
4
-------
TABLE OF CONTENTS
INTRODUCTION 1
ACRONYMS AND ABBREVIATIONS 3
SECTION 1 - FACILITY INFORMATION 8
Reporter number 8
Underground Injection Control (UIC) Class II Permit 8
UIC Well Identification Number 8
SECTION 2- PROJECT DESCRIPTION 9
Regional Geology 10
Regional Faulting 15
Site Characterization 15
Stratigraphy and Lithologic Characteristics 15
Upper Confining Interval - Woodford Shale 16
Injection Interval - Fasken Formation 17
Lower Confining Zone - Fusselman Formation 21
Local Structure 21
Injection and Confinement Summary 26
Groundwater Hydrology 26
Description of the Injection Process 31
Current Operations 31
Planned Operations 32
Reservoir Characterization Modeling 32
Simulation Modeling 35
SECTION 3 - DELI NATION OF MONITORING AREA 39
Maximum Monitoring Area 39
Active Monitoring Area 40
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE 42
Leakage from Surface Equipment 42
Leakage from Wells in the Monitoring Area 44
Oil and Gas Operations within Monitoring Area 44
Groundwater wells 48
Leakage Through Faults or Fractures 50
Leakage Through Confining Layers 51
Leakage from Natural or Induced Seismicity 51
SECTION 5 - MONITORING FOR LEAKAGE 54
Leakage from Surface Equipment 54
Leakage from Existing and Future Wells within Monitoring Area 55
Leakage through Faults, Fractures or Confining Seals 56
Leakage through Natural or Induced Seismicity 56
SECTION 6 - BASELINE DETERMINATIONS 57
Visual Inspections 57
H2S Detection 57
C02 Detection 57
Operational Data 57
Continuous Monitoring 57
Groundwater Monitoring 58
SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION 59
5
-------
Mass of C02 Received 59
Mass of C02 Injected 59
Mass of C02 Produced 60
Mass of C02 Emitted by Surface Leakage 60
Mass of C02 Sequestered 60
SECTION 8- IMPLEMENTATION SCHEDULE FOR MRV PLAN 62
SECTION 9 - QUALITY ASSURANCE 63
Monitoring QA/QC 63
Missing Data 63
MRV Plan Revisions 64
SECTION 10- RECORDS RETENTION 65
References 66
APPENDICES 67
LIST OF FIGURES
Figure 1 - Location of Rattlesnake AGI #1 well 1
Figure 2 - Illustrative overview of Rattlesnake AGI #1 and 30-30 Facility 9
Figure 3 - Regional Map of the Permian Basin 10
Figure 4 - Stratigraphic column of the Northwest Shelf 11
Figure 5 - Stratigraphic column depicting the composition of the Silurian group 12
Figure 6 - Thickness map of the Silurian system which composes the Fusselman and Wristen group 14
Figure 7 - Type Log (42-501-10238) with tops, confining and injection zones depicted 15
Figure 8 - Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994) 16
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays 18
Figure 10 - Rattlesnake AGI #1 open hole log (42-501-36998) 19
Figure 11 - Offset wells used for Formation Fluid Characterization 20
Figure 12 - Silurian Structure Map (subsea depths) 23
Figure 13 - Structural Northeast-Southwest Cross Section 24
Figure 14 - Structural Northwest-Southeast Cross Section 25
Figure 15 - Northwest-Southeast Cross Section of aquifers in the Rattlesnake AGI #1 well area 27
Figure 16 - Potentiometric surfaces from wells completed in A Ogallala aquifer, B the Edwards-Trinity aquifer
and Cthe Dockum aquifer 28
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDB) 29
Figure 18 -Total dissolved solids in groundwater from the Dockum Aquifer 29
Figure 19-Regional extent of the Edwards-Trinity freshwater aquifer 30
Figure 20 - Regional extent of the Ogallala freshwater aquifer 31
Figure 21 - 30-30 Facility Process Flow Diagram 32
Figure 22 - Permeability Distribution of Karst Limestone 34
Figure 23 - Areal View Gas Saturation Plume, 2036 (End of Injection) 37
Figure 24 - Areal View Gas Saturation Plume, 2779 (End of Density Drift) 38
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time 38
Figure 26 - Plume Boundary at End of Injection, Stabilized Plume, and Maximum Monitoring Area 40
Figure 27 - Active Monitoring Area 41
Figure 28 - Site Plan, 30-30 Facility 43
Figure 29 - Rattlesnake AGI #1 Wellbore Schematic 45
Figure 30 - Oil and Gas Wells within the MMA 46
6
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Figure 31 - Penetrating Oil and Gas Wells within the MMA 47
Figure 32 - Groundwater Wells within MMA 49
Figure 33 - Seismicity Review (TexNet - 06/01/2022) 52
Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI #1 location 53
LIST OF TABLES
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples 20
Table 2 - Fracture Gradient Assumptions 21
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and
Yoakum Counties, Texas 26
Table 4 - Gas Composition of 30-30 Facility outlet 31
Table 5 - Modeled Initial Gas Composition 33
Table 6 - CMG Model Layer Properties 34
Table 7 - All Offset SWDs included in the model 36
Table 8 - All Offset Producers included in the model 36
Table 9 - Groundwater Well Summary 50
Table 10 - Summary of Leakage Monitoring Methods 54
7
-------
SECTION 1 - FACILITY INFORMATION
This section contains key information regarding the Acid Gas and C02 injection facility.
Reporter number:
• Gas Plant Facility Name: 30-30 Gas Plant
• Greenhouse Gas Reporting Program ID: 574501
o Currently reporting under Subpart UU
• Operator: Stakeholder Gas Services, LLC
Underground Injection Control (UIC) 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 Rattlesnake AGI #1 well as a UIC Class II well. A Class II
permit was issued to Stakeholder under TRRC Rule 9 (entitled "Disposal into Non-Productive Formations")
and Rule 36 (entitled "Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas").
UIC Well Identification Number:
Rattlesnake AGI #1, API No. 42-501-36998, UIC #000117143.
8
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SECTION 2 - PROJECT DESCRIPTION
This Project Description discusses the geologic setting, planned injection volumes and process, and the
reservoir modeling performed for the Rattlesnake AGI #1 well. The Class II UIC permit was initially applied
for and received by Santa Fe Midstream Permian, LLC. The asset was acquired in 2020 by Stakeholder and
has been in operation since that time. Since the original application, Lonquist has revised and updated the
geology and the plume modeling within the reservoir in preparing this MRV Plan.
The Rattlesnake AGI #1 well is located and designed to protect against migration of C02 out of the injection
interval and to prevent surface releases. The injection interval for Rattlesnake AGI #1 is located over 4,720'
below the primary producing formation, the San Andres, in the area and 8,593' below the base of the lowest
useable quality water table, as shown in Figure 2. This well injects both H2S and C02, therefore the well and
the facility are designed to minimize any leakage to the surface.
STAKEHOLDER
TREATING & PROCESSING
PLANT
2,450'
LOWEST
WATER TABLE
DEPTH
5,500'
CASING DEPTH
Casing consists of
reinforced steel
and concrete
11,000'
INJECTION WELL
DEPTH
>8,500'
BELOW THE
WATER TABLE
Figure 2 - Illustrative overview of Rattlesnake AGI tt1 and 30-30 Facility
9
-------
Regional Geology
The Rattlesnake AGI #1 well is located on the southern portion of the Northwestern Shelf within the larger
Permian Basin as seen in Figure 3. The Northwestern Shelf is a broad marine shelf located in the northern
portion of the Permian Basin,
Basin
Matador Arch
Eastern
Shelf
f.. NEW MEXICO
Jtexas |
Delaware'^
Basin \
Ozona
, Arch
>Val Verde
' Basin
.Ouach/h
NJ
NEW
MEXICO
WO ml
100 Km
I I Permian Basin
Figure 3 - Regional Map of the Permian Basin. Red Star is approximate location of Rattlesnake AGI #1 well
Figure 4 depicts the stratigraphic column found at the Rattlesnake AGI #1 well location with red stars
referencing the injection formation and green stars indicating the productive intervals in the area. The
primary injection interval is found within the Wristen group, of Silurian-age, as seen in Figure 5. The TRRC
refers to this sequence under the general terms "Devonian", "Silurian-Devonian" or "Siluro-Devonian".
10
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Period
Epoch
Formation
General Lithology
Permian
Ochoan
Dewey Lake
Redbeds/Anhydrite
Rustler
Halite
Salado
Halite/Anhydrite
Guadalupian
Tansil
Anhydrite/Dolomite
Yates
Anhydrite/Dolomite
Seven Rivers
Dolomite/Anhydrite
Queen
Sandy Dolomite/Anhydrite/Sandstone
Grayburg
Dolomite/Anhydrite/Shale/Sandstone
Leonardian
~ San Andres
Dolomite/Anhydrite
Glorieta
Sandy Dolomite
Yeso
Paddock
Dolomite/Anhydrite/Sandstone
Blinebry
Tubb
Drinkard
Abo
Dolomite/Anhydrite/Shale
Wolfcampian
^ Wolfcamp
Limestone/Dolomite
Pennsylvanian
Virgilian
Cisco
Limestone/Dolomite
Missourian
Canyon
Limestone/Shale
Des Moinesian
Strawn
Limestone/Sandstone
Atokan
Bend
Limestone/Sandstone/Shale
Morrowan
Morrow
Mississippian
Mississippian Lime
Limestone
Devonian
Woodford
Shale
Silurian
-^Wristen Group
Dolomite/Limestone
^ Fusselman
Dolomite/Chert
Ordovician
Upper
Montoya
Dolomite/Chert
Middle
Simspson Gp
Limestone/Sandstone/Shale
Lower
Ellenburger
Dolomite
Figure 4 - Stratigraphic column of the North west Shelf. Red stars indicate injection interval. Green stars indicate productive
intervals.
-------
Mississippian
Chesterian
undivided
Meramecian
Osagian
Kinderhookian
Devonian
Upper
Woodford Shale
Middle
Lower
Thirtyone Fm.
Silurian
Pridolian
Wristen Gp.
~
Fasken
Fm.
Frame Fm.
Ludlovian
Wink Fm.
Wenlockian
Llandoverian
Fusselman Fm.
Ordovician
Upper
Montoya Fm.
Simpson Gp.
Middle
Lower
Ellenburger Fm.
Figure 5 - Stratigraphic column depicting the composition of the Silurian group. Red star indicates injection interval (Broadhead,
2005)
The Wristeri group was deposited in a basin platform setting across the northern half of the Permian Basin.
The depositional environment over Yoakum County during the Silurian period was a shallow inner platform,
the margin of which exists to the south, in southern Andrews County, Texas. The Silurian-age lithology on
the inner platform is dominated by grain-rich skeletal carbonates. Carbonate buildups are common within
the shallow inner platform, mainly skeletal wackestone, indicating a lower-energy deposition on the inner
platform. The carbonate shelf margin to the south acted as a barrier from basin-ward wave energy (Ruppel
and Holtz, 1994).
Depositional cycles within the inner platform indicate it was controlled by episodic sea level rise and fail,
resulting in sub-areal exposure and diagenesis. The diagenesis of the Silurian-age carbonate rocks initiated
12
-------
secondary porosity development and increased permeability. Dolomite and solution-related features are the
most prominent diagenetic characteristics found within the Silurian. The Wristen Group is composed of three
formations: Fasken, Frame, and Wink formations. The Frame and Wink formations are found near the ramp
boundary to the south, while the Fasken formation is found predominantly in the inner platform, where the
Rattlesnake AGI #1 well is located. The Fasken formation is predominately dolomite grading to limestone,
occurring as cycles, down section. This dolomitization is due in part to sub-areal exposure, during which
karsts and secondary porosity developed. Additional dolomitization was possible during successive sea level
fluctuations via movement of magnesium-rich solution through karsts and vugs, which acted as channels for
fluid flow (Ruppel and Holtz, 1994).
Figure 6 shows a regional isopach map of the Silurian (combined Fasken and Fusselman formations) with a
red star depicting the Rattlesnake AGI #1 well location. Thickness of the Silurian-age rock is approximately
1,000' at the Rattlesnake AGI #1 well location.
North of Andrews County there is little differentiation between the Fasken and Fusselman formations which
are both carbonate deposits with the potential for sub-areal exposure and porosity development. For
purposes of this MRV Plan, the combined Fasken and Fusselman formations are defined as the injection
interval, and the underlying Montoya formation serves as the lower confining unit.
13
-------
ThjChMSJ (ft)
W'Uin plait ttf iM'tm
M«l$COC« |4?t«U«IS
wiOtAI
4.0*1*4
Ttm
S kM>M
c«o«rTT
Figure 6- Thickness map of the Silurian system which composes the Fusselman and Wristen group
14
-------
Regional Faulting
A major uplift that began during the Pennsylvanian Period to the south, the Central Basin Platform, ceased
in the Early Permian (Wolfcampian), which caused a regional unconformity of the underlying formations
(Hoak, Sundberg, and Ortoleva). Faulting on the Northwest Shelf can be seen through high angle basement
faults that tend to die within the Pennsylvanian strata. These faults predominately represent contractional
(thrust) faults that were initiated during the Pennsylvanian as a result of regional tectonics. Hydrocarbon
traps within the Wristen group are primarily anticlinal structures dependent upon reservoir development
(Broadhead, 2005).
Site Characterization
The Rattlesnake AGI #1 well is located in Section 733, Block D, John H. Gibson Survey, in Yoakum County,
Texas. Stakeholder owns the 82.42-acre surface tract where the plant and Rattlesnake AGI #1 well are
located. The following discusses the geological character of this site.
Stratigraphy and Lithologic Characteristics
Figure 7 depicts an open hole log from an offset well (API No. 42-501-10238) to the Rattlesnake AGI #1 well
indicating the injection and primary upper confining zone. This well is approximately 1.8 miles to the
northwest of the Rattlesnake AGI #1 well, An offset well log was used to depict the upper confining intervals
as electric logs were only run in the Rattlesnake AGI #1 well across the injection zone.
15
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Upper Confining Interval - Woodford Shale
The Woodford is a late Devonian-age organic-rich shale deposited as a result of a widespread marine
transgression. The flooding event occurred over the majority of the Permian basin, which produced a low-
relief blanket-like shale deposit of the Woodford. Two major lithofacies found within the Woodford are black
shale and siltstone. Nutrient-rich surface waters promoted the decay of abundant organic matter within the
Woodford, resulting in a high total organic carbon ("TOC") percentage. The Woodford shale acts as the
primary source and sealant rock for the Wristen Group (Comer, 1991).
Figure 8 is a description of a core sample taken in Lea County, New Mexico just southwest of the Rattlesnake
AGI #1 well location. This sample is referenced as C9 in the reference map with the blue star representing
the Rattlesnake AGI #1 well. In the core description, black shale with abundant illitic clays is observed in the
upper section, and medium gray dolomitic siltstone found in the basal section. The mineralogic and lithologic
properties recorded in this description serve as excellent sealant characteristics to prohibit any injected fluids
from migrating above the injection interval.
The Woodford at the Rattlesnake AGI #1 well location is encountered at 10,973 ft and is approximately 63 ft
thick.
C9
Shell No. 5 Pacific Royalty
Lea County, New Mexico
Section 10.T15S-R37E
Elevation 3814 ft
X
Q
TOC
Weight
percent
1 2 3 4 5
—I I I I L_
GR i
C9 5
cs s
C9 7
Description
(ft)
35+
-12.200
Medium* to dark-gray limestone Lime mudstone with a few thin beds of brachiopod
wackestone and skeletal and pellet grainstone Some intervals highly fractured; all
fractures are filled, some with calcite, some with silica. Lowor contact not
preserved, probably conformable.
Green limestone. Clay rich. Lower contact not preserved, probably disconformablo.
Black shale. Parallel laminae Abundant fllitic clay; pyritic. Scattered grains of sift*
sized quartz, dolomite, and mica. Spores scattered or concentrated in thin laminae,
some spores replaced by pyrite, some by carbonate; sparse laminao of Radiolana;
rare burrows filled by chert, carbonate, and anhydrite Scarce veinlets filled with
calcite. Lower contact not preserved, probably conformable and abruptly gradatiorial.
I
| Boii»y
•Cochron
JRqCtMT
Medium-gray dolomitic siltstone. Abundant silt-sized anhedral and subnedral dolomite;
s»lt-sized quartz common Interbedded and interlaminated dark-gray shate and
medium-gray line-grained catcite grainstone, packs tone, and lime mudstone Wavy to
discontinuous bods near top; becomes more discontinuous, contorted, and mottled
downward; shales have parallel to wavy laminae. Pyritjc; micacoous. Sparse burrows;
rare Lmgula and wood fragments. Grades downward into lighter gray dolomitic
siltstone with fewer shale inter bods Lower contact not preserved, probably
disconfonrtablo.
Pale brownish pink crystalline dolostone. Vuggy.
^Medium-gray shale. Dolomitic; silty.
69+
Pale brownish-pink crystalline dolostone Vuggy.
»-12,400
l£
| Y00hum
I
I
I ~
' Coirct
Figure 8- Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994)
16
-------
Injection Interval - Fasken Formation
The Rattlesnake AGI #1 well reaches total depth in the Fasken/Fusselman formation (Silurian in age), directly
below the Woodford formation. Dolomites at the top of the Fasken formation underwent multiple leaching
and diagenetic episodes which developed secondary porosity. This is evidenced in offset wells by the practice
of only drilling through the top 30' of the Fasken, in anticipation of encountering the best reservoir quality.
In Figure 8, the uppermost Silurian section is described as 'vuggy dolostone' in the core description. Beds
below the top of the Fasken section may also have similar petrophysical attributes if exposed to multiple
diagenetic events. Solution-collapse and karst breccia horizons can be found within inner platform deposits,
some occurring as much as 100 ft below the Fasken top (Ruppel and Holtz, 1994).
Porositv/Permeabilitv Development
Porosity in the Fasken formation at the Rattlesnake AGI #1 well location is typically moldic and intercrystalline
associated with leaching of allochem-rich intervals. Porosity is directly related to these leaching events which
occurred during and post-deposition, resulting in vugs and karst-like features. Figure 9 provides reservoir
information from core data within fields in the Wristen buildup and platform carbonate play. The average
porosity of these cores is 7.1% with an average permeability of 45.28 millidarcies (Ruppel and Holtz, 1994).
The porosity and permeability described in the offset core data indicate the Fasken formation provides
sufficient accessible pore space for the amount of fluid injection proposed.
Using the above values as reference points, the Rattlesnake AGI #1 porosity log (API No. 42-501-36998) was
evaluated. Figure 10 is the product of the petrophysical analysis performed on the open hole logs run within
the injection interval at the Rattlesnake AGI #1 well. A permeability curve was generated from the effective
porosity curve using the table in Figure 9 to establish the porosity-permeability relationship. In Figure 10,
the majority of the injection interval's porosity and permeability is found at the top of the Fasken formation,
which correlates with the diagenetic processes described above. These curves are extrapolated to the
injection site and used to establish reservoir characteristics in the plume model.
17
-------
Wristen
Fusselman
Buildups and
Thirtyone
Thirtyone
Shallow Platform
Platform
Ramp
Deep-Water
Carbonate play
Carbonate play
Carbonate play
Chert play
Porosity (%>
Numbe/ o' data points
33
30
16
35
Mean
7,93
7. to
e.4i
14,85
Mnimum
1.00
2.70
3.50
2.00
Maximum
17,70
14.00
0.50
30.00
Standard devation
4.01
2.67
1.75
6.76
Permeability (md)
dumber ot (Jala points
21
24
12
33
Mean
11.61
45.28
1.51
9.56
Minimum
0.60
2.90
0.40
1.00
Maximum
84.80
400.00
30.00
100.00
Standard deviation
22.48
99.17
8.36
22.23
Initial water saturation {%)
Number oi data points
24
28
10
31
Mean
26.96
31.55
24.70
31.46
Mmmnum
10.00
20.00
16.00
10.00
Maximum
50.00
55.00
40.00
45.00
Standard deviation
9.31
10.4b
7.39
8.33
Residua) oil saturation {%)
Number a', data points
8
13
5
22
Mean
34.06
30.54
21.30
29.17
Minimum
30.00
20.00
9.00
14.00
Maximum
50.00
35.00
35.00
48.20
Standard devation
6.99
4.61
11.66
9.76
Oil viscosity (op)
Number oi data points
11
12
5
21
Mean
0.69
1.10
0.33
0.68
Mrnmum
0.13
0.32
0.04
0.07
Maximum
1.08
2.00
1.00
1.03
Standard devation
0.81
0.75
0.40
0.42
Oil formation volume factor
Number oi data points
21
22
6
32
Mean
1.57
1.22
1.65
1.50
Mnirnum
1.05
1.05
1.31
1.30
Maximum
1.91
1.55
1.66
1.73
Standard deviation
0.28
0.14
0.48
0.16
Bubble-point pressure (psi)
Number of data points
9
9
5
19
Mean
2.272
1,055
3.750
2.752
Minimum
798
450
2.660
1.755
Maximum
4.C50
2,600
4,440
4.655
Standard devation
1.300
689
756
667
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays (Ruppel and Holtz, 1994)
-------
Low Perm
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
0
[PLJ]=11036.9
Figure 10- Rattlesnake AG I #1 open hole log (42-501-36998) with effective porosity (green) and permeability (black)
Formation Fluid
Four wells were identified through a review of chemical analyses of oil-field brines from the U.S. Geological
Survey National Produced Waters Geochemical Database v2.1 within the Devonian, Silurian-Devonian, or
Fusselman formations within 20 miles of the Rattlesnake AGI #1 well. The location of these wells is shown in
Figure 11. Water chemistry analyses conducted on oil-field brines in Gaines County, as reported to the Texas
19
-------
Water Development Board, provided additional data on Devonian and Silurian reservoir fluids. Results from
the synthesis of these two sources are provided in Table 1. The fluids have greater than 20,000 parts per
million ("ppm") total dissolved solids, therefore these aquifers are considered saline. These analyses indicate
the in-situ reservoir fluid of the Devonian, Silurian, and Fusselman formations are compatible with the
proposed injection fluids.
Figure 11 - Offset wells used for Formation Fluid Characterization
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples
Average
Low
High
Total Dissolved Solids (ppm)
41,428
23,100
55,953
pH
7,2
7.0
7.3
Sodium (ppm)
12,458
7,426
15,948
Calcium (ppm)
1,759
1,010
2,320
Chlorides (ppm)
23,423
12,810
31,930
Fracture Pressure Gradient
Fracture pressure gradient was estimated using Eaton's equation. Eaton's equation is commonly accepted
as the standard practice for the determination of fracture gradients. Poisson's ratio ("v"), overburden
gradient ("OBG"), and pore gradient ("PG") are all variables that can be changed to match the site-specific
injection zone. Through literature review and industry standards, we are able to determine the expected
20
-------
fracture gradient. First, 1.05 psi/ft and 0.465 psi/ft were assumed for both the overburden and pore
gradients, respectively. These values are considered best practice values when there are no site-specific
numbers available. For limestone/dolomite rock, the Poisson's ratio to be assumed to be 0.3 through
literature review (Molina, Vilarras, Zeidouni 2016). Using these values in the equation below, a fracture
gradient of 0.72 psi/ft was calculated. A 10% safety factor was then applied to this number resulting in
maximum allowed bottom hole pressure of 0.64 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.
For the upper confining interval, a similar fracture gradient as the limestone was calculated. Shale has an
increased chance to vertically fracture if the injection interval is fractured (Molina, Vilarras, Zeidouni 2016),
so assuming a Poisson's ratio equal to the injection interval was used as a conservative estimate. The lower
confining zone was assumed to be of a similar matrix to that of the injection interval, with the key difference
being that the formation is much tighter (lower porosity/permeability). The Poisson's ratio was assumed to
be slightly higher in this rock. As seen in Table 2, the fracture gradient is slightly higher than the upper zones.
Table 2 - Fracture Gradient Assumptions
Injection Interval
Upper Confining
Lower Confining
Overburden Gradient (psi/ft)
1.05
1.05
1.05
Pore Gradient (psi/ft)
0.465
0.465
0.465
Poisson's Ratio
0.30
0.30
0.31
Fracture Gradient psi/ft
0.72
0.72
0.73
FG +10% Safety Factor (psi/ft)
0.64
0.64
0.66
The following steps were taken to calculate fracture gradient:
FG = —-—(OBG - PG) + PG
1 — v
0.3
FG = 1_Q3(1-05 - °-465) + °-465 = °-72
FG with SF = 0.72 x (1 - 0.1) = 0.64
Lower Confining Zone - Montoya Formation
The low-permeability Montoya Formation is a tight limestone/dolomite that will act as the lower confining
unit for the injection interval. Figure 10 shows the decreasing trend in porosity of the limestone rock in the
lower section that was not exposed to leaching diagenesis. Porosity in the lower section can range from 2-
3% with permeabilities below 1 millidarcy. The Rattlesnake AGI #1 well drilled 6' into the Montoya formation,
but the section was not logged. The Montoya is anticipated to be roughly 250' thick. These petrophysical
characteristics represent ideal sealing properties to prohibit any migration of injected fluid outside of the
injection interval.
Local Structure
Regional structure in the area of the Rattlesnake AGI #1 well is dictated by carbonate buildups and structural
events causing anticlinal to synclinal features throughout the area. The Rattlesnake AGI #1 well is specifically
located at the base of a syncline with anticlinal features to the northeast, south, and east. Figure 12 is a
21
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structure map of the Silurian formation of subsea depths with the star representing the location of the
Rattlesnake AGI #1 well. The red and blue lines represent the cross-section reference lines.
Faulting can be seen to the south and east of the Rattlesnake AGI #1 well location. These faults were
interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure 12. Many of
these faults are minor, with offsets less than 50'. The nearest large fault is found southeast of the Rattlesnake
AGI #1 well and has an offset of roughly 120'. None of these faults project above the Wolfcamp formation,
rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. Production is
associated with a hydrocarbon trap set up by the larger fault to the southeast, indicating the fault is vertically
sealing in nature. If, in the unlikely event the faults' sealing properties are compromised post-injection,
secondary confinement is provided by the tight limestones found within the overlying Mississippian Lime
formation along with shale layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the
largest fault found southeast of the Rattlesnake AGI #1 well, terminates within the Atoka formation. Though
it crosses the Silurian section, this fault thrusts the Mississippian Lime upward against the Atoka shales. The
tight reservoir characteristics of the Mississippian Lime and shaley section of the Atoka create a confining
environment vertically and laterally to contain potential upward migration of buoyant fluids. Shales within
the Wolfcamp formation provide additional confining beds between overlying USDWs and the fault plane.
Figures 13 and 14 are north-south and west-east structural cross sections showing the structural dips. As
seen in these figures, the Woodford formation is laterally present above the injection interval, alleviating risk
of erosion of the upper sealant formation.
Larger versions of Figures 11, 12, 13 and 14 are provided in Appendix A.
22
-------
-------
-------
NW
3T?w'
42501105700000
1-667
TEXAS CRUDE OIL CO
+
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
42501358340000
ROBERTS UNIT
2
APACHE
42501335110000
CORNELL UNIT
3019D
EXXON MOBIL
SE
asr
MONTOYA [PUJ
25
-------
Injection and Confinement Summary
The lithologic and petrophysical characteristics of the Faskeri and Fusseiman formations at the Rattlesnake
AGI #1 well location indicate the formations have sufficient thickness, porosity, permeability, and lateral
continuity to accept the proposed injection fluids. The Woodford formation shale at the Rattlesnake AGI #1
well has low permeability and is of sufficient thickness and lateral continuity to serve as the upper confining
zone. Beneath the injection interval, the low permeability, low porosity Montoya formation is unsuitable for
fluid migration and serves as the lower confining zone. Deeper, laterally continuous formations, including the
Simpson Group, provide additional confinement.
Groundwater Hydrology
Yoakum County falls within the boundary of the Sandy Land Underground Water Conservation District. Three
aquifers are identified by the Texas Water Development Board's Aquifers of Texas report in the vicinity of the
proposed Rattlesnake AGI #1 well: the Dockum Aquifer, Edwards-Trinity Aquifer, and Ogallala Aquifer
(George, Mace and Petrossian, 2011). Table 3 references the aquifers' positions in geologic time and the
associated geologic formations. A schematic cross section in Figure 15, near the proposed Rattlesnake AGI
#1 well, illustrates the structure and stratigraphy of these water-bearing formations. Groundwater flow
direction is the same for the three aquifers, generally from northwest to southeast, Figure 16 (Teeple, et al.,
2021).
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and Yoakum Counties, Texas
(Teeple, et al. 2021)
Era
Period
Epoch or series
Geologic unit group
or formation
Lithologic descriptions
Hydrogeologic unit
Cenozoic
Tertiary
Pliocene
Ogallala Formation
Gravel, sand, silt,
and clay
High Plains
aquifer system
(Ogallala aquifer)
Miocene
Mesozoic
Cretaceous'
Comanchean
Series
Washita Group2
Shale and limestone
Edwards-T rinity
(High Plains)
aquifer system
Fredericksburg Group
Clay, shale, and
limestone
Trinity Group
Sand and gravel
Triassic
Upper
Dockum Group
Sillstone, mudstone,
shale, and sandstone
Dockum aquifer
26
-------
Figure 15- NW-SE Cross Section of aquifers in the Rattlesnake AG! #1 well area (George, Mac and Petrossian, 2011)
27
-------
IOCKLEV COI NTY 8 103°0'
/ •
HOC KLEV COl.Vn
"J \^J! In* • •• •Hv4. •
V , " •. A " *
r I J ' *1 nnvaJ^Sil'
/ • • t / • 'I** * i» 1
K.-.'- l\i^\\s>* I
lY\ 3| ~7 . 1
/ ' <8 jX • /• *> / ~**. i' >!
[ <. OTvKsl ,. • ,
icuiNfu" fr;—7
i if _ \ »V*^r"
C 1Q3°D' ,K
rrir
33°20' I
I ~
L-'
Y0AKUM
»v \ | x COUNTY
©#xr /
/ fMiu \ ~'
y .<
l«s
f Mjch
\ / n*L"IMkt jif
v^' (
ftpy ' ' v x liruu^lfcUi x
~ ' j
artr'
32"4G'
-HOCKLEY COUNTY
0 5 10 (SMILES
1 . 1 r i1 1
0 5 tO T5 KILOMETERS
Base modified tram U S Geological Survey 1 250 000-scale to 1 2,000.000-scale digital data.
Universal Transverse Mercator projection, ione 13
North American Datum of 15&3
Groundwater-level altitude, in
leal above North American
Vertical Oatum of 1988
|^m" >3,750
Hj- 3,500
3,250
3,000
<2,750
EXPLANATION
Study area boundary
Edwards-Trinity I High Plains} nquilor downdip enfant
Underground water conservation district boundary
Llano Estacado Underground Water Conservation District
Sandy Land Underground Water Conservation District
South Plains Underground Water Conservation District
Potenriometric contour Shows altitude at
which water level would have stood in
tightly cased wells. Contour interval is
100 feel Datum it North American
Vertical Datum of 1988 Dashed where
mlerred.
Groundwater How pallia Dashed where
interred
• Groundwater tevol measurement (Payne
and others. 2020)
Figure 16 - Potentiometric surfaces from wells completed in A, Ogallala aquifer, B, the Edwards-Trinity aquifer and C, the Dockum
aquifer (George, Mace and Petrossian, 2011).
The Dockum Aquifer is the oldest of the three aquifers, formed from Triassic-age Dockum Group sediments,
and underlies the Cretaceous Trinity and Fredericksburg Groups (Teeple, et al., 2021). Figure 17 shows the
subsurface and outcrop extent of the Dockum Aquifer. As shown in Figure 18, the total dissolved solids in
western Yoakum County exceed 5,000 milligrams per liter ("mg/L"), therefore the aquifer is considered
brackish.
28
-------
Dockum
Aquifer
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDBj
Figure 18 - Total dissolved solids in groundwater from the Dockum Aquifer (Ewing et at, 2008)
The Edwards-Trinity Aquifer is a collection of Cretaceous age sediments - primarily the Trinity Group Antlers
formation sandstone and limestones of the Fredericksburg Group, specifically the Comanche Peak and
Edwards formations. Figure 19 shows the subsurface and outcrop extent of the Edwards-Trinity Aquifer.
Freshwater infiltration to this aquifer is primarily from the overlying Ogallala Aquifer (George, Mace and
Petrossian, 2011).
29
-------
The Ogallala aquifer consists of sand, gravel, clay and silt sediments (George, Mace and Petrossian, 2011) and
produces the majority of the freshwater for Yoakum County. Figure 20 shows the subsurface and outcrop
extent of the Ogallala Aquifer.
The base of the deepest aquifer is separated from the injection interval by approximately 8,600' of rock,
including 576' of Salado salt. Though unlikely for reasons outlined in the confinement and potential leaks
sections, if migration of injected fluid did occur above the Woodford Shale, thousands of feet of tight
sandstone, limestone, shale, salt and anhydrite beds occur between the injection interval and the lowest
water-bearing aquifer.
30
-------
The TRRC's Groundwater Advisory Unit ("GAU") identified the base of Underground Sources of Drinking
Water ("USDW") at 375' at the location of the Rattlesnake AGI #1 well. Therefore, there is approximately
10,661' 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
Rattlesnake AGI #1 well is provided in Appendix B.
Description of the Injection Process
Current Operations
The 30-30 Facility and its associated Rattlesnake AGI #1 well began operating in March of 2019. Since
operations began, 258 million cubic feet ("MMCF") of treated acid gas ("TAG") has been injected, which
equates to 12,316 metric tons of C02. Over the life of the injection period, the average daily injection rate
has been 223 MSCF/d. The approximate current composition of the TAG stream is as follows;
Table 4 - Gas Composition of 30-30 Facility outlet
Component
Mol %
C02
89.68%
H2S
9.20%
Other
1.12%
31
-------
The 30-30 Facility is designed to compress, treat, and process natural gas produced from the surrounding
counties in Texas and New Mexico. The gas is dehydrated to remove the water content, then processed to
separate natural gas liquids which are then sold, along with the pipeline quality natural gas, to various
customers. TAG is then directly routed from the plant amine regen system to the Rattlesnake AGI #1 well.
The facility is manned 24 hours per day, 7 days per week.
Planned Operations
Stakeholder anticipates increasing the amount of CO2 injected into Rattlesnake AGI #1 well from the current
rate up to 16 MMSCF/d. Additional growth is expected both at Stakeholder facilities and regionally as rising
sour gas production and flaring reduction mandates create the need for additional CO2 and H2S disposal
capacity. Stakeholder plans to inject into this AGI well for another 14 years for a total of 17 years from the
start of injection in 2019.
Figure 21 shows a high-level view of the current process flow plus the prospective additional operations over
time.
Amine Regen
System
>96% C02
1,090-1,150 psig
CO, Offta ke
13% H2S, 87% COj
1,400-2,200 psig
AGI
Compression
Prospective Facilities
Meter
er XV
Meter
&
XV
A
l_
"l
I
-L
596-13% HjS, 87%-
95% C02
1,400-2,500 psig
Injection
Pumps
XV
Current Operation
AGI
Well
Figure 21 - 30-30 Facility Process Flow Diagram
Reservoir Characterization Modeling
The modeling software used to evaluate this project was Computer Modelling Group's GEM 2020.11 ("GEM")
simulator. Computer Modelling Group ("CMG") has put together one of the most accurate and technically
sound reservoir simulation software packages for conventional, unconventional, and secondary recovery.
GEM utilizes equation-of-state ("EOS") algorithms along with some of the most advanced computational
methods to evaluate compositional, chemical, and geochemical processes and characteristics to produce
highly accurate and reliable simulation models for carbon injection and storage. The GEM model is
recognized by the EPA for use in area of review delineation modeling as listed in the Class VI Well Area of
Review Evaluation and Corrective Action Guidance document.
The Silurian (Fasken/Fusselman) formation is the target formation for Rattlesnake AGI #1 well. The Petra
software package was used to create the geologic model of the target formation. The faulting and geologic
structure was then imported into GEM and used to create contours for the model grid.
Porosity and permeability estimates were determined using the porosity log from the Rattlesnake AGI #1
well and a petrophysical analysis was performed to correlate porosity values by depth with core porosities
32
-------
as shown in the Holtz paper. The Coates permeability equation was then used to calculate permeability with
depth. Both porosity and permeability are assumed to be laterally homogeneous in the reservoir.
The reservoir is assumed to be at hydrostatic equilibrium and initially saturated with 100% brine. An infinite
acting reservoir was created to simulate boundary conditions. The gas injectate is composed of H2S, CO2,
CH4, and other components as shown in Table 5. Core data from literature review was used to determine
residual gas saturation (Ruppel and Holtz, 1994). The modeled composition only takes into consideration the
carbon dioxide and hydrogen sulfide as they comprise nearly 99% of total stream. For the initial injection
period, these compositions are normalized up to 100%. For the proposed additional injection period, it is
expected that a larger portion of the gas added is carbon dioxide, changing the composition to ~93% CO2 and
~7% H2S.
Table 5 - Modeled Initial Gas Composition
Measured Current
2019-2024 Model
2024-2036 Model
Component
Composition (mol%)
Composition (mol%)
Composition (mol%)
Carbon Dioxide (C02)
89.678
90.696
92.921
Hydrogen Sulfide (H2S)
9.200
9.304
7.079
Methane (CI)
0.303
0
0
Ethane (C2)
0.058
0
0
Propane (C3)
0.108
0
0
N-Butane (NC4)
0.025
0
0
Hexane Plus (C6+)
0.628
0
0
Core data from literature review was used to determine relative permeability curves between carbon dioxide
and the connate brine within the Silurian-Devonian carbonates (Ruppel and Holtz, 1994). The key inputs
used in the model include an irreducible water saturation of 25% and a maximum residual gas saturation of
21%.
The grid contains 141 blocks in the x-direction (E-W) and 201 blocks in the y-direction (N-S), totaling 28,341
grid blocks per layer. The grid blocks are each 150' by 150' by layer thickness as specified in Table 6. This
results in the grid being 21,150' by 30,150' totaling just over a 23-square mile area (14,640 acres). Each layer
in the model was determined by identifying higher permeability zones as targets for injection from the logs
and assigning each high permeability and intermediary low permeability zone its own layer. One zone was
identified as being a karst limestone (layers 2-7). Due to the "karsted" nature of this rock, it was determined
that most of the injectate would flow into this zone. Therefore, the karst limestone was further split into
layers by permeability to provide higher resolution and more accurately simulate which layer will have more
gas flow into it. Figure 22 provides a detailed breakdown of the "karsted" rock.
33
-------
Permeability Distribution of Karst Zone
2
3
4
l—
(D
_l
5
6
7
1 10 100 1000
Permeability (mD)
Figure 22 - Permeability Distribution of Karst Limestone
In total, there are sixteen (16) layers in the model, representing ten (10) layers of pay and six (6) layers of
intermediary low permeability zones. The properties of each of these layers are summarized in Table 6
below.
Table 6 - CMG Model Layer Properties
Layer #
Top (ft)
Thickness (ft)
Permeability (mD)
Porosity
1
11,037
71
1
2.8%
2
11,108
57
47
8.0%
3
11,165
19
223
11.9%
4
11,184
16
15
6.3%
5
11,200
39
70
9.2%
6
11,238
11
228
12.3%
7
11,249
21
49
8.3%
8
11,270
251
2
3.7%
9
11,520
46
9
5.6%
10
11,566
13
3
4.3%
11
11,579
19
17
6.5%
12
11,597
14
2
3.9%
13
11,611
103
13
6.0%
14
11,714
46
2
3.7%
15
11,759
67
23
6.1%
16
11,826
125
2
3.6%
34
-------
Simulation Modeling
The primary objectives of the model simulation were to:
1) Estimate the maximum areal extent and density drift of the acid gas plume after injection
2) Assess the impact of offset saltwater disposal ("SWD") well injection on density drift of the plume
3) Assess the impact of offset producing wells on the density drift of the plume
4) Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone
5) Assess the likelihood of the acid gas plume migrating into potential leak pathways
The reservoir is assumed to be an aquifer filled with 100% brine. The salinity of the formation is estimated
to be 53,000 ppm (Texas Water Development Board, 1972). The acid gas stream is primarily composed of
C02 and H2S as stated previously. Core data was used to help generate relative permeability curves. Cores,
from the literature reviews previously discussed, that most closely represent the vuggy carbonate seen in
this region were identified and the Corey-Brooks equations were used to develop the curves. The lowest
residual gas saturation found in the cores was then used for a conservative estimate of plume size. From
offset injection well analysis, the initial reservoir pressure was determined to be 5,132 psi which is equivalent
to a 0.465 psi/ft pressure gradient. The fracture gradient of the injection zone was estimated to be 0.72
psi/ft, which was determined using Eaton's equation. A 10% safety factor was then applied to this number,
putting the maximum bottom-hole pressure allowed in the model at 0.64 psi/ft which is equivalent to 7,064
psi.
The model also takes into account offset saltwater disposal ("SWD") injection volumes within five (5) miles
of the Rattlesnake AGI #1 well. These SWDs create a pressure front that push the plume further up-dip of
the formation. A total of twenty (20) offset wells currently injecting into the target formation were identified.
Eleven (11) of these offset SWDs were out of the confines of the grid, but were still accounted for in the
model. Nine (9) salt-water disposals were modeled within the boundaries of the 23-square-mile grid. Two
(2) of these offset injectors are currently only permitted (not drilled) but were assumed to start active
injection within the first year of the model. Both permits were simulated at the forecasted injection rate
schedule for 30 years. These forecasts were provided by the operators of these wells. Historical injection
rates of each of the other existing wells were analyzed and projected into the model. This simulation includes
the effect of water injection on the density drift of the plume and bottom hole pressure.
Further review of the area revealed production wells in the Silurian-Devonian formation that could impact
the density drift of the plume by creating a "pressure sink". A "pressure sink" is an area of lower pressure
caused by the production of formation fluids. To simulate this effect, nine (9) production wells were grouped
together and their respective production rates combined into a single well to add more conservatism into
the model. These producers were forecasted an additional 15 years to simulate their potential economic
lifespan. This simulation includes the effect of fluid production on the density drift of the plume and bottom
hole pressure. Overall, the "pressure sink" has little effect on the density drift and, as discussed below, the
plume never reaches the producing wells.
The model runs for a total of 814 years, starting in 1965 with the beginning of offset production until the
calculated stabilization of the plume in 2779. The injection of TAG from Rattlesnake AGI #1 is modeled from
the beginning of injection in 2019 through the planned 14 years of future injection. The model also includes
the 57 years of historical plus 15 years of forecasted future oil and gas production.
Additionally, historical monthly injection rates of all nearby SWDs were incorporated into the model to
simulate any additional near-wellbore pressure increase that may occur due to offset injection. The
35
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modelling of the saltwater injection begins in 1984 when the first offset SWD well became operational. The
SWDs to the North were grouped into four (4) separate groups to simulate their combined effect on the
density drift of the plume. All offset injection wells and their groupings are included in Table 7. All offset
production wells are listed in Table 8.
Table 7 - All Offset SI/l/Ds included in the model
Grouping
API
Well Name
Well#
42-501-32511
SAWYER, DESSIE
1
42-501-02068
WEST, M. M.
2
Group 1
42-501-02053
NORTH CENTRAL OIL CO. "A"
1
42-501-01453
SMITH, EDS. HEIRS "B"
1
42-501-02059
SMITH, ED "C"
1W
Group 2
42-501-30051
JOHNSON
2
42-501-30001
JOHNSON
ID
Group 3
42-501-37066
MISS KITTY SWD 669
1W
42-501-36650
RUSTY CRANE 604
1W
Group 4
42-501-36745
SUNDANCE 642
1
42-501-33887
WINFREY 602
3WD
42-501-37252
Miller SWD
7
42-501-37367
BLONDIE 704
1W
42-501-37206
BRUSHY BILL 707
1WD
42-501-36622
WISHBONE FARMS 710
1W
Standalone
42-501-35834
ROBERTS UNIT
2
42-501-33297
STATE ELMORE
1
42-501-10238
SHEPHERD SWD
1
42-501-33511
CORNELL UNIT
3019D
42-501-32868
WILLARD UNIT
1WD
Table 8 - All Offset Producers included in the model
API
Well Name
Well #
42-501-10046
ELLIOTT, C.A.
2
42-501-10079
RANDALL, E
32
42-501-337932
RANDALL, E
40
42-501-33885
RANDALL, E
41L
42-501-34016
RANDALL, E
43 L
42-501-34017
RANDALL, E.
45 L
42-501-34023
RANDALL, E
42L
42-501-34024
RANDALL, E
44
42-501-35418
RANDALL, E
46
Rattlesnake AGI #1 came online in 2019 and the model simulated its historical monthly injection rates until
2024. After this initial period, it is conservatively assumed that the injection rate increases to the maximum
permitted rate of 16 MMSCF/d for the remainder of the active injection period in 2036. At this point, the
36
-------
Rattlesnake AGI #1 well stops injection while the offset SWD injectors continue operations for thirty more
years. Density drift then occurs until plume stabilizes, which was determined to be 814 years from the start
of the model in 1965. Stabilization of the plume is determined to occur when the model shows no further
lateral movement horizontally or vertically. The plume boundary is then defined by a weighted average gas
saturation in the aquifer of 3%.
The maximum plume extent during the 17-year Rattlesnake injection period is shown in Figure 23. The final
extent after 743 years of density drift after injection ceases is shown in Figure 24. The extensive time of the
modeled density drift of the plume is driven by the buoyant forces of the gas, the permeability/porosity of
the rock, and the residual gas saturation. Initially, the karsted region takes on most of the injection, but due
to the buoyant forces, it is slowly pushed up higher into the less permeable layers of the injection interval.
These lower permeable layers, increase the amount of time it takes for the plume to reach its maximum areal
extent. As all the inputs to the model were based on the most conservative approach, the maximum extent
of the plume will likely be smaller and the effective impact on reaching potential leakage pathways will be
minimal as the amount of CO2 at those far extents will be small.
State Elmore
Brushy Bills 707
Shepherd SWD
Rattlesnake AGI Plume
Global Mote froction(CQ2) 2036-Jqn-Ol K Plone: 2 of 16
-0.70
¦ -060
1050
o.
-
0.20
Group 2 Group 4 Group 3 Group 1
Blondie 704
Mi ter SWD
Rattlesnake AGI
Willard Unit
Roberts Unit
Production Wells
Cornell Unit
Figure 23 - AreaI View Gas Saturation Plume, 2036 (End of Injection)
37
-------
Brushy Bills 707
19,215'
Miller SWD
6,900'
Blondie 704
Production Wells
Rattlesnake AGI
Willard Unit
Roberts Unit
Cornell Unit
Group 2 Group 4 Group 3 Group 1
State Elmore
Shepherd SWD
1.00-—
!¦
090
080
-070
-060
-
t
-030
020
Rattlesnake AGI Plume
Global Mole Fractlon{C02) 2779-Doc-OI K Plane: 2 of 16
Figure 24- Area! View Gas Saturation Plume, 2779 (End of Density Drift)
Figure 25 shows the surface injection rate and bottom hole pressure over the injection period and the period
of density drift after injection ceases. The bottomhole pressure increases the most as the injection rate
reaches its peak, reaching a maximum pressure of 5,413 psi. This buildup of 280 psi keeps the bottomhole
pressure well below the fracture pressure of 7,064 psi. The maximum surface pressure associated with the
maximum bottomhole pressure reached is 2,494 psi.
16.000,000
I" 14.000,000
£ 12,000,000
= 10,000,000
o
¦ 8,000,000
O
6,000,000
£
a 4,000,000
s 2.000,000
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2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049 2051 2053 2055
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w
5220 c
at
5190 9*
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5160 —
— Rattlesnake AGI, Gas Rate SC - Daily
— Rattlesnake AGI, Well Bottom-hole Pressure
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time
38
-------
SECTION 3 - DELINATION OF MONITORING AREA
This section discusses the delineation of Maximum Monitoring Area ("MMA") and Active Monitoring Area
("AMA") as described in EPA 40 CFR §98.448(a)(l).
Maximum Monitoring Area
The MMA is defined as equal to or greater than the area expected to contain the free-phase C02 plume until
the C02 plume has stabilized plus an all-around buffer zone of at least one-half mile. 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 takes into account the
following considerations:
• 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 adequately predict the density drift of the plume
Acid gas injectate was analyzed by a third-party vendor to determine the initial composition used in the
model. The report is provided in Appendix C. The molar composition of the gas is primarily C02 with some
H2S and CH4. The change in molar composition was also incorporated into the model as future predominantly
C02 streams are added for injection. As discussed in Section 2, the gas was injected into the Silurian
formation, specifically, the Fasken/Fusselman formation. The geomodel was created based off the rock
properties seen in the Fasken/Fusselman.
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 2036, the areal
expanse of the plume will be 1,052 acres. The maximum distance between the wellbore and the edge of the
plume is approximately 0.87 miles to the southeast. After 743 additional years of density drift, the areal
extent of the plume is 2,177 acres with a maximum distance to the edge of the plume of approximately 1.35
miles to the southeast.
Figure 26 shows the plume boundary at the end of injection, the stabilized plume boundary and the MMA.
39
-------
f
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
6 Stabilized Plune
i
1/2-Mile Naxinua Monitoring Area CMHA)
Stakeholder Midstream
Yoakum Co., TX
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Figure 26 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area
Active Monitoring Area
The initial AMA will cover a 14-year monitoring period. This period equates to the time of expected future
injection. The AMA will be established by superimposing the area based on a half-mile buffer around the
anticipated plume location at the end of injection (2036) with the area of the projected free-phase C02 plume
at five additional years (2041). In this case, the plume boundary in 2041 is within the plume at 2036 plus a
half-mile buffer. By 2036 at the latest, a revised MRV plan will be submitted to define a new AMA. Figure 27
shows the area covered by the AMA.
Larger size versions of Figures 26 and 27 are provided in Appendix D.
40
-------
ID
1 Inch = 0.51 Mile
1:32,000 m
&
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
& 19-Year Plume
wi th
1/Z-Hile Active Monitoring Area (AHA)
Stakeholder Midstream
Yoakum Co.. TX
PCS: NADB3 TX-NC FIPS 4202
-------
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE
This section identifies the potential pathways for C02 to leak to the surface within the MMA and the
likelihood, magnitude and timing of such leakage. The potential leakage pathways are:
• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Leakage through the confining layer
• Leakage from Natural or Induced Seismicity
Leakage from Surface Equipment
The surface facilities at the 30-30 Facility are designed for injecting acid gas containing H2S, and therefore
minimize leakage points such as valves and flanges following industry standards and best practices. H2S gas
detectors are located around the facility and the well site. These gas detectors trigger alarms at 10 parts per
million ("ppm"). Additionally, all Stakeholder field personnel are required to wear H2S monitors which are
triggered at 5 ppm of H2S. A shut-in valve is located at the wellhead and is locally controlled by pressure,
with a high pressure and low pressure shut-off.
The facilities have been designed and constructed with additional safety systems to provide for safe
operations. These systems include Emergency Shutdown ("ESD") valves to isolate portions of the plant and
pipeline, pressure relief valves along the pipeline to prevent over pressurization, and flares to allow piping
and equipment to be de-pressured rapidly under safe and controlled operating conditions in the event of a
leak. Figures 28 and 29 display the facility safety plot plan, taken from the 30-30 H2S Contingency Plan, and
show the location of the H2S monitors in the vicinity of the plant and the Rattlesnake AGI #1 well. Should
Stakeholder construct additional C02 facilities, as indicated in Figure 21, a separate meter will be installed for
the additional stream in order to comply with the 40 CFR §98.448(a)(5) measurement. As this meter will be
in close proximity to the existing facilities, it will utilize the existing monitoring programs discussed previously.
Additionally, C02 monitors will be installed near the new meter and tied into the facility monitoring systems.
42
-------
Figure 28 - Site Plan, 30-30 Facility
43
-------
With the level of monitoring at the 30-30 Facility and the Rattlesnake AGI #1 well, any release of H2S and C02
would be quickly identified, and the safety systems would quickly minimize the volume of the release. The
C02 injected into the Rattlesnake AGI #1 is injected with H2S at a concentration of 10% (100,000 ppm). At
this high level of H2S concentration, even a small leakage would trigger personal and facility H2S monitors set
to alarm at 5 ppm and 10 ppm respectively. If any leakage were to be detected, the volume of C02 released
will 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).
A larger scale version of Figure 28 is provided in Appendix E.
Leakage from Existing Wells within MMA
Oil and Gas Operations within Monitoring Area
A significant number of wells have historically been drilled within the area of the Rattlesnake AGI #1 well,
however production has primarily been from the shallower San Andres formation in the Wasson Field. The
San Andres is separated from the Silurian-Devonian interval by 4,720' in this area. In addition to the primary
San Andres production, a few wells have produced from the Wolfcamp. The Wolfcamp is separated from the
Siluro-Devonian interval by is 1,800'. Within the projected plume area of the Rattlesnake AGI #1 well, there
are no penetrations of the injection interval. There are ten wells within the MMA that penetrate the
injection interval.
A review of the TRRC records for all of the wells which penetrate the injection interval within the MMA,
shows the wells were properly cased and cemented to prevent annular leakage of C02 to the surface. The
plugged wells are also adequately protected against migration from the Devonian by the placement of the
plugs within the wellbores. Additionally, the Rattlesnake AGI #1 well was designed to prevent migration from
the injection interval to the surface through the casing and cement placed in the well, as shown in Figure 29.
Mechanical integrity tests ("MIT") required under TRRC rules are run annually to verify the well and wellhead
can hold the appropriate amount of pressure. If the MIT were to indicate a leak, the well would be isolated
and the leak mitigated quickly to prevent leakage to the atmosphere.
A map of all wells within the MMA is shown in Figure 30. Figure 31 shows only those wells which penetrate
the injection interval within the MMA. The MMA review maps, a summary of all the wells in the MMA and
detailed wellbore schematics for those wells which penetrate the injection interval are provided in Appendix
F.
44
-------
Base of USDW@375'
Rustler @ 2,345'
Salado @ 2,443'
Yates @ 3,019'
Seven Rivers @ 3,440'
dH
Grayburg @ 4; 190'
San Andres @ 4,465'
DV Tool @ 4,275'
DV Tool @5,591'
Glorieta @ 6,316'
Clearfork @ 6,492'
Wichita @ 8,628'
12,500' -
13,000' -
15,500' -
GK
Upper Wolfcamp @ 9,239'
Strawn @ 10,030'
Atoka @ 10,230'
Woodford @ 10,973'
Devonian @ 11,036'
Wristen@ 11,268'
Fusselman@ 11,538' Ci)
Montoya @ 11,974'
¦
ir
DV Tool @9,575'
Packer @ 10,966'
TD@ 11,980'
KB:
N/A
BHF:
NA
GL:
3,627'
Spud:
5/27/2018
Casing/Tubing Information
Label
1
2
3
4
Type
Surface
Intermediate
Production
Tubing
OD
13-3/8"
9-5/8"
7"
3-1/2"
Weight
48
40
29
9,2
WT
.330
.395
.408
NA
Grade
H40/J55 STC
L- 80 BTC
L80 LTC
2535 Vam Top
L80 Vam Top:
G3 Vam Top'
Hole Size
17-1/2"
12-1/4"
8 3/4
6"
Depth Set
504'
5.498'
11,014'
10,966'
TOC
Surface
Surface
Surface
NA
Volume
510 sks
2,135 sks
760 sks
NA
LONQUIST & CO. LLC
PETROLEUM
ENER6Y
ENGINEERS
ADVISORS
HOUSTON'CALGARY
AUSTIN I WICHITA I DENVER
Stakeholder Midstream
Country: USA
Location: 33.07884, -103.904514
API No: 42-501-36998
Rattlesnake No. 1
State/Province: Texas
Site:
County/Parish: Yoakum
Survey:
Well Type/Status: AG I
Texas License F-9147
RRC District No:
Project No: LS 128
Date: 5/27/2022
12912 Hill Country Blvd Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Reviewed: SLP
Approved: SLP
Figure 29 - Rattlesnake AG! #1 Well bore Schematic
45
-------
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LONQUIST & CO LLC
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Figure 30 - Oil arid Gas Wells within the MMA
46
-------
1 Inch = 0.51 Mile
1:32,000 ^
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BATTLES NAKCAOI NO. 1
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Yoakum Co.. TX
PCS: NAD S3 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER | Date: 6/1/2022 | Approved by: RH
LONQUIST & CO LLC
+ Rattlesnake ACI No. 1 SHL
| ( 1/2-Mile luffer from Mix. Plume Extent IMMA)
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Figure 31 - Penetrating Oil and Gas Wells within the MMA
47
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Future Drilling
Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations, such as the Devonian, have proven to-date to be less productive or non-productive in this area,
which is why the location was selected for injection. Furthermore, any drilling permits issued by the TRRC in
the area of the Rattlesnake AGI #1 well include a list of formations for which oil and gas operators are
required to comply with TRRC Rule 13 (entitled "Casing, Cementing, Drilling, Well Control, and Completion
Requirements"). 16 TAC § 3.13. By way of example, see the Rattlesnake AGI #1 well drilling permit provided
in Appendix B. The Devonian is among the formations listed for which operators in Yoakum County (where
the Rattlesnake #1 is located) are required to comply with TRCC Rule 13 (Appendix B, pg. 5). TRRC Rule 13
requires oil and gas operators to set steel casing and cement across and above all formations permitted for
injection under TRRC Rule 9 or immediately above all formations permitted for injection under Rule 46 for
any well proposed within a one-quarter mile radius of an injection well. In this instance, any new well
permitted and drilled to the Rattlesnake AGI #1 well's injection zone, and located within a one-quarter mile
radius of the Rattlesnake AGI #1 well, will be required under TRRC Rule 13 to set steel casing and cement
above the Rattlesnake AGI #1 well injection zone. Additionally, Rule 13 requires operators to case and
cement across and above all potential flow zones and/or zones with corrosive formation fluids. The TRRC
maintains a list of such known zones by TRRC district and county and provides that list with each drilling
permit issued, which is also shown in the above-mentioned permit in Appendix B.
If any leakage were to be detected, the volume of C02 released will be quantified based on the operating
conditions at the time of release.
Groundwater wells
There are seven groundwater wells located within the MMA, as identified by the Texas Water Development
Board. All of the identified groundwater wells in the area have total depths less than or equal to 265', as
shown in Figure 32 and Table 9. One of the wells is located on the 30-30 facility property with a total depth
of 119'and is operated by Stakeholder.
The surface and intermediate casings of the Rattlesnake AGI #1 well, as shown in Figure 29, are designed to
protect the shallow freshwater aquifers consistent with applicable TRRC regulations and the GAU letter
issued for this location. See GAU letter included within Appendix B. The wellbore casings and cements also
serve to prevent C02 leakage to the surface along the borehole.
A larger scale version of Figure 32 is provided in Appendix F.
48
-------
1 Inch = 0.51 Mile
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Maximum Monitoring Area
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Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD 83 TX-NC FIPS 4202
-------
Table 9 - Groundwater Well Summary
State Well ID
Owner Name
Primary Use Well Depth Data Source
370449
Frances Barbini
Irrigation
237
SDRDB
443840
Frances Jean Barbini
Irrigation
250
SDRDB
482963
Santa Fe Midstream Permian
Industrial
119
SDRDB
510854
FRANCIS BARNINI
Irrigation
255
SDRDB
520249
Thomas Durham
Irrigation
264
SDRDB
543433
FRANCIS BARBIDI
Irrigation
240
SDRDB
84760
TEXACO PRODUCING INC
TWDB BW
Leakage Through Faults and Fractures
Faults were interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure
12. Faulting in this region terminates vertically below the Pennsylvanian-age rock. Secondary confining
shales within the Wolfcampian and younger strata provide additional, redundant confining layers that would
prevent C02from migrating into freshwater aquifers. None of the mapped faults project above the Wolfcamp
formation; rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. If, in
the unlikely event the faults' sealing properties are compromised post-injection, secondary confinement is
provided by the tight limestones found within the overlying Mississippianan Lime formation and the shale
layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the largest fault found SE of the
Rattlesnake AGI #1 well, terminates within the Atoka formation. Though it crosses the Silurian section, this
fault thrusts the Mississippian Lime upward against the Atoka shales. The tight reservoir characteristics of
the Mississippian Lime and shaley section of the Atoka create a confining environment vertically and laterally
to contain potential upward migration of buoyant fluids. Shales within the Wolfcamp formation provide
additional confining beds between overlying USDWs and the fault plane.
Should an unmapped fault exist within the plume boundary, the offset would be below 3D seismic resolution.
The offset would be less than the thickness of the Woodford shale, juxtaposing the Woodford against itself,
preventing vertical migration.
Fractures and subsequent subaerial exposure are responsible for porosity development within the injection
intervals. Open hole logs show little to no porosity development indicating the Woodford or Mississippian
Lime were not exposed at this location. Upward migration of injected gas through confining bed fractures is
unlikely.
50
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Leakage Through the Confining Layer
The Silurian-Devonian injection zones have competent sealing rocks above and below the porous sub-aerially
exposed carbonate. The properties of the overlying transgressive Woodford shale (widespread deposition,
high illite clay and organic matter composition, and low porosity and permeability) make an excellent sealing
rock to the underlying Silurian formation. Tight Mississippian Lime of roughly 660 ft, lay between Atoka and
Woodford shale formations, forming an impermeable upper seal to the injection interval. Above this
confining unit, correlative shales of the Wolfcamp, Abo and Tubb formations will prevent any upper fluid
migration. These impermeable shales are capped by hundreds of feet of the regionally present Salado
formation evaporites. The USDW lies above the sealing properties of the formations outlined above, making
stratigraphic migration of fluids into the USDW highly unlikely. The underlying low porosity and permeability
Montoya carbonate minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injected gas to the in-situ reservoir fluid makes migration below the lower confining layer
unlikely.
Leakage from Natural or Induced Seismicitv
The location of Rattlesnake AGI #1 is in an area of the Permian Basin that is inactive from a seismicity
perspective, whether induced or natural. A review of historical seismic events on the USGS's Advanced
National Seismic System site (from 1971 to present) and the Bureau of Economic Geology's TexNet catalog
(from 2017 to present), as shown in Figure 33, indicates the nearest seismic event occurred more than 60
miles away.
A regional analysis of the probabilistic fault slip potential across the Permian Basin (Snee & Zoback 2016), as
seen in Figure 34, further demonstrates that the Rattlesnake AGI #1 well is located in a seismically inactive
area and confirms that this area has little to no potential for an induced seismicity event.
Therefore, there is no indication that seismic activity poses a risk for loss of C02 to the surface within the
MMA.
Pressures will be kept significantly below the fracture gradient of the injection and confining intervals.
Additionally, continuous well monitoring combined with seismic monitoring will identify any operational
anomalies associated with a seismicity event.
51
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LLANO E S TAC A DO
(STAKED PLAIN)
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52
-------
New MexJco
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Ranch
Vaf l/erc/e Basin
fdwwtfs
L'af /e.'de \ /- '
Seism rcity:
o U„ 2.0-2.9 O Sines 3005
O 3.0-3.9 O 1970-2004
Oh,^
Fault slip potential (%):
0 10 2D 30 « 50+
Terrell
TM'W
icyw
IQCTW
NU
(/j
Swrf r>5 '& Co**>j
G/aisorit 1 ^
,..... , ^ Tom Green
and Hiils fault ^ / &Jrich,
*'
^rloxi SAN ANOELO
34°N
Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI ft1 location (Snee & Zobak 2016)
53
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SECTION 5 - MONITORING FOR LEAKAGE
This section discusses the strategy that Stakeholder 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). 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. Table 10 summarizes the
monitoring of potential leakage pathways to the surface. Monitoring will occur during the planned 17-year
injection period, or cessation of injection operations, plus a proposed 5-year post-injection period.
• Leakage from surface equipment
• Leakage through existing and future wells within MMA
• Leakage through faults , fractures or confining seals
• Leakage through natural or induced seismicity
Because the acid gas injection stream also contains H2S, any leakage would be detected by the H2S alarms
located around the facility and would be quickly addressed which would minimize the release of C02 into the
atmosphere.
Table 10- Summary of Leakage Monitoring Methods
Leakage Pathway
Monitoring Method
Leakage from surface equipment
Fixed H2S monitors throughout the AGI facility
Daily visual inspections
Personal H2S monitors
Distributed Control System Monitoring (Volumes and Pressures)
Leakage through existing wells
Fixed H2S monitor at the AGI well
SCADA Continuous Monitoring at the AGI Well
Annual Mechanical Integrity Tests ("MIT") of the AGI Well
Visual Inspections
Quarterly C02 Measurements within AMA
Leakage through groundwater wells
Annual GroundwaterSamples on Property
Leakage from future wells
H2S Monitoring during offset drilling operations
Leakage through faults and fractures
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage through confining layer
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage from natural or induced
seismicity
Seismic monitoring station to be installed
54
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Leakage from Surface Equipment
As the 30-30 Facility and the Rattlesnake AGI #1 well are designed to handle H2S, leakage from surface
equipment is unlikely to occur and would be quickly detected and addressed. The facility design minimizes
leak points through the equipment used and the type of connections are designed to minimize corrosion
points. The H2S in the injectate serves as a proxy for the release of C02. The facility and well site contain a
number of H2S alarms, set with a high alarm setpoint of 10 ppm of H2S, which are shown in Figure 28 above.
Additionally, all Stakeholder field personnel are required to wear H2S monitors, which trigger the alarm at 5
ppm H2S.
The AGI facility is continuously monitored through automated systems. In addition, field personnel conduct
daily visual field inspections of gauges, monitors and leak indicators such as vapor plumes. The effectiveness
of the internal and external corrosion control program is monitored through the periodic inspection of the
system, analysis of liquids collected from the line, and inspection of the cathodic protection system. These
inspections, in addition to the automated systems, allow Stakeholder to quickly respond to any leakage
situation. Monitoring will occur for the duration of injection and the post-injection period. 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).
Pressures and flowrates 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 at the time, including pressure, flow rate, size of the leak point opening, and duration
of the leak.
Leakage from Existing and Future Wells within MMA
Stakeholder continuously monitors and collects injection volumes, pressures, temperatures and gas
composition data, through their SCADA systems, for the Rattlesnake AGI #1 well. This data is reviewed by
qualified personnel and will follow response and reporting procedures when data is outside acceptable
performance limits. Rattlesnake AGI #1 has a pressure and temperature gauge placed in the injection stream
at its wellhead, and a pressure gauge on the casing annulus. A change of pressure on the annulus would
indicate the presence of a possible leak. Mechanical integrity tests ("MITs") performed annually would also
indicate the presence of a leak. Upon a negative MIT, the well would immediately be isolated and the leak
mitigated.
The ten offset penetrating wells within the MMA are adequately cased and cemented to prevent potential
leakage of C02 from the Rattlesnake AGI #1 well plume. Additionally, the plugged wells were done so in a
way to prevent migration of C02 as provided in Appendix E. As discussed previously, Rule 13 would ensure
that new wells in the field would be constructed in a manner to prevent migration from the injection interval.
In addition to the fixed and personal monitors described previously, Stakeholder will also establish and
operate an in-field monitoring program to detect any C02 leakage within the AMA. The scope of work will
include H2S and C02 monitoring at the AGI well site as well as minimum, quarterly atmospheric monitoring
near identified penetrations within the AMA. Upon approval of the MRV and through the post-injection
monitoring period, Stakeholder will have these monitoring systems in place. Additional monitoring will be
added as the AMA is updated over time.
At the well site, H2S and C02 concentrations will be monitored continuously with fixed monitors that detect
55
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atmospheric concentrations of H2S and C02. At penetrating well sites, Stakeholder will similarly measure
atmospheric concentrations of C02 and H2S using mobile gas monitors. This data will be recorded at least
quarterly.
Groundwater Quality Monitoring
Stakeholder will monitor the groundwater quality in fluids above the confining interval by sampling the well
on the facility property and analyzing the sample with a third-party laboratory on an annual basis. Any
significant changes to the water analysis would be investigated to determine if such change was a result of
leakage from the Rattlesnake AGI #1 well. The parameters to be measured will include pH, total dissolved
solids, total inorganic and organic carbons, density, temperature and other standard laboratory
measurements. Any significant differences in these parameters from the baseline sample will be evaluated
to determine if leakage of C02 to the USDW may have occurred.
Leakage through Faults, Fractures or Confining Seals
Stakeholder continuously monitors the operations of the Rattlesnake AGI #1 well through automated
systems. Any deviation from normal operating conditions indicating movement into a potential pathway
such as a fault or breakthrough of the confining seal would trigger an alert. Any such alert would be reviewed
by field personnel and action taken to shut in the well, if necessary. Field H2S monitoring systems would alert
field personnel for any release of H2S/C02 caused by such leakage.
Leakage through Natural or Induced Seismicitv
While the likelihood of a natural or induced seismicity event is extremely low, Stakeholder plans to install a
seismic monitoring station in the general area of the Rattlesnake AGI #1 well. The installation of this station
would start upon approval of the MRV plan, with an expected in-service data within six months after the
commencement of the installation project. This monitoring station will be tied in to the Bureau of Economic
Geology's TexNet Seismic Monitoring system. If a seismic event of 3.0 magnitude or greater is detected,
Stakeholder will review the injection volumes and pressures at the Rattlesnake AGI #1 well to determine if
any significant changes occur that would indicate potential leakage.
56
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SECTION 6 - BASELINE DETERMINATIONS
This section identifies the strategies Stakeholder will undertake to establish the expected baselines for
monitoring C02 surface leakage per 40 CFR §98.448(a)(4). Stakeholder will use the existing SCADA monitoring
systems to identify changes from expected performance that may indicate leakage of C02.
Visual Inspections
Daily inspections will be conducted by field personnel at the 30-30 Facility and the Rattlesnake AGI #1 well.
These inspections will aid with identifying and addressing issues timely to minimize the possibility of leakage.
If any issues are identified, such as vapor clouds or ice formations, corrective actions would be taken to
address such issues.
H2S Detection
H2S will be initially injected into the AGI well at a concentration of approximately ten (10) percent or 100,000
ppm. The concentration will drop to approximately seven (7) percent as additional volumes are added. H2S
gas detectors are located throughout the AGI facility and well site and are set to trigger the alarm at 10 ppm.
Additionally, all field personnel are required to wear personal H2S monitors, which are set to trigger the alarm
at 5 ppm. Any alarm would trigger an immediate response to protect personnel and verify that the monitors
are working properly. If monitors are working correctly, immediate actions would be taken to secure the
facility and mitigate potential leaks.
CO2 Detection
Any C02 release would be accompanied by H2S and therefore the H2S monitors at the facility would also serve
as a C02 release warning system. In addition to the fixed and personal monitors described previously,
Stakeholder will also establish and operate an in-field monitoring program to detect any C02 leakage within
the AMA. The scope of work will include H2S and C02 monitoring at the AGI well site as well as atmospheric
monitoring near identified penetrations within the AMA.
Operational Data
Upon starting injection operations, baseline measurements of injection volumes and pressures will be taken.
Any significant deviations over time will be analyzed for indication of leakage of C02.
Continuous Monitoring
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as per Texas regulations and Stakeholder's TRRC-
approved H2S Contingency Plan. Gas detectors and continuous monitoring systems would trigger an alarm
upon a release. The mass of the C02 released would be calculated for the operating conditions at the time,
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.
57
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No C02 emissions will occur from venting because of the high H2S concentrations. Blowdown emissions are
sent to flares and would be reported as part of the required reporting for the gas plant.
Groundwater Monitoring
An initial sample will be taken from the groundwater well on Stakeholder's property, identified as Well #
482963 in Table 9 above, upon approval of Stakeholder's MRV and prior to increasing injection. The sample
will be analyzed by a third-party laboratory to establish the baseline properties of the groundwater.
58
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SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE
EQUATION
This section identifies how Stakeholder will calculate the mass of C02 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the C02 emissions from equipment leaks and vented
emissions of C02 between the injection flow meter and the injection well, per 40 CFR §98.448(a)(5).
Mass of CO2 Received
Per 40 CFR §98.443, the mass of C02 received must be calculated using the specified C02 received equations
"unless you follow the procedures in 40 CFR §98.444(a)(4)." 40 CFR §98.444(a)(4) states that "if the C02 you
receive is wholly injected and is not mixed with any other supply of C02, you may report the annual mass of
C02 injected that you determined following the requirements under paragraph (b) of this section as the total
annual mass of C02 received instead of using Equation RR-1 or RR-2 of this subpart to calculate C02 received."
The C02 received for this injection well is wholly injected and not mixed with any other supply and the annual
mass of C02 injected will equal the amount received. Any future streams would be metered separately before
being combined into the calculated stream.
Mass of CO2 Injected
Per 40 CFR §98.444(b), since the flow rate 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:
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 (metric tons per
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682
Cco2,P,u = Quarterly C02 concentration measurement in flow for flow meter u in quarter p (wt. percent
C02, expressed as a decimal fraction)
p = Quarter of the year
u = Flow meter
4
p = 1
where:
quarter)
59
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Mass of CO2 Produced
The Rattlesnake AGI #1 well is not part of an enhanced oil recovery project; therefore, no C02 will be
produced.
Mass of CO2 Emitted by Surface Leakage
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as a major upset event. Gas detectors and continuous
monitoring systems would trigger an alarm upon a release. The mass of the C02 released would be calculated
for the operating conditions at the time, 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 C02 was released as a result 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:
C02 = 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 from subpart W will be used to calculate C02 emissions from equipment located on
the surface between the flow meter used to measure injection quantity and the injection wellhead
Mass of CO2 Sequestered
The mass of C02 sequestered in subsurface geologic formations will be calculated based off Equation RR-12,
as this well will not actively produce oil or natural gas or any other fluids, as follows:
X
X=1
Where:
CO 2 — C02i C02e C02fi
Where:
60
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C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year
CO21 = 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
CO 2fi - 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
CO 2fi will be calculated in accordance with Subpart W reporting of GHGs. Because no venting would occur
due to the high H2S concentrations of the injectate stream, the calculations would be based on the blowdown
emissions that would be sent to flares and would be reported as part of the required GHG reporting for the
gas plant.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
61
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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN
The Rattlesnake AGI #1 well currently reports GHGs under Subpart UU, but Stakeholder has elected to submit
an MRV plan under, and otherwise comply with, Subpart RR. The MRV plan will be implemented upon
receiving EPA approval. The Annual Subpart RR Report will be filed on March 31st of the year following the
reporting year.
62
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SECTION 9 - QUALITY ASSURANCE
This section identifies how Stakeholder plans to manage quality assurance and control, to meet the
requirements of 40 CFR §98.444.
Monitoring QA/QC
C02 Injected
• The flow rate of the C02 being injected will be measured with a volumetric flow meter, consistent
with industry best practices. These flow rates will be compiled quarterly.
• The composition of the C02 stream will be measured upstream of the volumetric flow meter with a
continuous gas composition analyzer or representative sampling consistent with industry best
practices.
• The gas composition measurements of the injected stream will be averaged quarterly.
• The C02 measurement equipment will be calibrated according to manufacturer recommendations.
C02 Emissions from Leaks and Vented Emissions
• Gas detectors will be operated continuously, except for maintenance and calibration.
• Gas detectors will be calibrated according to manufacturer recommendations and API standards.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
Measurement Devices
• Flow meters will be continuously operated except for maintenance and calibration.
• Flow meters will be calibrated according to the requirements in 40 CFR §98.3(i).
• Flow meters will be operated per an appropriate standard method as published by a consensus-
based standards organization.
• Flow meter calibrations will be traceable to the National Institute of Standards and Technology
(NIST).
All measured volumes of C02 will be converted to standard cubic meters at a temperature of 60 degrees
Fahrenheit and an absolute pressure of 1 atmosphere.
Missing Data
In accordance with 40 CFR §98.445, Stakeholder 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 C02 injected is missing, the amount will be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.
• Fugitive C02 emissions from equipment leaks from facility surface equipment will be estimated and
reported per the procedures specified in subpart W of 40 CFR §98.
63
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MRV Plan Revisions
If any of the changes outlined in 40 CFR §98.448(d) occur, Stakeholder will revise and submit an amended
MRV plan within 180 days to the Administrator for approval.
64
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SECTION 10 - RECORDS RETENTION
Stakeholder will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
three years and include:
• Quarterly records of the C02 injected
o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the C02 stream
• Annual records of the information used to calculate the C02 emitted by surface leakage from leakage
pathways.
• Annual records of information used to calculate C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
65
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References
Broadhead, Ronald E., 2005. Regional Aspects of the Wristen petroleum system, southeastern New Mexico:
New Mexico Bureau of Geology and Mineral Resources Open File Report, no. 485.
Comer, John B., 1991. Stratigraphic Analysis of the Upper Devonian Woodford Formation, Permian Basin,
West Texas and Southeastern New Mexico: Bureau of Economic Geology Report of Investigations, no. 201.
George, Peter G., Mace, Robert E., and Petrossian, Rima, 2011. Aquifers of Texas: Texas Water Development
Board Report, no 380.
Hoak, T., Sundberg, K., and Ortoleva, P. Overview of the Structural Geology and Tectonics of the Central Basin
Platform, Delaware Basin, and Midland Basin, West Texas and New Mexico: Department of Energy Open File
Report.
Molina, Oscar, Vilarras, Victor, and Zeidouni, Mehdi, 2016. Geologic carbon storage for shale gas recovery:
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18.
Ruppel, Stephen C. and Holtz, Mark H., 1994. Depositional and Diagenetic Facies Patterns and Reservoir
Development in Silurian and Devonian Rocks of the Permian Basin: Bureau of Economic Geology Report of
Investigations, no. 216.
Snee, Jens-Erik Lund and Zoback, Mark D., 2016. State of stress in the Permian Basin, Texas and New Mexico:
Implications for induced seismicity.
Teeple, Andrew P., Ging, Patricia B., Thomas, Jonathan V., Wallace, David S., and Payne, Jason D., 2021.
Hydrogeologic Framework, Geochemistry, Groundwater-Flow System, and Aquifer Hydraulic Properties Used
in the Development of a Conceptual Model of the Ogallala, Edwards-Trinity (High Plains), and Dockum
Aquifers In and Near Gaines, Terry, and Yoakum Counties, Texas: USGS Scientific Investigations Report 2021-
5009.
66
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APPENDICES
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APPENDIX A-GEOLOGY
APPENDIX A-l: SILURIAN STRUCTURE MAP
APPENDIX A-2: NE-SW CROSS SECTION
APPENDIX A-3: NW-SE CROSS SECTION
APPENDIX A-4: FORMATION FLUID SAMPLE WELL MAP
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mi
LONQU 1ST
SEQUESTRATION L
Stakeholder Midstream
-------
42501105700000
1-667
TEXAS CRUDE OIL CO
42501358340000
ROBERTS UNIT
2
APACHE
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
-------
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
Formation Fluid Sample Wells
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
| DENVER
• COLLEGE STATION |
[ BATON ROUGE • EDMONTON
-J- Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
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APPENDIX B -TRRC FORMS Rattlesnake AG I #1
APPENDIX B-l: UIC CLASS II ORDER
APPENDIX B-2: GAU GROUNDWATER PROTECTION DETERMINATION
APPENDIX B-3: DRILLING PERMIT
APPENDIX B-4: COMPLETION REPORT
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Christi Craddick, Chairman
Ryan Sitton, Commissioner
Wayne Christian, Commissioner
B-1
Danny Sorrells
Assistant Executive Director
Director, Oil and Gas Division
Leslie Savage
Assistant Director, Technical Permitting
Railroad Commission of Texas
OIL AND GAS DIVISION
PERMIT TO DISPOSE OF NON-HAZARDOUS OIL AND GAS WASTE BY INJECTION INTO A
POROUS FORMATION NOT PRODUCTIVE OF OIL AND GAS
PERMIT NO. 15848
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024
DOCKET NO. 8A-0312019
Authority is granted to inject Non-Hazardous Oil and Gas waste into the well identified herein in accordance
with Statewide Rule 9 of the Railroad Commission of Texas and based on information contained in the
application (Form W-14) dated March 12, 2018 for the permitted interval of the DEVONIAN formation and
subject to the following terms and special conditions:
RATTLESNAKE AGI (000000) LEASE
WASSON FIELD
YOAKUM COUNTY, DISTRICT 8A
WELL II
DENTIFIC ATION AND P]
ERMIT PA]
RAMET]
ERS:
Well No.
API No.
UIC Number
Permitted
Fluids
Top
Interval
(feet)
Bottom
Interval
(feet)
Maximum
Liquid
Daily
Injection
Volume
(BBL/day)
Maximum
Gas Daily
Injection
Volume
(MCF/day)
Maximum
Surface
Injection
Pressure
for Liquid
(PSIG)
Maximum
Surface
Injection
Pressure
for Gas
(PSIG)
1
50136998
000117143
C02, and
H2S
11,000
12,000
4,500
N/A
N/A
2,200
SPECIAL CONDITIONS:
Well No.
API No.
Special Conditions
1
50136998
1. Open hole completions shall have a plug back depth no deeper than the bottom of the
permitted injection interval.
2. The operator shall provide to the UIC section an annotated electric log, and a mud log if
available, of the subject well with the top(s) and bottom(s) of the permitted formation
indicated on the log. Top and bottom of the authorized injection interval may be modified
based on electric log or mud log indications of the top and bottom of the permitted
formations.
1701 NORTH CONGRESS AVENUE * POST OFFICE BOX 12967 * AUSTIN. TEXAS 78711-2967 * PHONE: 512/463-6792* FAX: 512/463-6780
TDD 800/735-2989 OR TDY 512/463-7284 * AN EQUAL OPPORTUNITY EMPLOYER* http://www.rrc.texas.gov
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STANDARD CONDITIONS:
1. Injection must be through tubing set on a packer. The packer must be set no higher than 100 feet above the
top of the permitted interval.
2. The District Office must be notified 48 hours prior to:
a. running tubing and setting packer;
b. beginning any work over or remedial operation;
c. conducting any required pressure tests or surveys.
3. The wellhead must be equipped with a pressure observation valve on the tubing and for each annulus.
4. Prior to beginning injection and subsequently after any work over, an annulus pressure test must be
performed. The test pressure must equal the maximum authorized injection pressure or 500 psig, whichever
is less, but must be at least 200 psig. The test must be performed, and the results submitted in accordance
with the instructions of Form H-5.
5. The injection pressure and injection volume must be monitored at least monthly and reported annually on
Form H-10 to the Commission's Austin office.
6. Within 30 days after completion, conversion to disposal, or any work over which results in a change in well
completion, a new Form W-2 or G-l must be filed to show the current completion status of the well. The
date of the disposal well permit, and the permit number must be included on the new Form W-2 or G-l.
7. Written notice of intent to transfer the permit to another operator by filing Form P-4 must be submitted to
the Commission at least 15 days prior to the date of the transfer.
8. This permit will expire when the Form W-3, Plugging Record, is filed with the Commission. Furthermore,
permits issued for wells to be drilled will expire three (3) years from the date of the permit unless drilling
operations have commenced.
Provided further that, should it be determined that such injection fluid is not confined to the approved interval, then
the permission given herein is suspended and the disposal operation must be stopped until the fluid migration from
such interval is eliminated. Failure to comply with all of the conditions of this permit may result in the operator
being referred to enforcement to consider assessment of administrative penalties and/or the cancellation of the
permit.
APPROVED AND ISSUED ON November 14. 2018.
Injection-Storage Permits Unit
IN-HOUSE AMENDMENT TO CORRECT THE RATE.
Note: This document will only be distributed electronically.
PERMIT NO. 15848
Page 2 of 2
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GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit
Form GW-2
B-2
Date Issued:
31 August 2017
GAU Number:
179154
Attention:
SANTA FE MIDSTREAM
API Number:
5700 GRANITE PARKWAY
County:
YOAKUM
PLANO, TX 75024
Lease Name:
Roberts Unit
Operator No.:
748093
Lease Number:
Well Number:
Total Vertical Depth:
Latitude:
Longitude:
Datum:
019212
1
11000
33.049990
-102.903464
NAD27
Purpose:
New Drill
Location:
Survey-Gibson, J H/Poole, J T; Block-D; Section-733
To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:
The interval from the land surface to a depth of 375 feet must be protected.
Note: Unless stated otherwise, this recommendation is intended to apply only to the subject well and not for area-wide use.
This recommendation is for normal drilling, production, and plugging operations only. It does not apply to saltwater disposal
operation into a nonproductive zone (RRC Form W-14).
This determination is based on information provided when the application was submitted on 08/30/2017. 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.gov
Rev. 02/2014
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APINa 42-501-36998
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
APPLICATION FOR PERMIT TO DRILL, RECOMPLETE, OR RE-ENTER
This facsimile W-l was generated electronically from data submitted to the RRC.
A certification of the automated data is available in the RRC's Austin office.
FORM W-l 07/2004
Drilling Permit #
839303
SWR Exception Case/Docket No.
Permit Status: Approved
B-3
1. RRC Operator No.
748093
2. Operator's Name (as shown on form P-5, Organization Report)
SANTA FE MIDSTREAM PERMIAN LLC
3. Operator Address (include street, city, state, zip):
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
4. Lease Name
RATTLESNAKE AGI
5. Well No.
1
GENERAL INFORMATION
6. Purpose of filing (mark ALL appropriate boxes): Ix] New Drill EH Recompletion EH Reclass EH Field Transfer EH Re-Enter
EH Amended EH Amended as Drilled (BHL) (Also File Form W-1D)
7. Wellbore Profile (mark ALL appropriate boxes): 0 Vertical EH Horizontal (Also File Form W-1H) EH Directional (Also File Form W-1D) EH Sidetrack
8. Total Depth
12000
9. Do you have the right to develop the [x] - | |
minerals under any right-of-way ?
10. Is this well subject to Statewide Rule 36 (hydrogen sulfide area)? IS Yes EH \0
SURFACE LOCATION AND ACREAGE INFORMATION
11. RRC District No.
8A
12. County I—, ,—, ,—, ,—¦
YOAKUM 13. Surface Location LXI Land 1—1 Bay/Estuary 1—1 Inland Waterway 1—1 Offshore
14. This well is to be located miles in a NW direction from DENVER CITY which is the nearest town in the county of the well site.
15. Section 16. Block 17. Survey 18. Abstract No.
733 D GIBSON, J H A-89
19. Distance to nearest lease line:
200 ft-
20. Number of contiguous acres in
lease, pooled unit, or unitized tract: 640
21. Lease ]
22. Survey
'erpendiculars: 200 ft from the NORTH line and 200 ft froi
nt
nt
ie WEST line.
PprppiiHii^iilars" 200 ft from the NORTH line and 200 ft froi
le WEST line.
23. Is this a pooled unit? EH Yes B No 24. Unitization Docket No:
25. Are you applying for Substandard Acreage Field? EH Yes (attach Form W-1A) S No
FIELD INFORMATION List all fields of anticipated completion including Wildcat. List one zone per line.
26. RRC
District No.
27. Field No.
28. Field Name (exactly as shown in RRC records)
29. Well Type
30. Completion Depth
31. Distance to Nearest
Well in this Reservoir
32. Number of Wells on
this lease in this
Reservoir
8A
95397001
WASSON
Injection Well
12000
0.00
1
8A
95399400
WASSON, NORTH (SAN ANDRES)
Injection Well
12000
0.00
1
BOTTOMHOLE LOCATION INFORMATION is required for DIRECTIONAL, HORIZONTAL, AND AMENDED AS DRILLED PERMIT APPLICATIONS
Remarks
[FILER Apr 16, 2018 5:16 PM]: Filing for an acid gas injection well.
Certificate:
I certify that information stated in this application is true and complete, to the
best of my knowledge.
Jessica Risien, Regulatory Compliance
Specialist Apr 25, 2018
Name of filer Date submitted
(281)8729300 jrisien@ntglobal.com
Phone E-mail Address (OPTIONAL)
RRC Use Only Data Validation Time Stamp: Apr 27, 2018 10:36 AM( As Approved' Version )
Page 1 of 1
-------
NOTE: Acreages shown hereon ere based on Information provided by others.
This plat represents a staked well location and does not represent a boundary survey.
The Information shown does not meet the current TBPLS minimum standards for boundary
surveys. Limited field measurements were acquired. Lease and tract line Information is
compiled from record information and additional sources.
NOTES:
1)
2)
3-J
ALL BEARINGS. DISTANCES ANO COORDINATES SHOWN
HEREON WERE DERIVED FROM <3. P S. OBSERVATIONS
CONVERTED TO THE TEXAS COORDINATE SYSTEM,
NORTH CENTRAL ZONE (NAD 1993). US FOOT AND ARE
REFERENCED TO THE LOCAL GNSS RTK NETWORK.
THE PROPOSED WELL LOCATION IS SITUATED N 37~W -
7.3 MILES FROM DENVER CITY, TX.
THE PROPOSED WELL LOCATION IS SITUATED SOW FROM
THE NSL AND 200 FROM THE WSL.
6
5°X'
rC-< liw
SECTION 704. BLOCK D
J. H. GIBSON SURVEY-
ABSTRACT NO. 1144
YOAKUM COUNTY. TX
704
733
RA TTLESMAKE AGf No.
(PROPOSED)
.0^
SURFACE L OCA T/ON
NAD 83, TX-NC, U.S. FT.
NORTH/NG/Y; 7093713.4ST
EASTING/X 619409-13"
LATITUDE (DDJ- 33.05134722°
LONGITUDE (DO)- -102.90450555*
NAD 27, TX-NC, US- FT,
NORTHfNG/Y: 546285.34*
EAST/NG/X; 344968.61'
LA TTTUDE (DO)- 33.05124473"
LONGITUDE (DO)- -102.90401331°
SURFACEELEVA T/ON- 3627.05-
732
*
83^8
2
5>^0
S
Af /=>&?AfMA/LLG
rtATTL£SA/j4/C£-s4G/A/o. 7
*/.M. G/&SOA/ SURWEK
SEGT/OA/ 733, &LOC/C0
yOAKt/AS GCHSA/TX TjEXAS
m Y aHcmws80i*a,7x:7B>
IhtebkityRk
i ] Positions, llc
-------
Railroad Commission of Texas
PERMIT TO DRILL, RE-COMPLETE, OR RE-ENTER ON REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
CONDITIONS AND INSTRUCTIONS
Permit Invalidation. It is the operator's responsibility to make sure that the permitted location complies with Commission density and
spacing rules in effect on the spud date. The permit becomes invalid automatically if, because of a field rule change or the drilling of another
well, the stated location is not in compliance with Commission field rules on the spud date. If this occurs, application for an exception to
Statewide Rules 37 and 38 must be made and a special permit granted prior to spudding. Failure to do so may result in an allowable not being
assigned and/or enforcement procedures being initiated.
Notice Requirements. Per H.B 630, signed May 8,2007, the operator is required to provide notice to the surface owner no later than the
15th business day after the Commission issues a permit to drill. Please refer to subchapter Q Sec. 91.751-91.755 of the Texas Natural
Resources Code for applicability.
Permit expiration. This permit expires two (2) years from the date of issuance shown on the original permit. The permit period will not
be extended.
Drilling Permit Number. The drilling permit number shown on the permit MUST be given as a reference with any notification to the
district (see below), correspondence, or application concerning this permit.
Rule 37 Exception Permits. This Statewide Rule 37 exception permit is granted under either provision Rule 37 (h)(2)(A) or 37(h)(2)(B).
Be advised that a permit granted under Rule 37(h)(2)(A), notice of application, is subject to the General Rules of Practice and Procedures
and if a protest is received under Section 1.3, "Filing of Documents," and/or Section 1.4, "Computation of Time," the permit may be deemed
invalid.
Before Drilling
Fresh Water Sand Protection. The operator must set and cement sufficient surface casing to protect all usable-quality water, as defined by
the Railroad Commission of Texas (RRC) Groundwater Advisory Unit (GWAU). Before drilling a well, the operator must obtain a letter from
the Railroad Commission of Texas stating the depth to which water needs protection, Write: Railroad Commission of Texas, Groundwater
Advisory Unit (GWAU), P.O. Box 12967, Austin, TX 78711-3087. File a copy of the letter with the appropriate district office.
Accessing the Well Site. If an OPERATOR, well equipment TRANSPORTER or WELL service provider must access the well site from a
roadway on the state highway system (Interstate, U.S. Highway, State Highway, Farm-to-Market Road, Ranch-to-Market Road, etc.), an
access permit is required from TxDOT. Permit applications are submitted to the respective TxDOT Area Office serving the county where the
well is located.
Water Transport to Well Site. If an operator intends to transport water to the well site through a temporary pipeline laid above
ground on the state's right-of-way, an additional TxDOT permit is required. Permit applications are submitted to the respective
TxDOT Area Office serving the county where the well is located.
^NOTIFICATION
The operator is REQUIRED to notify the district office when setting surface casing, intermediate casing, and production casing, or when
plugging a dry hole. The district office MUST also be notified if the operator intends to re-enter a plugged well or re-complete a well into a
different regulatory field. Time requirements are given below. The drilling permit number MUST be given with such notifications.
During Drilling
Permit at Drilling Site : A copy of the Form W-l Drilling Permit Application, the location plat, a copy of Statewide Rule 13
alternate surface casing setting depth approval from the district office, if applicable, and this drilling permit must be kept at the
permitted well site throughout drilling operations.
*Notification of Setting Casing : The operator MUST call in notification to the appropriate district office (phone number shown the
on permit) a minimum of eight (8) hours prior to the setting of surface casing, intermediate casing, AND production casing. The
individual giving notification MUST be able to advise the district office of the drilling permit number.
*Notification of Re-completion/Re-entry : The operator MUST call in notification to the appropriate district office (phone number
shown on permit) a minimum of eight (8) hours prior to the initiation of drilling or re-completion operations. The individual giving
notification MUST be able to advise the district office of the drilling permit number.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 1 of 5
-------
Completion and Plugging Reports
Hydraulic Fracture Stimulation using Diesel Fuel: Most operators in Texas do not use diesel fuel in hydraulic fracturing fluids.
Section 322 of the Energy Policy Act of 2005 amended the Underground Injection Control (UIC) portion of the federal Safe Drinking Water
Act (42 USC 300h(d)) to define "underground Injection" to EXCLUDE " ...the underground injection of fluids or propping agents (other
than dieselfluels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities." (italic and underlining
added.) Therefore, hydraulic fracturing may be subject to regulation under the federal UIC regulations if diesel fuel is injected or used as a
propping agent. EPA defined "diesel fuel" using the following five (5) Chemical Abstract Service numbers: 68334-30-5 Primary Name: Fuels,
diesel; 68476-34-6 Primary Name: Fuels, diesel, No. 2; 68476-30-2 Primary Name: Fuel oil No. 2; 68476-31-3 Primary Nmae: Fuel oil, No.
4; and 8008-20-6 Primary Name: Kerosene. As a result, an injection well permit would be required before performing hydraulic fracture
stimulation using diesel fuel as defined by EPA on any well in Texas. Hydraulic fracture stimulation using diesel fuel as defined by EPA on a
well in Texas without an injection well permit could result in enforcement action.
Producing Well: Statewide Rule 16 states that the operator of a well shall file with the Commission the appropriate completion report
within thirty (30) days after completion of the well or within ninety (90) days after the date on which the drilling operation is completed,
whichever is earlier. Completion of the well in a field authorized by this permit voids the permit for all other fields included in the permit
unless the operator indicates on the initial completion report that the well is to be a dual or multiple completion and promptly submits an
application for multiple completion. All zones are required to be completed before the expiration date on the existing permit. Statewide Rule
40(d) requires that upon successful completion of a well in the same reservoir as any other well previously assigned the same acreage,
proration plats and P-15s (if required) must be submitted with no double assignment of acreage.
Dry or Noncommercial Hole : Statewide Rule 14(b)(2) prohibits suspension of operations on each dry or non-commercial well without
plugging unless the hole is cased and the casing is cemented in compliance with Commission rules. If properly cased, Statewide Rule 14(b)(2)
requires that plugging operations must begin within a period of one (1) year after drilling or operations have ceased. Plugging operations must
proceed with due diligence until completed. An extension to the one-year plugging requirement may be granted under the provisions stated in
Statewide Rule 14(b)(2).
Intention to Plug : The operator must file a Form W-3 A (Notice of Intention to Plug and Abandon) with the district office at least five (5)
days prior to beginning plugging operations. If, however, a drilling rig is already at work on location and ready to begin plugging operations,
the district director or the director's delegate may waive this requirement upon request, and verbally approve the proposed plugging
procedures.
*Notification of Plugging a Dry Hole : The operator MUST call in notification to the appropriate district office (phone number shown on
permit) a minimum of four (4) hours prior to beginning plugging operations. The individual giving the notification MUST be able to advise
the district office of the drilling permit number and all water protection depths for that location as stated in the Texas Commission on
Environmental Quality letter.
DIRECT INQUIRIES TO: DRILLING PERMIT SECTION, OIL AND GAS DIVISION
PHONE
(512) 463-6751
MAIL:
PO Box 12967
Austin, Texas, 78711-2967
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 2 of 5
-------
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
PERMIT TO DRILL, DEEPEN, PLUG BACK, OR RE-ENTER ON A REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
PERMIT NUMBER
839303
DATE PERMIT ISSUED OR AMENDED
04/27/2018
DISTRICT
8A
API NUMBER
42-501-36998
FORM W-l RECEIVED
04/25/2018
COUNTY
YOAKUM
TYPE OF OPERATION
New Drill
WELLBORE PROFILE(S)
Vertical
ACRES
640.0
OPERATOR 748093
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
NOTICE
This permit and any allowable assigned may
be revoked if payment for fee(s) submitted to
the Commission is not honored.
District Office Telephone No:
(806) 698-6509
LEASE NAME
RATTLESNAKE AGI
WELL NUMBER
1
LOCATION
7.3 miles NW direction from DENVER CITY
TOTAL DEPTH
12000
Section, Block and/or
SECTION 733 BLOCK D ABSTRACT 89
SURVEY GIBSON, J H
DISTANCE TO SURVEY LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST LEASE LINE
200.0
DISTANCE TO LEASE LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST WELL ON LEASE
See FIELD(s) Below
FIELD(s) and LIMITATIONS:
* SEE FIELD DISTRICT FOR REPORTING PURPOSES *
FIELDNAME ACRES DEPTH WELL# DIST
LEASE NAME NEAREST LEASE NEAREST WELL
WASSON "640!0 12000 1 8A
RATTLESNAKE AGI 200 0 0.0
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
WASSON, NORTH (SAN ANDRES) "64o!o 12000 1 8A
RATTLESNAKE AGI 200.0 0.0
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 3 of 5
-------
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
THE FOLLOWING RESTRICTIONS APPLY TO ALL FIELDS
This well shall be completed and produced in compliance with applicable special field or statewide spacing and density rules. If this well is
to be used for brine mining, underground storage of liquid hydrocarbons in salt formations, or underground storage of gas in salt formations,
a permit for that specific purpose must be obtained from Environmental Services prior to construction, including drilling, of the well in
accordance with Statewide Rules 81, 95, and 97.
This well must comply to the new SWR 3.13 requirements concerning the isolation of any potential flow zones and zones with corrosive
formation fluids. See approved permit for those formations that have been identified for the county in which you are drilling the well in.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 4 of 5
-------
Railroad Commission of Texas
Oil and Gas Division
SWR #13 Formation Data
YOAKUM (501) COUNTY
l-'oniiiilioii
Koniiirks
Order
I.ITcc(i\c
Diilo
RED BED-SANTA ROSA
1
01/01/2014
YATES
2
01/01/2014
SAN ANDRES
high flows, H2S, corrosive
3
01/01/2014
GLORIETA
4
01/01/2014
CLEARFORK
Active C02 Flood
5
01/01/2014
WICHITA
6
01/01/2014
LEONARD
7
01/01/2014
WOLFCAMP
8
01/01/2014
PENNSYLVANIAN
9
01/01/2014
STRAWN
10
01/01/2014
MISSISSIPPIAN
11
01/01/2014
DEVONIAN
12
01/01/2014
DEVONIAN-SILURIAN
13
01/01/2014
The above list may not be all inclusive, and may also include formations that do not intersect all wellbores. The listing order of the Formation
information reflects the general stratigraphic order and relative geologic age. This is a dynamic list subject to updates and revisions. It is the
operator's responsibility to make sure that at the time of spudding the well the most current list is being referenced. Refer to the RRC website
at the following address for the most recent information, http://www.rrc.texas.gov/oil-gas/compliance-enforcement/rule-13-geologic-
formation-info
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 5 of 5
-------
B-4
RAILROAD COMMISSION OF TEXAS Form G-1
1701 N. Congress Status: Approved
P.O. Box 12967 Date: 07/25/2019
Austin, Texas 78701-2967 Tracking No.: 205926
GAS WELL BACK PRESSURE TEST, COMPLETION OR RECOMPLETION REPORT, AND LOG
OPERATOR INFORMATION
Operator Name: santa fe midstream permian llc Operator No.: 748093
Operator Address: 5830 granite pkwy ste 1025 plano, tx 75024-0000
WELL INFORMATION
API No.: 42-501-36998
County: YOAKUM
Well No.: 1
RRC District No.: 8A
Lease Name: RATTLESNAKE AG I
Field Name: WASSON
RRC Gas ID No.: 286838
Field No.: 95397001
Location: Section: 733, Block: D, Survey: GIBSON, J H, Abstract: 89
Latitude:
Longitude:
This well is located 7.3 miles in a nw
direction from Denver city,
which is the nearest town in the county.
FILING INFORMATION
Purpose of filing: Well Record Only
Type of completion: New Well
Well Type: Active UIC
Completion or Recompletion Date: 08/31/2018
Type of Permit
Date Permit No.
Permit to Drill, Plug Back, or Deepen
04/27/2018 839303
Rule 37 Exception
Fluid Injection Permit
O&G Waste Disposal Permit
11/14/2018 15848
Other:
COMPLETION INFORMATION
ISpud date: 07/16/2018
Date of first production after rig released: 08/31/2018 I
Date plug back, deepening, recompletion, or Date plug back, deepening, recompletion, or
drilling operation commenced: 07/16/2018
drilling operation ended: 08/31/2018
Number of producing wells on this lease in
Distance to nearest well in lease &
this field (reservoir) including this well:
1 reservoir (ft.): 0.0
Total number of acres in lease: 640.00
Elevation (ft.): 3627 GR
Total depth TVD (ft.): 11980
Total depth MD (ft.):
Plug back depth TVD (ft.): 11980
Plug back depth MD (ft.):
Was directional survey made other than
Rotation time within surface casing (hours): 72.0
inclination (Form W-12)? Yes
Is Cementing Affidavit (Form W-15) attached? Yes
Recompletion or reclass? No
Multiple completion? No
Type(s) of electric or other log(s) run: Combo of Induction/Neutron/Density/Sonic
Electric Log Other Description:
Location of well, relative to nearest lease boundaries Off Lease: No
of lease on which this well is located:
200.0 Feet from the North Line and
200 0 Feet from the West Line of the
rattlesnake agi Lease.
FORMER FIELD (WITH RESERVOIR) & GAS ID OR OIL LEASE NO.
Field & Reservoir
Gas ID or Oil Lease No. Well No. Prior Service Type
Page 1 of4
-------
G1: N/A
PACKET: N/A
FOR NEW DRILL OR RE-ENTRY, SURFACE CASING DEPTH DETERMINED BY:
GAU Groundwater Protection Determination Depth (ft.): 2025.0 Date: 01/12/2018
SWR 13 Exception Depth (ft.):
GAS MEASUREMENT DATA
I Date of test: Gas measurement method(s):
Gas production during test (MCF):
Was the well preflowed for 48 hours? No
Orif. or 24 hr. Coeff.
Run Line Choke Orif. Or Choke Static Pm or Diff
No. size Size (in.) (in.) Choke (in.) (hw)
Flow
Temp Temp. Gravity
(°F) (l-tt) (hg)
Compress
(Fpv)
Volume
(MCF/day)
N/A
FIELD DATA AND PRESSURE CALCULATIONS
Gravity (dry gas):
Gas-Liquid Hydro Ratio (CF/Bbl):
Avg. shut in temp. (°F):
Gravity (liquid hydrocarbons) (Deg. API):
Gravity (mixture): Gmix=
Bottom hole temp, and depth: °F@ ft
Run No. Time of Run (Min.)
Choke Size (in.) Wellhead Pressure (PSIA) Wellhead Flow Temp (°F )
N/A
CASING RECORD
Casing Hole Setting Multi - Multi - Cement Slurry Top of TOC
Type of
Size
Size
Depth Stage Tool Stage Shoe Cement Amount Volume Cement Determined
Row Casing
(in.)
(in.)
(ft.)
Depth (ft.) Depth (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
1 Surface
13 3/8
17 1/2
504
c
510
687.5
0
Circulated to Surface
3 Intermediate
9 5/8
12 1/4
5498
5498
c
485
797.0
4275
Circulated to Surface
2 Intermediate
13 3/8
17 1/2
5498
4275
c
1650
3045.0
0
Circulated to Surface
6 Conventional Production
7
8 3/4
11023
WELL
60
337.0
9575
Calculation
LOCK
5 Conventional Production
7
8 3/4
11023
5591
PREM
380
906.5
0
Circulated to Surface
PLUS
4 Conventional Production
7
8 3/4
11023
9575
PREM
380
906.5
5591
Calculation
PLUS
LINER RECORD
Cement
Slurry
Top of
TOC
Liner Hole
Liner
Liner
Cement
Amount
Volume
Cement
Determined
Row Size (in.) Size (in.)
Top (ft.)
Bottom (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
N/A
TUBING RECORD
Row
Size (in.)
Depth Size (ft.)
Packer Depth (ft.)/Type
1
3 1/2
10966
10966 / HALLIBURTON
BWD
PRODUCING/INJECTION/DISPOSAL INTERVAL
Row
Open hole?
From (ft.)
To (ft.)
1
Yes
L 11025
11980
Page 2 of4
-------
ACID, FRACTURE, CEMENT SQUEEZE,
CAST IRON BRIDGE PLUG, RETAINER, ETC.
Was hydraulic fracturing treatment performed? No
Is well equipped with a downhole actuation
sleeve? No
If yes, actuation pressure (PSIG):
Production casing test pressure (PSIG) prior to
Actual maximum pressure (PSIG) during hydraulic
hydraulic fracturing treatment:
fracturing:
Has the hydraulic fracturing fluid disclosure been
reported to FracFocus disclosure registry (SWR29)?
No
Row Type of Operation Amount and Kind of Material Used Depth Interval (ft.)
N/A
FORMATION RECORD
Is formation
Formations Encountered Depth TVD (ft.) Depth MP (ft.) isolated? Remarks
YATES
Yes
3019.0
Yes
SAN ANDRES - HIGH FLOWS, H2S,
Yes
4465.0
Yes
CORROSIVE
GLORIETA
Yes
6316.0
Yes
CLEARFORK - ACTIVE C02 FLOOD
Yes
6492.0
Yes
WICHITA
Yes
8628.0
Yes
UPPER WOLFCAMP
Yes
9239.0
Yes
STRAWN
Yes
10030.0
Yes
ATOKA
Yes
10230.0
Yes
WOODFORD
Yes
10973.0
Yes
DEVONIAN
Yes
11036.0
No
DISPOSAL
WRISTEN
Yes
11268.0
No
DISPOSAL
FUSSELMAN
Yes
11538.0
No
DISPOSAL
MONTOYA
Yes
11974.0
No
DISPOSAL
RED BED-SANTA ROSA
No
No
NOT IN AREA
LEONARD
No
No
NOT IN AREA
WOLFCAMP
No
No
NOT IN AREA
PENNSYLVANIAN
No
No
NOT IN AREA
STRAWN
No
No
NOT IN AREA
MISSISSIPPIAN
No
No
NOT IN AREA
Do the producing interval of this well produce H2S with a concentration in excess of 100 ppm (SWR 36)? No
s the completion being downhole commingled (SWR 10)? No
REMARKS
NEW WELL PUTTING ON SCHEDULE.
Page 3 of4
-------
OPERATOR'S CERTIFICATION
Printed Name: Karen Zornes
Title:
Telephone No.: (281) 872-9300
Date Certified: 06/25/2019
Page 4 of4
-------
APPENDIX C - GAS COMPOSITION
-------
C-1
1 rv » n,,
natural Gas Analysis
www.permianls.com
575.397.3713 2609 W Marland HobbS NM 88240
11093G
30/30 Acid Gas
Sample Point Code
Sample Point Name
C6+ Gas Analysis Report
30/30 Acid Gas
Sample Point Location
Laboratory Services
Date Sampled
2021048523
1781
E Benavides - Spot
Source Laboratory
Lab File No
Container Identity
Sampler
USA
USA
USA
Texas
District
Area Name
Field Name
Facility Name
Nov 16, 2021
Nov 16, 2021
Nov 19, 2021 09:59
Nov 19, 2021
Date Effective
System Administrator
Ambient Temp (°F)
Flow Rate (Mcf)
Analyst
Date Received
21 @ 129
Press PSI @ Temp °F
Source Conditions
Date Reported
Stakeholder Midstream
30/30
Operator
Lab Source Description
Component
Normalized
Mol %
Un-Normalized
Mol %
GPM
H2S (H2S)
9.2000
9.2
Nitrogen (N2)
0.0000
0
C02 (C02)
89.6780
98.775
Methane (CI)
0.3030
0.331
Ethane (C2)
0.0580
0.063
0.0150
Propane (C3)
0.1080
0.118
0.0300
I-Butane (IC4)
0.0000
0
0.0000
N-Butane (NC4)
0.0250
0.027
0.0080
I-Pentane (IC5)
0.0000
0
0.0000
N-Pentane (NC5)
0.0000
0
0.0000
Hexanes Plus (C6+)
0.6280
0.686
0.2710
TOTAL
100.0000
109.2000
0.3240
Method(s): Gas C6+ - GPA 2261, Extended Gas - GPA 2286, Calculations - GPA 2172
Analyzer Information
Device Type: Gas Chromatograph Device Make: Shimadzu
Device Model: GC-2014 Last Cal Date: Nov 14, 2021
Gross Heating Values (Real, BTU/ft3)
14.696 PSI @ 60.00 A°F 14.65 PSI @ 60.00 A°F
Dry Saturated Dry Saturated
98.7 98.00 98.4 97.7
Calculated Total Sample Properties
GPA2145-16 Calculated at Contract Conditions
Relative Density Real Relative Density Ideal
1.5042 1.4956
Molecular Weight
43.3157
C6 - 60.000%
C6+ Group Properties
Assumed Composition
C7 - 30.000%
C8 - 10.000%
Field H2S
92000 PPM
PROTREND STATUS: DATA SOURCE:
Passed By Validator on Nov 21, 2021 Imported
PASSED BY VALIDATOR REASON:
Close enough to be considered reasonable.
VALIDATOR:
Dustin Armstrong
VALIDATOR COMMENTS:
OK
Nov 22, 2021 7:57 a
Powered By ProTrend -www.criticalcontrol.com
Page 1 of 1
-------
APPENDIX D - MONITORING AREA MAPS
APPENDIX D-l: MMA MAP
APPENDIX D-2: AMA MAP
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
1560
-------
A-1143
A-1866
A-572
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
A-545
A-1314
A-549
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
+ Rattlesnake AGI No. 1 SHL
1 Active Monitoring Area Boundary
1 9-Year Plume
J Plume Boundary at End of Injection
1560
-------
APPENDIX E - FACILITY SAFETY PLOT PLANS
-------
PLANT NORTH
LEGEND
•
FIRE EXTINGUISHER
~
SCBA/ESCAPE PACK
~
WIND SOCK
®
LEL/H2S MONITOR
ESD BUTTON
H
STROBE LIGHTS
HORN
E-1
r
i| 1 | |—1 l\ 71 1 k 1 A 1 \ W—1 / \ 1 1
—\
JKI 1 IMINAKY 1 ()l>
pn/ic\A/
0
NO.
05/11 / 22
DATE
INITIAL RELEASE K C V 1 C V V
REVISION DESCRIPTION
KLD
BY
BEC
FCE
JB
CLIENT
CHAR1S ENGINEERING. LLC
"IX ENG. FIRM NO. F-1B8B4
MIDLAND. IX
STAKEHOLDER
MIDSTREAM
CLIENT ;
PROJECT ;
TITLE :
STAKEHOLDER MIDSTREAM
30-30 GAS PLANT
SAFETY EQUIPMENT PLOT PLAN
1" = 50'—0"
DATE
5/11/22
ME—PLNP—AOOO—0004
A
-------
APPENDIX F - MMA/AMA REVIEW MAPS
APPENDIX F-l: PLUME BOUNDARY AT END OF INJECTION, STABILIZED PLUME BOUNDARY AND MAXIMUM
MONITORING AREA MAP
APPENDIX F-2: ACTIVE MONITORING AREA MAP
APPENDIX F-3: OIL AND GAS WELLS WITHIN THE MMA MAP
APPENDIX F-4: OIL AND GAS WELLS WITHIN THE MMA LIST
APPENDIX F-5: INJECTION INTERVAL PENETRATING WELLS WITHIN THE MMA MAP
APPENDIX F-6: GROUNDWATER WELLS WITHIN THE MMA
APPENDIX F-7: WELLBORE SCHEMATICS FOR INJECTION INTERVAL PENETRATING WELLS
-------
A-1143
A-545
A-1866
A-572
A-£ 58
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
A-1314
A-549
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
J Plume Boundary at End of Injection
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-2
Rattlesnake AGI No. 1 SHL
1 Active Monitoring Area Boundary
1 9-Year Plume
J Plume Boundary at End of Injection
Abstract
Note: All coordinates shown are in NAD83 (DD).
MAP EXTENT
~
-------
A-1866
A-1314
iiiiiiiiij
36998 l\
RATTLESNAKE AGI NO
33.0513499,1
-102.90450576
00000
32541
00261
32531
00000
iiiiiiiiii
00000"
00000
00262
000
\ 00645 •
00050
00643s
00644
00000
33349.
33530
00057
33173
32702
34984\
32065
00059
33172
33531
A-1484
33531'
32703
33351
32064
,00061
00000
00060
00058
32704
33 no 3
00065
00068
00064
^067 ^
32945
32975
32077
32075
: 30600
32076
36156
00267
00266
00066 3271 i
00063
02992
02991
02990
02989 35820
A-1816
34878
32070
36155
36151 30604 35791 30602
30606
JO fyy
36152
35821
30630
32072
36153
30601
30605
35794
35793 30598
36150
30603
36048
36154
35180
35703
35701
35705
30000
=3058.4;
32270
33065
1:34099;
00755
30583
30629
35961'
34797
56428 00000
• °l
36098
-34023 •
00768J
34124
30580
36327
33843
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
+ Rattlesnake AC I No. 1 SHL
| ~ ~ ™ 1/2-Mile Buffer from Max. Plume Extent (MMA)
I ~ Z Z Z Combined Maximum Plume Extent
1 Stabilized Plume
I ~ ~ ~ Z Plume Boundary at End of Injection
Abstract
Lateral (21)
API (42-501-...) SHL Status - Type (Count)
O Horizontal Surface Location (21)
• Active - Oil (93)
Active - Injection/Disposal (21)
•» Active - Injection/Disposal from Oil (22)
X Plugged - Oil (69)
^ Plugged - Gas (1)
Plugged- Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal (3)
TA - Injection/Disposal from Oil (7)
"0" Dry Hole (6)
o Permitted Location (2)
0 Canceled/Abandoned Location (6)
X Expired Permit (7)
API (42-501-...) BHL Status - Type (Count)
• Active - Oil (11)
•A Active - Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal from Oil (1)
o Permitted Location (4)
X Expired Permit (3)
Sou rce:
1.) Oil/Cas Well SHL Data: DI-2022
2.) Oil/Cas Well BHL Data: DI-2022
3.) Oil/Cas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD). *
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
1
A-1531
A-1064
A-87
A-1483
A-1641
A-499
VI55 !
i .-1777
A
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
F-4
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101829
DENVER UNIT
2215W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5300
5300
2215W
4250101835
DENVER UNIT
2207
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5185
5185
2207
4250130914
DENVER UNIT
2222
OCCIDENTAL PERMIAN LTD.
Active - Oil
2222
4250101832
DENVER UNIT
2201W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5190
5190
2201W
4250101826
DENVER UNIT
2203
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2203
4250101319
ROBERTS UNIT
4532W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5200
5200
4532W
4250130629
ROBERTS UNIT
4535
APACHE CORPORATION
Active - Oil
5280
5280
4535
4250130583
ROBERTS UNIT
4525
APACHE CORPORATION
Active - Oil
5286
5286
4525
4250101318
ROBERTS UNIT
4541
APACHE CORPORATION
TA - Injection/Disposal from Oil
5240
5240
4541
4250101889
ROBERTS UNIT
3614
APACHE CORPORATION
Plugged - Oil
5180
5180
3614
4250130598
Roberts Unit
3647
APACHE CORPORATION
Plugged - Oil
5281
5281
3647
4250130603
ROBERTS UNIT
3626
APACHE CORPORATION
Plugged - Oil
5289
5289
3626
4250102992
ROBERTS UNIT
3612W
APACHE CORPORATION
Plugged - Oil
5226
5226
3612W
4250100066
ROBERTS UNIT
3532
APACHE CORPORATION
Plugged - Oil
5231
5231
3532
4250101886
ROBERTS UNIT
3631
APACHE CORPORATION
Plugged - Oil
3631
4250101885
ROBERTS UNIT
3641
APACHE CORPORATION
Plugged - Oil
5212
5212
3641
4250100068
ROBERTS UNIT
3521
APACHE CORPORATION
Plugged - Oil
5225
5225
3521
4250100064
ROBERTS UNIT
3541
APACHE CORPORATION
Plugged - Oil
5264
5264
3541
4250102014
ROBERTS UNIT
2443
APACHE CORPORATION
Plugged - Oil
5226
5226
2443
4250100050
ROBERTS UNIT
1654
APACHE CORPORATION
Plugged - Oil
5198
5198
1654
4250133531
ROBERTS UNIT
2443A
Active - Injection/Disposal
5325
5325
2443A
4250133502
ROBERTS UNIT
2527A
Plugged - Oil
5308
5308
2527A
4250100000
C. A. ELLIOTT
6
AMERICAN LIBERTY OIL CO
Plugged - Oil
5229
5229
6
4250100000
C. A. ELLIOTT
7
AMERICAN LIBERTY AND ATLANTIC
Active - Oil
5182
5182
7
4250100000
GEO CLEVELAND
1
DELFERN OIL CO
Dry Hole
5071
5071
1
4250100000
JAMES H. LYNN
1614
AMERICAN LIBERTY
Active - Oil
5169
5169
1614
4250100000
J. H. LYNN
1634
AMERICAN LIBERTY
Active - Oil
5160
5160
1634
4250100000
A. T. MORRIS
1
ATLANTIC
Active - Oil
5235
5235
1
4250100000
A. T. MORRIS
2
AMERICAN LIBERTY OIL CO
Plugged - Oil
5179
5179
2
4250100000
W.J. CARPENTER
1642
AMERICAN LIBERTY OIL COMPANY
Plugged - Oil
5183
5183
1642
4250100000
E.S.SMITH
1
CREAT WESTERN FROD
Dry Hole
5216
5216
1
4250130607
ROBERTS UNIT
3546
Active - Oil
3546
4250135958
DENVER UNIT
2247
OCCIDENTAL PERMIAN LTD.
Active - Oil
2333
2333
2247
4250131542
DENVER UNIT
2229
SHELL OIL COMPANY
Dry Hole
2409
2409
2229
4250101320
ROBERTS UNIT
4543
APACHE CORPORATION
Active - Injection/Disposal from Oil
5120
5120
4543
4250137301
MILLER
8H
AMTEX ENERGY, INC.
Active - Oil
5157
5157
8H
4250137304
MILLER 732 C
10H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
10H
4250137305
MILLER 732 D
11H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
11H
4250101888
ROBERTS UNIT
3634W
APACHE CORPORATION
Plugged - Oil
5160
5160
3634W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101031
ROBERTS UNIT
3534W
APACHE CORPORATION
Plugged - Oil
5164
5164
3534W
4250101828
DENVER UNIT
2208
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5170
5170
2208
4250101032
ROBERTS UNIT
3544
APACHE CORPORATION
Plugged - Oil
5170
5170
3544
4250101841
DENVER UNIT
2206
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5177
5177
2206
4250101842
ROBERTS UNIT
3643W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3643W
4250101035
ROBERTS UNIT
3533W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3533W
4250132704
ROBERTS UNIT
2615
APACHE CORPORATION
Active - Oil
5180
5180
2615
4250100261
ROBERTS UNIT
1643W
APACHE CORPORATION
Plugged - Oil
5180
5180
1643W
4250101323
ROBERTS UNIT
4542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
4542W
4250102989
ROBERTS UNIT
3642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
3642W
4250102991
ROBERTS UNIT
3622W
APACHE CORPORATION
Plugged - Oil
5185
5185
3622W
4250132417
MILLER
3
AMTEX ENERGY, INC.
Active - Oil
5186
5186
3
4250101025
ROBERTS UNIT
2613W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5188
5188
2613W
4250101887
ROBERTS UNIT
3644
APACHE CORPORATION
Active - Injection/Disposal from Oil
5189
5189
3644
4250101830
DENVER UNIT
2214WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5190
5190
2214WC
4250101103
ROBERTS UNIT
3621
APACHE CORPORATION
Plugged - Oil
5190
5190
3621
4250101024
ROBERTS UNIT
2623
APACHE CORPORATION
Plugged - Oil
5190
5190
2623
4250101023
ROBERTS UNIT
2622W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5190
5190
2622W
4250101022
ROBERTS UNIT
2632
APACHE CORPORATION
Active - Oil
5190
5190
2632
4250101019
ROBERTS UNIT
2621
APACHE CORPORATION
Active - Oil
5190
5190
2621
4250101030
ROBERTS UNIT
3524W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5193
5193
3524W
4250101829
DENVER UNIT
2205
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5195
5195
2205
4250101836
DENVER UNIT
2213WC
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5200
5200
2213WC
4250101833
DENVER UNIT
2202WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5200
5200
2202WC
4250134099
DENVER UNIT
2239WC
OCCIDENTAL PERMIAN LTD.
Dry Hole
5200
5200
2239WC
4250132717
ROBERTS UNIT
3531A
APACHE CORPORATION
TA - Injection/Disposal
5200
5200
3531A
4250101014
ROBERTS UNIT
2624W
APACHE CORPORATION
Plugged - Oil
5200
5200
2624W
4250101028
ROBERTS UNIT
3523
APACHE CORPORATION
Plugged - Oil
5205
5205
3523
4250101102
ROBERTS UNIT
3611
APACHE CORPORATION
Plugged - Oil
5206
5206
3611
4250101827
DENVER UNIT
2209W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5210
5210
2209W
4250101015
2643
TEXACO INCORPORATED
Active - Injection/Disposal from Oil
5210
5210
2643
4250100266
ROBERTS UNIT
3522W
APACHE CORPORATION
Plugged - Oil
5211
5211
3522W
4250132632
MILLER
5
AMTEX ENERGY, INC.
Active - Oil
5213
5213
5
4250100057
ROBERTS UNIT
2512W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5213
5213
2512W
4250101890
ROBERTS UNIT
3624W
APACHE CORPORATION
Plugged - Oil
5214
5214
3624W
4250101033
ROBERTS UNIT
3543W
APACHE CORPORATION
Plugged - Oil
5215
5215
3543W
4250101012
ROBERTS UNIT
2634W
APACHE CORPORATION
Plugged- Injection/Disposal from Oil
5215
5215
2634W
4250101734
ROBERTS UNIT
2442
APACHE CORPORATION
Plugged - Oil
5215
5215
2442
4250101020
ROBERTS UNIT
2611W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5215
5215
2611W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100067
ROBERTS UNIT
3531
APACHE CORPORATION
Plugged - Oil
5216
5216
3531
4250101013
ROBERTS UNIT
2614W
APACHE CORPORATION
Plugged - Oil
5216
5216
2614W
4250101844
ROBERTS UNIT
3623W
APACHE CORPORATION
Plugged - Oil
5217
5217
3623W
4250131869
ROBERTS UNIT
A3534W
APACHE CORPORATION
Plugged - Oil
5220
5220
A3534W
4250102990
ROBERTS UNIT
3632W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5220
5220
3632W
4250100262
ROBERTS UNIT
1644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5220
5220
1644W
4250132858
DENVER UNIT
2235
OCCIDENTAL PERMIAN LTD.
Shut-In - Oil
5225
5225
2235
4250100058
ROBERTS UNIT
2544W
APACHE CORPORATION
Plugged - Oil
5225
5225
2544W
4250130584
ROBERTS UNIT
4520
APACHE CORPORATION
Active - Oil
5230
5230
4520
4250130630
ROBERTS UNIT
3535
APACHE CORPORATION
Active - Oil
5230
5230
3535
4250100063
ROBERTS UNIT
3542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5230
5230
3542W
4250132076
ROBERTS UNIT
3627
APACHE CORPORATION
Active - Oil
5230
5230
3627
4250100267
ROBERTS UNIT
3512W
APACHE CORPORATION
Plugged - Oil
5233
5233
3512W
4250101016
ROBERTS UNIT
2642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5234
5234
2642W
4250134716
DENVER UNIT
2242
OCCIDENTAL PERMIAN LTD.
Active - Oil
5236
5236
2242
4250100061
ROBERTS UNIT
2524W
APACHE CORPORATION
Plugged - Oil
5238
5238
2524W
4250101021
ROBERTS UNIT
2633
APACHE CORPORATION
Plugged - Oil
5240
5240
2633
4250101011
ROBERTS UNIT
2644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5241
5241
2644W
4250132541
FUTCH
1
AMTEX ENERGY, INC.
Active - Oil
5244
5244
1
4250101026
ROBERTS UNIT
2612W
APACHE CORPORATION
Plugged - Oil
5245
5245
2612W
4250100059
ROBERTS UNIT
2513W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5246
5246
2513W
4250132531
MILLER
4
AMTEX ENERGY, INC.
Plugged - Oil
5248
5248
4
4250132687
ROBERTS UNIT
2635
APACHE CORPORATION
Plugged - Oil
5248
5248
2635
4250131656
DENVER UNIT
2232WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2232WC
4250131791
DENVER UNIT
2231
SHELL OIL COMPANY
Canceled/Abandoned Location
5250
5250
2231
4250134118
DENVER UNIT
2238
OCCIDENTAL PERMIAN LTD.
Active - Oil
5250
5250
2238
4250101342
ROBERTS UNIT
APACHE CORPORATION
Plugged - Gas
5250
5250
4250132269
ROBERTS UNIT
3601
APACHE CORPORATION
Plugged - Oil
5250
5250
3601
4250101843
ROBERTS UNIT
3633W
APACHE CORPORATION
Plugged - Oil
5250
5250
3633W
4250130608
ROBERTS UNIT
3545
APACHE CORPORATION
Active - Oil
5250
5250
3545
4250132077
ROBERTS UNIT
3617
APACHE CORPORATION
Active - Oil
5250
5250
3617
4250134963
DENVER UNIT
2244WC
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal
5251
5251
2244WC
4250100060
ROBERTS UNIT
2514
APACHE CORPORATION
Plugged - Oil
5251
5251
2514
4250101459
DENVER UNIT
2211
OCCIDENTAL PERMIAN LTD.
Active - Oil
5252
5252
2211
4250132521
DENVER UNIT
2233W
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal from Oil
5253
5253
2233W
4250135211
DENVER UNIT
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5253
5253
2241
4250101837
DENVER UNIT
2212W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5255
5255
2212W
4250132793
MILLER
6
AMTEX ENERGY, INC.
Active - Oil
5258
5258
6
4250132356
MILLER
1
AMTEX ENERGY, INC.
Active - Oil
5260
5260
1
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101017
ROBERTS UNIT
2641
APACHE CORPORATION
Active - Oil
5260
5260
2641
4250101825
DENVER UNIT
2204W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5264
5264
2204W
4250132416
MILLER
2
AMTEX ENERGY, INC.
Active - Oil
5269
5269
2
4250100065
ROBERTS UNIT
3511W
APACHE CORPORATION
Plugged - Oil
5270
5270
3511W
4250101018
ROBERTS UNIT
2631
APACHE CORPORATION
Active - Oil
5270
5270
2631
4250130600
ROBERTS UNIT
3645
APACHE CORPORATION
Active - Oil
5273
5273
3645
4250130580
ROBERTS UNIT
4536
APACHE CORPORATION
Active - Oil
5279
5279
4536
4250130599
ROBERTS UNIT
3646
APACHE CORPORATION
Active - Oil
5279
5279
3646
4250130602
ROBERTS UNIT
3635
APACHE CORPORATION
Active - Oil
5283
5283
3635
4250132997
DENVER UNIT
2208WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5284
5284
2208WC
4250130601
ROBERTS UNIT
3636
APACHE CORPORATION
Active - Oil
5286
5286
3636
4250132174
SHEPHERD
1
YOUNG, MARSHALL R., OIL CO.
Dry Hole
5286
5286
1
4250130604
ROBERTS UNIT
3625
APACHE CORPORATION
Active - Oil
5287
5287
3625
4250130912
DENVER UNIT
2224
OCCIDENTAL PERMIAN LTD.
Active - Oil
5288
5288
2224
4250130911
DENVER UNIT
2225
OCCIDENTAL PERMIAN LTD.
Active - Oil
5290
5290
2225
4250130609
ROBERTS UNIT
4530
APACHE CORPORATION
Active - Oil
5291
5291
4530
4250130605
ROBERTS UNIT
3616
APACHE CORPORATION
Plugged - Oil
5291
5291
3616
4250130606
ROBERTS UNIT
3615
APACHE CORPORATION
Active - Oil
5293
5293
3615
4250133172
ROBERTS UNIT
2523
CONOCOPHILLIPS COMPANY
Plugged - Oil
5295
5295
2523
4250132739
CLEVELAND
1
HIGHLAND PRODUCTION COMPANY
Plugged - Oil
5300
5300
1
4250133064
DENVER UNIT
2238
SHELL WESTERN E&P INC.
Canceled/Abandoned Location
5300
5300
2238
4250132927
DENVER UNIT
2236
OCCIDENTAL PERMIAN LTD.
Active - Oil
5300
5300
2236
4250133065
DENVER UNIT
2237
SHELL WESTERN E&P INC.
Expired Permit
5300
5300
2237
4250132270
ROBERTS UNIT
4540
APACHE CORPORATION
Active - Oil
5300
5300
4540
4250132414
ROBERTS UNIT
3523A
APACHE CORPORATION
Active - Injection/Disposal
5300
5300
3523A
4250132712
ROBERTS UNIT
3537
APACHE CORPORATION
Plugged - Oil
5300
5300
3537
4250132722
ROBERTS UNIT
3547
APACHE CORPORATION
Active - Oil
5300
5300
3547
4250132945
ROBERTS UNIT
3541A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3541A
4250132975
ROBERTS UNIT
3641A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3641A
4250132711
ROBERTS UNIT
3620
APACHE CORPORATION
Active - Oil
5300
5300
3620
4250133527
ROBERTS UNIT
2518
APACHE CORPORATION
Active - Oil
5300
5300
2518
4250132714
ROBERTS UNIT
2637
APACHE CORPORATION
Plugged - Oil
5300
5300
2637
4250133351
ROBERTS UNIT
2526
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2526
4250132703
ROBERTS UNIT
2516
APACHE CORPORATION
Plugged - Oil
5300
5300
2516
4250133348
ROBERTS UNIT
2533
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2533
4250132702
ROBERTS UNIT
2515
APACHE CORPORATION
Active - Oil
5300
5300
2515
4250133350
ROBERTS UNIT
2525
APACHE CORPORATION
Active - Oil
5300
5300
2525
4250133498
ROBERTS UNIT
2532
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2532
4250133173
ROBERTS UNIT
2522
APACHE CORPORATION
Active - Oil
5300
5300
2522
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250133499
ROBERTS UNIT
2527
TEXACO PRODUCING INC.
Dry Hole
5300
5300
2527
4250133530
ROBERTS UNIT
2507
APACHE CORPORATION
Active - Oil
5300
5300
2507
4250132685
ROBERTS UNIT
2638
APACHE CORPORATION
Plugged - Oil
5302
5302
2638
4250133349
ROBERTS UNIT
2517
APACHE CORPORATION
Active - Oil
5302
5302
2517
4250132718
ROBERTS UNIT
3532A
APACHE CORPORATION
Active - Injection/Disposal
5304
5304
3532A
4250132713
ROBERTS UNIT
2625
APACHE CORPORATION
Active - Oil
5308
5308
2625
4250133502
ROBERTS UNIT
2527A
APACHE CORPORATION
Plugged - Oil
5308
5308
2527A
4250132716
ROBERTS UNIT
3526
APACHE CORPORATION
Active - Oil
5309
5309
3526
4250100645
ROBERTS UNIT
1624W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5309
5309
1624W
4250130913
DENVER UNIT
2223
OCCIDENTAL PERMIAN LTD.
Active - Oil
5310
5310
2223
4250132686
ROBERTS UNIT
2636
APACHE CORPORATION
Active - Oil
5310
5310
2636
4250101457
DENVER UNIT
2210
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5325
5325
2210
4250133529
ROBERTS UNIT
2508
APACHE CORPORATION
Plugged - Oil
5325
5325
2508
4250133531
ROBERTS UNIT
2443A
APACHE CORPORATION
Active - Injection/Disposal
5325
5325
2443A
4250133528
ROBERTS UNIT
2511
APACHE CORPORATION
Active - Oil
5325
5325
2511
4250135912
ROBERTS UNIT
3771W
APACHE CORPORATION
Active - Injection/Disposal
5330
5330
3771W
4250132075
ROBERTS UNIT
3637
APACHE CORPORATION
Active - Oil
5330
5330
3637
4250132063
ROBERTS UNIT
2705
APACHE CORPORATION
Active - Oil
5330
5330
2705
4250135793
ROBERTS UNIT
3672
APACHE CORPORATION
Active - Oil
5334
5334
3672
4250135819
ROBERTS UNIT
3674W
APACHE CORPORATION
Active - Injection/Disposal
5336
5336
3674W
4250135792
ROBERTS UNIT
3671
APACHE CORPORATION
Active - Oil
5339
5339
3671
4250135820
ROBERTS UNIT
3675W
APACHE CORPORATION
Active - Injection/Disposal
5341
5341
3675W
4250135818
ROBERTS UNIT
3633RW
APACHE CORPORATION
Active - Injection/Disposal
5344
5344
3633RW
4250135790
ROBERTS UNIT
3647R
APACHE CORPORATION
Active - Oil
5345
5345
3647R
4250100768
CORNELL UNIT
3107W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5350
5350
3107W
4250130915
DENVER UNIT
2221
OCCIDENTAL PERMIAN LTD.
Active - Oil
5350
5350
2221
4250136048
ROBERTS UNIT
3634RW
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3634RW
4250135908
ROBERTS UNIT
3678W
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3678W
4250132072
ROBERTS UNIT
3525
APACHE CORPORATION
Active - Oil
5350
5350
3525
4250135915
ROBERTS UNIT
3626R
APACHE CORPORATION
Active - Oil
5350
5350
3626R
4250132281
ROBERTS UNIT
2446
APACHE CORPORATION
Active - Oil
5350
5350
2446
4250132064
ROBERTS UNIT
2704
APACHE CORPORATION
Active - Oil
5350
5350
2704
4250132280
ROBERTS UNIT
2445
APACHE CORPORATION
Plugged - Oil
5350
5350
2445
4250135791
ROBERTS UNIT
3670
APACHE CORPORATION
Active - Oil
5351
5351
3670
4250135794
ROBERTS UNIT
3673
APACHE CORPORATION
Active - Oil
5352
5352
3673
4250135821
ROBERTS UNIT
3676W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3676W
4250135914
ROBERTS UNIT
3681W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3681W
4250100643
ROBERTS UNIT
1634W
APACHE CORPORATION
Plugged - Oil
5353
5353
1634W
4250135796
ROBERTS UNIT
3669
APACHE CORPORATION
Active - Oil
5356
5356
3669
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100644
ROBERTS UNIT
1614
APACHE CORPORATION
Plugged - Oil
5356
5356
1614
4250135913
ROBERTS UNIT
3680W
APACHE CORPORATION
Active - Injection/Disposal
5357
5357
3680W
4250135705
ROBERTS UNIT
3752
APACHE CORPORATION
Active - Oil
5360
5360
3752
4250135822
ROBERTS UNIT
3677W
APACHE CORPORATION
Active - Injection/Disposal
5362
5362
3677W
4250134984
ROBERTS UNIT
2626W
APACHE CORPORATION
Active - Injection/Disposal
5364
5364
2626W
4250135701
ROBERTS UNIT
3667
APACHE CORPORATION
Active - Oil
5365
5365
3667
4250132070
ROBERTS UNIT
3536
APACHE CORPORATION
Active - Oil
5370
5370
3536
4250132065
ROBERTS UNIT
2703
APACHE CORPORATION
Active - Oil
5370
5370
2703
4250100755
CORNELL UNIT
3101W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5373
5373
3101W
4250135703
ROBERTS UNIT
3668
APACHE CORPORATION
Active - Oil
5380
5380
3668
4250135229
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5388
5388
2240
4250136152
ROBERTS UNIT
3682W
APACHE CORPORATION
Active - Injection/Disposal
5397
5397
3682W
4250131539
DENVER UNIT
2230
SHELL OIL COMPANY
Canceled/Abandoned Location
5400
5400
2230
4250136327
ROBERTS UNIT
4547
APACHE CORPORATION
Active - Oil
5400
5400
4547
4250136154
ROBERTS UNIT
3624RW
APACHE CORPORATION
Active - Injection/Disposal
5400
5400
3624RW
4250136155
ROBERTS UNIT
3683W
APACHE CORPORATION
Active - Injection/Disposal
5402
5402
3683W
4250136156
ROBERTS UNIT
3686
APACHE CORPORATION
Active - Oil
5404
5404
3686
4250134797
CORNELL UNIT
3194
XTO ENERGY INC.
Active - Oil
5405
5405
3194
4250135696
CORNELL UNIT
113
XTO ENERGY INC.
Active - Oil
5406
5406
113
4250136150
ROBERTS UNIT
3684
APACHE CORPORATION
Active - Oil
5421
5421
3684
4250133629
CORNELL UNIT
3156
XTO ENERGY INC.
Active - Oil
5425
5425
3156
4250135961
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Active - Oil
5425
5425
2246
4250135960
DENVER UNIT
2249
OCCIDENTAL PERMIAN LTD.
Active - Oil
5431
5431
2249
4250136153
ROBERTS UNIT
3623RW
APACHE CORPORATION
Active - Injection/Disposal
5439
5439
3623RW
4250135353
CORNELL UNIT
107
XTO ENERGY INC.
Active - Oil
5450
5450
107
4250135528
ROBERTS UNIT
3549
APACHE CORPORATION
Active - Oil
5452
5452
3549
4250136151
ROBERTS UNIT
3685
APACHE CORPORATION
Active - Oil
5463
5463
3685
4250135963
DENVER UNIT
2252
OCCIDENTAL PERMIAN LTD.
Active - Oil
5476
5476
2252
4250136434
ROBERTS UNIT
263H
APACHE CORPORATION
Expired Permit
5500
5500
263H
4250136433
ROBERTS UNIT
262H
APACHE CORPORATION
Expired Permit
5500
5500
262H
4250136098
CORNELL UNIT
110
XTO ENERGY INC.
Active - Injection/Disposal
5510
5510
110
4250133615
ROBERTS UNIT
2442A
APACHE CORPORATION
TA - Injection/Disposal
5516
5516
2442A
4250135180
ROBERTS UNIT
3534B
APACHE CORPORATION
Active - Injection/Disposal
5517
5517
3534B
4250136428
CORNELL UNIT
124
XTO ENERGY INC.
Active - Oil
5532
5532
124
4250134878
ROBERTS UNIT
3548
APACHE CORPORATION
Active - Oil
5550
5550
3548
4250135966
DENVER UNIT
2251
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2251
4250135962
DENVER UNIT
2250
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2250
4250135356
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Expired Permit
5600
5600
2246
4250135959
DENVER UNIT
2248
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2248
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250135210
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250135211
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2241
4250134710
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250101845
ROBERTS UNIT
3613
APACHE CORPORATION
Active - Oil
7000
7000
3613
4250110083
RANDALL, E.
36
EXXON CORP.
Plugged - Oil
8595
8595
36
4250110046
ELLIOTT, C.A.
2
MCCLURE OIL COMPANY, INC.
Plugged - Oil
9000
9000
2
4250136692
MISS KITTY 704-669
3XH
RILEY EXPLORATION OPG CO, LLC
Expired Permit
9000
9000
3XH
4250133793
RANDALL, E.
39
XTO ENERGY INC.
Active - Oil
9000
9000
39
4250137375
RIP WHEELER 705-668
5XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
5XH
4250137358
RIP WHEELER 705-668
1XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
1XH
4250133843
ELLIOTT
1
DELTA C02, LLC
Plugged - Oil
9050
9050
1
4250134124
RANDALL, E
46
EXXON CORP.
Canceled/Abandoned Location
9100
9100
46
4250133792
RANDALL, E.
40
XTO ENERGY INC.
Plugged - Oil
9591
9591
40
4250110079
RANDALL, E.
32
EXXON CORP.
Plugged - Oil
9615
9615
32
4250135418
RANDALL, E.
46
XTO ENERGY INC.
Active - Oil
9650
9650
46
4250134023
RANDALL, E.
42
XTO ENERGY INC.
Active - Oil
9660
9660
42
4250134016
RANDALL, E.
43
XTO ENERGY INC.
Active - Oil
9740
9740
43
4250132388
RANDALL, E.
38
EXXON CORP.
Canceled/Abandoned Location
10300
10300
38
4250137302
MILLER 732 B
9H
AMTEX ENERGY, INC.
Active - Oil
5183
10662
9H
4250136432
ROBERTS UNIT
261 H
APACHE CORPORATION
Active - Oil
5151
11117
261 H
4250136998
RATTLESNAKE AGI
1
SANTA FE MIDSTREAM PERMIAN LLC
Active - Injection/Disposal
11980
11980
1
4250137252
MILLER SWD
7
AMTEX ENERGY, INC.
Permitted Location
13000
13000
7
4250136984
MADCAP 731-706
1XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5261
13274
1XH
4250137127
MISS KITTY A 669-704
25XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5321
13428
25XH
4250137287
MISS KITTY A 669-704
4XH
RILEY PERMIAN OPERATING CO, LLC
Shut-In - Oil
5340
13452
4XH
4250137236
MISS KITTY 669-704
2XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5317
13622
2XH
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well Penetrators
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
1
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-5
+ Rattlesnake AGI No. 1 SHL
I '
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
API (42-501-...) SHL Status - Type (Count)
• Active - Oil (4)
Active - Injection/Disposal (1)
Plugged - Oil (4)
® Permitted Location (1)
Sou rce:
1.) Oil/Gas Well SHL Data: DI-2022
2.) Oil/Gas Well BHL Data: DI-2022
3.) Oil/Gas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD).
1560
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Groundwater Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
F-6
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
+ Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
SDRDB Groundwater Wells [TWDB-2022]
Proposed Use (Labeled with Well Report No.)
A Industrial (1)
Irrigation (5)
TWDB Groundwater Wells [TWDB-2022]
Well Type (Labeled with State Well No.)
¦ Withdrawal of Water (1)
Sou rce:
1.) SDRDB Groundwater Well SHL Data: TWDB-2022
2.) TWDB Groundwater Well SHL Data: TWDB-2022
3.) Brackish Groundwater Well SHL Data: TWDB-2022
* Note: All coordinates shown are in NAD83 (DD). *
1560
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Cement Plug #9
@7'-1,013'
Cement Plug #8
@ 1,730'- 1,800'
Cement Plug #7
@ 2,031' - 2,100
Cement Plug #6
@2,430'-2,500'
Cement Plug #5
@2,660'-2,719'
Cement Plug #4
@2,790'-2,860'
Cement Plug #3
@3,172'-3,239'
Cement Plug #2
@3,765'-3,831'
Cement Plug #1
@ 3,900'-3,960'
Perfs @ 8,231
8,396', 8,420'
8,447', 8,462'
Casing Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
4-1/2"
Depth Set
2,134'
9,601'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-10079
RRC District No: 8-A
Drawn: KAS
E. Randall No. 32
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18231
Date: 05/31/2022
Approved: SLP
-------
Cement Plug #5
@ 0' - 458'
Cement Plug #4
@2,070'-2,295'
Cement Plug #3
@2,780'- 3,009'
Cement Plug #2
@4,450'-4,870'
Cement Plug #1
@5,184'-5,266'
Perfs@ 9,496'-9,516'
TD@ 9,591'
PBTD @ 9,560'
DV Tool ® 4,522'
DV Tool @ 5,676'
Casing Information
Label
1
3
Type
Surface
Production
OD
9-5/8"
5-1/2"
Weight
36 lb/ft
UNK
Depth Set
2,162'
9,569'
Hole Size
12-1/4"
7-7/8"
TOC
Surface
2,350'
Volume
880 sks
5,450 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-337932
RRC District No: 8-A
Drawn: KAS
E. Randall No. 40
State/Province: Texas
Spud Date: 12/04/1992
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
A
Perfs (5) 9,536' - 9,540'
SI
[S
: . I
DV Tool @ 5,968'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54 lb/ft
36 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,129'
5,606'
9,699'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
1,790 sks
2,910 sks
1,590 sks
2-3/8" Tubing & Packer Set @ 9,331'
TD @ 9,700'
PBTD @ 9,654'
MD
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-33885
RRC District No: 8-A
Drawn: KAS
E. Randall No. 41L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,533' - 9,553'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,167'
5,830'
9,658'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
440'
1,800'
Volume
1,530 sks
3,500 sks
1,050 sks
DV Tool ® 7,414'
2-3/8" Tubing & Packer Set @ 8,970'
TD @ 9,660' \-(3)
PBTD @ 9,623' W
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34023
RRC District No: 8-A
Drawn: KAS
E. Randall No. 42L
State/Province: Texas
Spud Date: 07/01/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Li;.
Perfs @ 9,550' - 9,538'
9,603'-9,610'
sf.
.... «¦
*'¦ •-
4/?
¦A ¦
" B ¦'
" ¦ /
?
, 4' i
,
"4
t" '
'*¦ ?r
. v.
> .¦
"A
' 'i
;
¦ 'v
„ .: '
4* •"
/
CIBP ® 8,917'
CIBP @ 9,590'
TD @ 9,740'
PBTD @ 8,917'
rv@
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,166'
5,902'
9,735'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
2,000'
Volume
1,530 sks
3,505 sks
967 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-34016
RRC District No: 8-A
Drawn: KAS
E. Randall No. 43L
State/Province: Texas
Spud Date: 04/08/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs @ 8,762' - 8,782'
(Sqz w/100 sx)
Perfs @8,822'-8,831'
(Sqz w/ 75 sx)
Perfs @ 9,562' - 9,570'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
29 lb/ft
Depth Set
2,158'
5,904'
9,620'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,600'
Volume
1,450 sks
5,190 sks
1,100 sks
DV Tool ® 7,482'
2-3/8" Tubing & Packer Set @ 9,552'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34024
RRC District No: 8-A
Drawn: KAS
E. Randall No. 44
State/Province: Texas
Spud Date: 08/09/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,565' - 9,575'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,175'
5,898'
9,615'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,500'
Volume
1,530 sks
3,525 sks
1,170 sks
DV Tool ® 7,508'
2-3/8" Tubing Set @ 9,580'
Packer Set (5) 9,394'
TD @ 9,684'
PBTD @ 9,593'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34017
RRC District No: 8-A
Drawn: KAS
E. Randall No. 45L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
Perfs (5) 9,504' - 9,512'
TD @ 9,650'
PBTD @ 9,594'
Casing/Tubing
Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
5-1/2"
Weight
24 lb/ft
17 lb/ft
Depth Set
2,120'
9,650'
Hole Size
11"
7-7/8"
TOC
Surface
Surface
Volume
900 sks
3,400 sks
DV Tool ® 8,656' & 8,674'
2-7/8" Tubing & Packer Set @ 9,184'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy, Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-35418
RRC District No: 8-A
Drawn: KAS
E. Randall No. 46
State/Province: Texas
Spud Date: 05/23/2007
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
u
Cement Plug #4
@48'-60'
Cement Plug #3
@ 270' - 450'
Cement Plug #1
@7,549'-8,000'
Perfs @ 8,292' - 8,428'
Cement Plug #2
@3,273'-3,439'
Top of Cut @ 750'
Top of Cut @ 1,439'
TD ® 9,645'
v@
Casing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
5-1/2"
Depth Set
300'
3,200'
9,610'
TOC
Surface
Surface
Surface
Volume
400 sks
300 sks
425 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Bonanza Oil Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-10046
RRC District No: 8-A
Drawn: KAS
C.A. Elliott No. 2
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18875
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
w
if.
II
: .
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
48 lb/ft
40 lb/ft
26 lb/ft
28 lb/ft
Depth Set
500'
5,500'
10,695'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
350 sks
1,705 sks
1,635 sks
3-1/2" Tubing & Packer Set @ 10,650'
MD
TD @ 13,000'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Amtex Energy, Inc.
Country: USA
Location: Section 732, Block D
API No: 42-501-37252
RRC District No: 7-C
Drawn: KAS
Miller SWD No. 7 (Permitted)
State/Province: Texas
Spud Date: 08/09/1995
Field: Wasson
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
Permit Number: 16637
Date: 05/31/2022
Approved: SLP
-------
Request for Additional Information: 30-30 Gas Plant
August 31, 2022
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references,
or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1
4
42
• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Natural or induced seismicity
• Drilling through the MMA
• Leakage through the confining layer
Is this bullet list intended to represent the upcoming subsections within
section 3 of the MRV plan? If so, EPA recommends that 30-30 revise so
that this list matches the sub-section headings. There are some slight
differences between the two.
List and Subsection headings synchronized (pg 42-51)
2
5
54
"This section discusses the strategy that Stakeholder will employ for
detecting and quantifying surface leakage of C02 through the
pathways..."
40 CFR 98.448(a)(3) requires that the MRV plan contain "A strategy for
detecting and quantifying any surface leakage of C02." While the above
sentence references quantification, the subsequent section does not
appear to identify quantification strategies for the identified leakage
pathways. In the MRV plan, please ensure that you have provided a
strategy for quantifying surface leakage of C02.
Added paragraph "Pressures and flowrates 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
at the time, including pressure, flow rate, size of the leak point
opening, and duration of the leak." (pg 55)
-------
No.
MRV
Section
Plan
Page
EPA Questions
Responses
3
6
57
"H2S will be initially injected into the AGI well at a concentration of
approximately ten (10) percent or 100,000 ppm. The concentration will
drop to approximately six (6) percent as additional volumes are added."
Page 33 states that, "...It is expected that a larger portion of the gas
added is carbon dioxide, changing the composition to "93% C02 and
~7% H2S."
These statements potentially conflict with each other. Please clarify.
Concentration of BBS corrected to "seven (7) percent" (pg 57)
54
List and Subsection headings synchronized (pg 54-56)
5
-------
STAKEHOLDER
I!MIDSTREAM
Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
Rattlesnake AGI #1
Yoakum County, Texas
Prepared for Stakeholder Gas Services, LLC
San Antonio, TX
By
Lonquist Sequestration, LLC
Austin, TX
Version 2
August 2022
LONQUIST
SEQUESTRATION LLC
Hi
-------
INTRODUCTION
Stakeholder Gas Services, LLC ("Stakeholder") currently has a Class II acid gas injection ("AGI") permit, issued
by the Texas Railroad Commission ("TRRC") in November 2018, for the Rattlesnake AGI #1 well, API No. 42-
501-36998. This permit was originally issued to Santa Fe Midstream Permian, LLC, in 2018 and the asset was
subsequently acquired by Stakeholder in December of 2020. This permit currently authorizes Stakeholder to
inject up to 4,500 barrels per day ("bbls/d") of treated acid gas ("TAG") into the Devonian formation at a
depth of 11,000' to 12,000' with a maximum allowable surface pressure of 2,200 psi. Since being permitted,
injection has proceeded without incident. This AGI well is associated with Stakeholder's 30-30 gas treating
and processing plant ("30-30") located in a rural, sparsely populated area of Yoakum County, Texas,
approximately seven miles northwest of the town of Plains, as shown in Figure 1.
I t
H-
Ula
homa
STAKEHOLDER
MIDSTREAM
Mexlip
TT
:
1
t
L
Y
I
H
iti
l^vas
J L
riV
r\ fV
WES
T OIL F
IELD
Yoakum
ink Bas.n
Rattlesnake
AGI(RS#1)
¦
WASSON OIL
FIELD
° *
9
"S
W
i
|
Four Mi
| 1
Ji|—k s ¦/- 1 i
§
YbAKUM
GAINrS
^ Gaines
0 0.5 1 2 Miles
GEOROi
ALLEN
OIL
FIELD
# Stakeholder AGI Well
Figure 1 - Location of Rattlesnake AGI #3 Well
1
-------
Stakeholder 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, Stakeholder is also applying to the TRRC for an amendment to the
Rattlesnake AGI #1 well's Class II permit to increase its authorized injection volume and maximum allowable
surface injection pressure ("MASIP"). Approval of the permit amendment will allow Stakeholder to increase
the capacity of its existing 30-30 Facility, which removes H2S and C02 from natural gas production using amine
treating, as well as increase the injection well capacity for a future gas processing facility which is currently
under development by Stakeholder. Additionally, expanded capacity allows Stakeholder to potentially
provide future disposal in its AGI well for oil and gas waste derived TAG from similar third-party gas processing
facilities. Increased disposal capacity will allow for greater gas processing capacity in the region, ultimately
helping to reduce flaring and its associated emissions. Throughout this document, both in written reference
and in modeling inputs, Stakeholder has used the applied-for expanded permit capacity of 16 million standard
cubic feet per day ("MMSCF/d"). Stakeholder plans to inject C02 for approximately 14 more years.
2
-------
ACRONYMS AND ABBREVIATIONS
%
°c
°F
AMA
BCF
CH4
CMG
C02
E
EOS
EPA
ESD
FG
ft
GAU
GEM
GHGs
GHGRP
H2S
md
mi
MIT
MM
MMA
MCF
MMCF
MMSCF
Feet
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)
Groundwater Advisory Unit
Computer Modelling Group's GEM 2020.11
Greenhouse Gases
Greenhouse Gas Reporting Program
Hydrogen Sulfide
Millidarcy(ies)
Mile(s)
Mechanical Integrity Test
Million
Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet
-------
MSCF/D Thousand 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
4
-------
TABLE OF CONTENTS
INTRODUCTION 1
ACRONYMS AND ABBREVIATIONS 3
SECTION 1 - FACILITY INFORMATION 8
Reporter number 8
Underground Injection Control (UIC) Class II Permit 8
UIC Well Identification Number 8
SECTION 2- PROJECT DESCRIPTION 9
Regional Geology 10
Regional Faulting 15
Site Characterization 15
Stratigraphy and Lithologic Characteristics 15
Upper Confining Interval - Woodford Shale 16
Injection Interval - Fasken Formation 17
Lower Confining Zone - Fusselman Formation 21
Local Structure 21
Injection and Confinement Summary 26
Groundwater Hydrology 26
Description of the Injection Process 31
Current Operations 31
Planned Operations 32
Reservoir Characterization Modeling 32
Simulation Modeling 35
SECTION 3 - DELI NATION OF MONITORING AREA 39
Maximum Monitoring Area 39
Active Monitoring Area 40
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE 42
Leakage from Surface Equipment 42
Leakage from Wells in the Monitoring Area 44
Oil and Gas Operations within Monitoring Area 44
Groundwater wells 48
Leakage Through Faults or Fractures 50
Leakage Through Confining Layers 51
Leakage from Natural or Induced Seismicity 51
SECTION 5 - MONITORING FOR LEAKAGE 54
Leakage from Surface Equipment 54
Leakage from Existing and Future Wells within Monitoring Area 55
Leakage through Faults, Fractures or Confining Seals 56
Leakage through Natural or Induced Seismicity 56
SECTION 6 - BASELINE DETERMINATIONS 57
Visual Inspections 57
H2S Detection 57
C02 Detection 57
Operational Data 57
Continuous Monitoring 57
Groundwater Monitoring 58
SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION 59
5
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Mass of C02 Received 59
Mass of C02 Injected 59
Mass of C02 Produced 61
Mass of C02 Emitted by Surface Leakage 61
Mass of C02 Sequestered 61
SECTION 8- IMPLEMENTATION SCHEDULE FOR MRV PLAN 63
SECTION 9 - QUALITY ASSURANCE 64
Monitoring QA/QC 64
Missing Data 64
MRV Plan Revisions 65
SECTION 10- RECORDS RETENTION 66
References 67
APPENDICES 68
LIST OF FIGURES
Figure 1 - Location of Rattlesnake AGI #1 well 1
Figure 2 - Illustrative overview of Rattlesnake AGI #1 and 30-30 Facility 9
Figure 3 - Regional Map of the Permian Basin 10
Figure 4 - Stratigraphic column of the Northwest Shelf 11
Figure 5 - Stratigraphic column depicting the composition of the Silurian group 12
Figure 6 - Thickness map of the Silurian system which composes the Fusselman and Wristen group 14
Figure 7 - Type Log (42-501-10238) with tops, confining and injection zones depicted 15
Figure 8 - Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994) 16
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays 18
Figure 10 - Rattlesnake AGI #1 open hole log (42-501-36998) 19
Figure 11 - Offset wells used for Formation Fluid Characterization 20
Figure 12 - Silurian Structure Map (subsea depths) 23
Figure 13 - Structural Northeast-Southwest Cross Section 24
Figure 14 - Structural Northwest-Southeast Cross Section 25
Figure 15 - Northwest-Southeast Cross Section of aquifers in the Rattlesnake AGI #1 well area 27
Figure 16 - Potentiometric surfaces from wells completed in A Ogallala aquifer, B the Edwards-Trinity aquifer
and Cthe Dockum aquifer 28
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDB) 29
Figure 18 -Total dissolved solids in groundwater from the Dockum Aquifer 29
Figure 19-Regional extent of the Edwards-Trinity freshwater aquifer 30
Figure 20 - Regional extent of the Ogallala freshwater aquifer 31
Figure 21 - 30-30 Facility Process Flow Diagram 32
Figure 22 - Permeability Distribution of Karst Limestone 34
Figure 23 - Areal View Gas Saturation Plume, 2036 (End of Injection) 37
Figure 24 - Areal View Gas Saturation Plume, 2779 (End of Density Drift) 38
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time 38
Figure 26 - Plume Boundary at End of Injection, Stabilized Plume, and Maximum Monitoring Area 40
Figure 27 - Active Monitoring Area 41
Figure 28 - Site Plan, 30-30 Facility 43
Figure 29 - Rattlesnake AGI #1 Wellbore Schematic 45
Figure 30 - Oil and Gas Wells within the MMA 46
6
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Figure 31 - Penetrating Oil and Gas Wells within the MMA 47
Figure 32 - Groundwater Wells within MMA 49
Figure 33 - Seismicity Review (TexNet - 06/01/2022) 52
Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI #1 location 53
LIST OF TABLES
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples 20
Table 2 - Fracture Gradient Assumptions 21
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and
Yoakum Counties, Texas 26
Table 4 - Gas Composition of 30-30 Facility outlet 31
Table 5 - Modeled Initial Gas Composition 33
Table 6 - CMG Model Layer Properties 34
Table 7 - All Offset SWDs included in the model 36
Table 8 - All Offset Producers included in the model 36
Table 9 - Groundwater Well Summary 50
Table 10 - Summary of Leakage Monitoring Methods 54
7
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SECTION 1 - FACILITY INFORMATION
This section contains key information regarding the Acid Gas and C02 injection facility.
Reporter number:
• Gas Plant Facility Name: 30-30 Gas Plant
• Greenhouse Gas Reporting Program ID: 574501
o Currently reporting under Subpart UU
• Operator: Stakeholder Gas Services, LLC
Underground Injection Control (UIC) 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 Rattlesnake AGI #1 well as a UIC Class II well. A Class II
permit was issued to Stakeholder under TRRC Rule 9 (entitled "Disposal into Non-Productive Formations")
and Rule 36 (entitled "Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas").
UIC Well Identification Number:
Rattlesnake AGI #1, API No. 42-501-36998, UIC #000117143.
8
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SECTION 2 - PROJECT DESCRIPTION
This Project Description discusses the geologic setting, planned injection volumes and process, and the
reservoir modeling performed for the Rattlesnake AGI #1 well. The Class II UIC permit was initially applied
for and received by Santa Fe Midstream Permian, LLC. The asset was acquired in 2020 by Stakeholder and
has been in operation since that time. Since the original application, Lonquist has revised and updated the
geology and the plume modeling within the reservoir in preparing this MRV Plan.
The Rattlesnake AGI #1 well is located and designed to protect against migration of C02 out of the injection
interval and to prevent surface releases. The injection interval for Rattlesnake AGI #1 is located over 4,720'
below the primary producing formation, the San Andres, in the area and 8,593' below the base of the lowest
useable quality water table, as shown in Figure 2. This well injects both H2S and C02, therefore the well and
the facility are designed to minimize any leakage to the surface.
STAKEHOLDER
TREATING & PROCESSING
PLANT
2,450'
LOWEST
WATER TABLE
DEPTH
5,500'
CASING DEPTH
Casing consists of
reinforced steel
and concrete
11,000'
INJECTION WELL
DEPTH
>8,500'
BELOW THE
WATER TABLE
Figure 2 - Illustrative overview of Rattlesnake AGI tt1 and 30-30 Facility
9
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Regional Geology
The Rattlesnake AGI #1 well is located on the southern portion of the Northwestern Shelf within the larger
Permian Basin as seen in Figure 3. The Northwestern Shelf is a broad marine shelf located in the northern
portion of the Permian Basin,
Basin
Matador Arch
Eastern
Shelf
f.. NEW MEXICO
Jtexas |
Delaware'^
Basin \
Ozona
, Arch
>Val Verde
' Basin
.Ouach/h
NJ
NEW
MEXICO
WO ml
100 Km
I I Permian Basin
Figure 3 - Regional Map of the Permian Basin. Red Star is approximate location of Rattlesnake AGI #1 well
Figure 4 depicts the stratigraphic column found at the Rattlesnake AGI #1 well location with red stars
referencing the injection formation and green stars indicating the productive intervals in the area. The
primary injection interval is found within the Wristen group, of Silurian-age, as seen in Figure 5. The TRRC
refers to this sequence under the general terms "Devonian", "Silurian-Devonian" or "Siluro-Devonian".
10
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Period
Epoch
Formation
General Lithology
Permian
Ochoan
Dewey Lake
Redbeds/Anhydrite
Rustler
Halite
Salado
Halite/Anhydrite
Guadalupian
Tansil
Anhydrite/Dolomite
Yates
Anhydrite/Dolomite
Seven Rivers
Dolomite/Anhydrite
Queen
Sandy Dolomite/Anhydrite/Sandstone
Grayburg
Dolomite/Anhydrite/Shale/Sandstone
Leonardian
~ San Andres
Dolomite/Anhydrite
Glorieta
Sandy Dolomite
Yeso
Paddock
Dolomite/Anhydrite/Sandstone
Blinebry
Tubb
Drinkard
Abo
Dolomite/Anhydrite/Shale
Wolfcampian
^ Wolfcamp
Limestone/Dolomite
Pennsylvanian
Virgilian
Cisco
Limestone/Dolomite
Missourian
Canyon
Limestone/Shale
Des Moinesian
Strawn
Limestone/Sandstone
Atokan
Bend
Limestone/Sandstone/Shale
Morrowan
Morrow
Mississippian
Mississippian Lime
Limestone
Devonian
Woodford
Shale
Silurian
-^Wristen Group
Dolomite/Limestone
^ Fusselman
Dolomite/Chert
Ordovician
Upper
Montoya
Dolomite/Chert
Middle
Simspson Gp
Limestone/Sandstone/Shale
Lower
Ellenburger
Dolomite
Figure 4 - Stratigraphic column of the North west Shelf. Red stars indicate injection interval. Green stars indicate productive
intervals.
-------
Mississippian
Chesterian
undivided
Meramecian
Osagian
Kinderhookian
Devonian
Upper
Woodford Shale
Middle
Lower
Thirtyone Fm.
Silurian
Pridolian
Wristen Gp.
~
Fasken
Fm.
Frame Fm.
Ludlovian
Wink Fm.
Wenlockian
Llandoverian
Fusselman Fm.
Ordovician
Upper
Montoya Fm.
Simpson Gp.
Middle
Lower
Ellenburger Fm.
Figure 5 - Stratigraphic column depicting the composition of the Silurian group. Red star indicates injection interval (Broadhead,
2005)
The Wristeri group was deposited in a basin platform setting across the northern half of the Permian Basin.
The depositional environment over Yoakum County during the Silurian period was a shallow inner platform,
the margin of which exists to the south, in southern Andrews County, Texas. The Silurian-age lithology on
the inner platform is dominated by grain-rich skeletal carbonates. Carbonate buildups are common within
the shallow inner platform, mainly skeletal wackestone, indicating a lower-energy deposition on the inner
platform. The carbonate shelf margin to the south acted as a barrier from basin-ward wave energy (Ruppel
and Holtz, 1994).
Depositional cycles within the inner platform indicate it was controlled by episodic sea level rise and fail,
resulting in sub-areal exposure and diagenesis. The diagenesis of the Silurian-age carbonate rocks initiated
12
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secondary porosity development and increased permeability. Dolomite and solution-related features are the
most prominent diagenetic characteristics found within the Silurian. The Wristen Group is composed of three
formations: Fasken, Frame, and Wink formations. The Frame and Wink formations are found near the ramp
boundary to the south, while the Fasken formation is found predominantly in the inner platform, where the
Rattlesnake AGI #1 well is located. The Fasken formation is predominately dolomite grading to limestone,
occurring as cycles, down section. This dolomitization is due in part to sub-areal exposure, during which
karsts and secondary porosity developed. Additional dolomitization was possible during successive sea level
fluctuations via movement of magnesium-rich solution through karsts and vugs, which acted as channels for
fluid flow (Ruppel and Holtz, 1994).
Figure 6 shows a regional isopach map of the Silurian (combined Fasken and Fusselman formations) with a
red star depicting the Rattlesnake AGI #1 well location. Thickness of the Silurian-age rock is approximately
1,000' at the Rattlesnake AGI #1 well location.
North of Andrews County there is little differentiation between the Fasken and Fusselman formations which
are both carbonate deposits with the potential for sub-areal exposure and porosity development. For
purposes of this MRV Plan, the combined Fasken and Fusselman formations are defined as the injection
interval, and the underlying Montoya formation serves as the lower confining unit.
13
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ThjChMSJ (ft)
W'Uin plait ttf iM'tm
M«l$COC« |4?t«U«IS
wiOtAI
4.0*1*4
Ttm
S kM>M
c«o«rTT
Figure 6- Thickness map of the Silurian system which composes the Fusselman and Wristen group
14
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Regional Faulting
A major uplift that began during the Pennsylvanian Period to the south, the Central Basin Platform, ceased
in the Early Permian (Wolfcampian), which caused a regional unconformity of the underlying formations
(Hoak, Sundberg, and Ortoleva). Faulting on the Northwest Shelf can be seen through high angle basement
faults that tend to die within the Pennsylvanian strata. These faults predominately represent contractional
(thrust) faults that were initiated during the Pennsylvanian as a result of regional tectonics. Hydrocarbon
traps within the Wristen group are primarily anticlinal structures dependent upon reservoir development
(Broadhead, 2005).
Site Characterization
The Rattlesnake AGI #1 well is located in Section 733, Block D, John H. Gibson Survey, in Yoakum County,
Texas. Stakeholder owns the 82.42-acre surface tract where the plant and Rattlesnake AGI #1 well are
located. The following discusses the geological character of this site.
Stratigraphy and Lithologic Characteristics
Figure 7 depicts an open hole log from an offset well (API No. 42-501-10238) to the Rattlesnake AGI #1 well
indicating the injection and primary upper confining zone. This well is approximately 1.8 miles to the
northwest of the Rattlesnake AGI #1 well, An offset well log was used to depict the upper confining intervals
as electric logs were only run in the Rattlesnake AGI #1 well across the injection zone.
15
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Upper Confining Interval - Woodford Shale
The Woodford is a late Devonian-age organic-rich shale deposited as a result of a widespread marine
transgression. The flooding event occurred over the majority of the Permian basin, which produced a low-
relief blanket-like shale deposit of the Woodford. Two major lithofacies found within the Woodford are black
shale and siltstone. Nutrient-rich surface waters promoted the decay of abundant organic matter within the
Woodford, resulting in a high total organic carbon ("TOC") percentage. The Woodford shale acts as the
primary source and sealant rock for the Wristen Group (Comer, 1991).
Figure 8 is a description of a core sample taken in Lea County, New Mexico just southwest of the Rattlesnake
AGI #1 well location. This sample is referenced as C9 in the reference map with the blue star representing
the Rattlesnake AGI #1 well. In the core description, black shale with abundant illitic clays is observed in the
upper section, and medium gray dolomitic siltstone found in the basal section. The mineralogic and lithologic
properties recorded in this description serve as excellent sealant characteristics to prohibit any injected fluids
from migrating above the injection interval.
The Woodford at the Rattlesnake AGI #1 well location is encountered at 10,973 ft and is approximately 63 ft
thick.
C9
Shell No. 5 Pacific Royalty
Lea County, New Mexico
Section 10.T15S-R37E
Elevation 3814 ft
X
Q
TOC
Weight
percent
1 2 3 4 5
—I I I I L_
GR i
C9 5
cs s
C9 7
Description
(ft)
35+
-12.200
Medium* to dark-gray limestone Lime mudstone with a few thin beds of brachiopod
wackestone and skeletal and pellet grainstone Some intervals highly fractured; all
fractures are filled, some with calcite, some with silica. Lowor contact not
preserved, probably conformable.
Green limestone. Clay rich. Lower contact not preserved, probably disconformablo.
Black shale. Parallel laminae Abundant fllitic clay; pyritic. Scattered grains of sift*
sized quartz, dolomite, and mica. Spores scattered or concentrated in thin laminae,
some spores replaced by pyrite, some by carbonate; sparse laminao of Radiolana;
rare burrows filled by chert, carbonate, and anhydrite Scarce veinlets filled with
calcite. Lower contact not preserved, probably conformable and abruptly gradatiorial.
I
| Boii»y
•Cochron
JRqCtMT
Medium-gray dolomitic siltstone. Abundant silt-sized anhedral and subnedral dolomite;
s»lt-sized quartz common Interbedded and interlaminated dark-gray shate and
medium-gray line-grained catcite grainstone, packs tone, and lime mudstone Wavy to
discontinuous bods near top; becomes more discontinuous, contorted, and mottled
downward; shales have parallel to wavy laminae. Pyritjc; micacoous. Sparse burrows;
rare Lmgula and wood fragments. Grades downward into lighter gray dolomitic
siltstone with fewer shale inter bods Lower contact not preserved, probably
disconfonrtablo.
Pale brownish pink crystalline dolostone. Vuggy.
^Medium-gray shale. Dolomitic; silty.
69+
Pale brownish-pink crystalline dolostone Vuggy.
»-12,400
l£
| Y00hum
I
I
I ~
' Coirct
Figure 8- Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994)
16
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Injection Interval - Fasken Formation
The Rattlesnake AGI #1 well reaches total depth in the Fasken/Fusselman formation (Silurian in age), directly
below the Woodford formation. Dolomites at the top of the Fasken formation underwent multiple leaching
and diagenetic episodes which developed secondary porosity. This is evidenced in offset wells by the practice
of only drilling through the top 30' of the Fasken, in anticipation of encountering the best reservoir quality.
In Figure 8, the uppermost Silurian section is described as 'vuggy dolostone' in the core description. Beds
below the top of the Fasken section may also have similar petrophysical attributes if exposed to multiple
diagenetic events. Solution-collapse and karst breccia horizons can be found within inner platform deposits,
some occurring as much as 100 ft below the Fasken top (Ruppel and Holtz, 1994).
Porositv/Permeabilitv Development
Porosity in the Fasken formation at the Rattlesnake AGI #1 well location is typically moldic and intercrystalline
associated with leaching of allochem-rich intervals. Porosity is directly related to these leaching events which
occurred during and post-deposition, resulting in vugs and karst-like features. Figure 9 provides reservoir
information from core data within fields in the Wristen buildup and platform carbonate play. The average
porosity of these cores is 7.1% with an average permeability of 45.28 millidarcies (Ruppel and Holtz, 1994).
The porosity and permeability described in the offset core data indicate the Fasken formation provides
sufficient accessible pore space for the amount of fluid injection proposed.
Using the above values as reference points, the Rattlesnake AGI #1 porosity log (API No. 42-501-36998) was
evaluated. Figure 10 is the product of the petrophysical analysis performed on the open hole logs run within
the injection interval at the Rattlesnake AGI #1 well. A permeability curve was generated from the effective
porosity curve using the table in Figure 9 to establish the porosity-permeability relationship. In Figure 10,
the majority of the injection interval's porosity and permeability is found at the top of the Fasken formation,
which correlates with the diagenetic processes described above. These curves are extrapolated to the
injection site and used to establish reservoir characteristics in the plume model.
17
-------
Wristen
Fusselman
Buildups and
Thirtyone
Thirtyone
Shallow Platform
Platform
Ramp
Deep-Water
Carbonate play
Carbonate play
Carbonate play
Chert play
Porosity (%>
Numbe/ o' data points
33
30
16
35
Mean
7,93
7. to
e.4i
14,85
Mnimum
1.00
2.70
3.50
2.00
Maximum
17,70
14.00
0.50
30.00
Standard devation
4.01
2.67
1.75
6.76
Permeability (md)
dumber ot (Jala points
21
24
12
33
Mean
11.61
45.28
1.51
9.56
Minimum
0.60
2.90
0.40
1.00
Maximum
84.80
400.00
30.00
100.00
Standard deviation
22.48
99.17
8.36
22.23
Initial water saturation {%)
Number oi data points
24
28
10
31
Mean
26.96
31.55
24.70
31.46
Mmmnum
10.00
20.00
16.00
10.00
Maximum
50.00
55.00
40.00
45.00
Standard deviation
9.31
10.4b
7.39
8.33
Residua) oil saturation {%)
Number a', data points
8
13
5
22
Mean
34.06
30.54
21.30
29.17
Minimum
30.00
20.00
9.00
14.00
Maximum
50.00
35.00
35.00
48.20
Standard devation
6.99
4.61
11.66
9.76
Oil viscosity (op)
Number oi data points
11
12
5
21
Mean
0.69
1.10
0.33
0.68
Mrnmum
0.13
0.32
0.04
0.07
Maximum
1.08
2.00
1.00
1.03
Standard devation
0.81
0.75
0.40
0.42
Oil formation volume factor
Number oi data points
21
22
6
32
Mean
1.57
1.22
1.65
1.50
Mnirnum
1.05
1.05
1.31
1.30
Maximum
1.91
1.55
1.66
1.73
Standard deviation
0.28
0.14
0.48
0.16
Bubble-point pressure (psi)
Number of data points
9
9
5
19
Mean
2.272
1,055
3.750
2.752
Minimum
798
450
2.660
1.755
Maximum
4.C50
2,600
4,440
4.655
Standard devation
1.300
689
756
667
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays (Ruppel and Holtz, 1994)
-------
Low Perm
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
0
[PLJ]=11036.9
Figure 10- Rattlesnake AG I #1 open hole log (42-501-36998) with effective porosity (green) and permeability (black)
Formation Fluid
Four wells were identified through a review of chemical analyses of oil-field brines from the U.S. Geological
Survey National Produced Waters Geochemical Database v2.1 within the Devonian, Silurian-Devonian, or
Fusselman formations within 20 miles of the Rattlesnake AGI #1 well. The location of these wells is shown in
Figure 11. Water chemistry analyses conducted on oil-field brines in Gaines County, as reported to the Texas
19
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Water Development Board, provided additional data on Devonian and Silurian reservoir fluids. Results from
the synthesis of these two sources are provided in Table 1. The fluids have greater than 20,000 parts per
million ("ppm") total dissolved solids, therefore these aquifers are considered saline. These analyses indicate
the in-situ reservoir fluid of the Devonian, Silurian, and Fusselman formations are compatible with the
proposed injection fluids.
Figure 11 - Offset wells used for Formation Fluid Characterization
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples
Average
Low
High
Total Dissolved Solids (ppm)
41,428
23,100
55,953
pH
7,2
7.0
7.3
Sodium (ppm)
12,458
7,426
15,948
Calcium (ppm)
1,759
1,010
2,320
Chlorides (ppm)
23,423
12,810
31,930
Fracture Pressure Gradient
Fracture pressure gradient was estimated using Eaton's equation. Eaton's equation is commonly accepted
as the standard practice for the determination of fracture gradients. Poisson's ratio ("v"), overburden
gradient ("OBG"), and pore gradient ("PG") are all variables that can be changed to match the site-specific
injection zone. Through literature review and industry standards, we are able to determine the expected
20
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fracture gradient. First, 1.05 psi/ft and 0.465 psi/ft were assumed for both the overburden and pore
gradients, respectively. These values are considered best practice values when there are no site-specific
numbers available. For limestone/dolomite rock, the Poisson's ratio to be assumed to be 0.3 through
literature review (Molina, Vilarras, Zeidouni 2016). Using these values in the equation below, a fracture
gradient of 0.72 psi/ft was calculated. A 10% safety factor was then applied to this number resulting in
maximum allowed bottom hole pressure of 0.64 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.
For the upper confining interval, a similar fracture gradient as the limestone was calculated. Shale has an
increased chance to vertically fracture if the injection interval is fractured (Molina, Vilarras, Zeidouni 2016),
so assuming a Poisson's ratio equal to the injection interval was used as a conservative estimate. The lower
confining zone was assumed to be of a similar matrix to that of the injection interval, with the key difference
being that the formation is much tighter (lower porosity/permeability). The Poisson's ratio was assumed to
be slightly higher in this rock. As seen in Table 2, the fracture gradient is slightly higher than the upper zones.
Table 2 - Fracture Gradient Assumptions
Injection Interval
Upper Confining
Lower Confining
Overburden Gradient (psi/ft)
1.05
1.05
1.05
Pore Gradient (psi/ft)
0.465
0.465
0.465
Poisson's Ratio
0.30
0.30
0.31
Fracture Gradient psi/ft
0.72
0.72
0.73
FG +10% Safety Factor (psi/ft)
0.64
0.64
0.66
The following steps were taken to calculate fracture gradient:
FG = —-—(OBG - PG) + PG
1 — v
0.3
FG = 1_Q3(1-05 - °-465) + °-465 = °-72
FG with SF = 0.72 x (1 - 0.1) = 0.64
Lower Confining Zone - Montoya Formation
The low-permeability Montoya Formation is a tight limestone/dolomite that will act as the lower confining
unit for the injection interval. Figure 10 shows the decreasing trend in porosity of the limestone rock in the
lower section that was not exposed to leaching diagenesis. Porosity in the lower section can range from 2-
3% with permeabilities below 1 millidarcy. The Rattlesnake AGI #1 well drilled 6' into the Montoya formation,
but the section was not logged. The Montoya is anticipated to be roughly 250' thick. These petrophysical
characteristics represent ideal sealing properties to prohibit any migration of injected fluid outside of the
injection interval.
Local Structure
Regional structure in the area of the Rattlesnake AGI #1 well is dictated by carbonate buildups and structural
events causing anticlinal to synclinal features throughout the area. The Rattlesnake AGI #1 well is specifically
located at the base of a syncline with anticlinal features to the northeast, south, and east. Figure 12 is a
21
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structure map of the Silurian formation of subsea depths with the star representing the location of the
Rattlesnake AGI #1 well. The red and blue lines represent the cross-section reference lines.
Faulting can be seen to the south and east of the Rattlesnake AGI #1 well location. These faults were
interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure 12. Many of
these faults are minor, with offsets less than 50'. The nearest large fault is found southeast of the Rattlesnake
AGI #1 well and has an offset of roughly 120'. None of these faults project above the Wolfcamp formation,
rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. Production is
associated with a hydrocarbon trap set up by the larger fault to the southeast, indicating the fault is vertically
sealing in nature. If, in the unlikely event the faults' sealing properties are compromised post-injection,
secondary confinement is provided by the tight limestones found within the overlying Mississippian Lime
formation along with shale layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the
largest fault found southeast of the Rattlesnake AGI #1 well, terminates within the Atoka formation. Though
it crosses the Silurian section, this fault thrusts the Mississippian Lime upward against the Atoka shales. The
tight reservoir characteristics of the Mississippian Lime and shaley section of the Atoka create a confining
environment vertically and laterally to contain potential upward migration of buoyant fluids. Shales within
the Wolfcamp formation provide additional confining beds between overlying USDWs and the fault plane.
Figures 13 and 14 are north-south and west-east structural cross sections showing the structural dips. As
seen in these figures, the Woodford formation is laterally present above the injection interval, alleviating risk
of erosion of the upper sealant formation.
Larger versions of Figures 11, 12, 13 and 14 are provided in Appendix A.
22
-------
-------
-------
NW
3T?w'
42501105700000
1-667
TEXAS CRUDE OIL CO
+
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
42501358340000
ROBERTS UNIT
2
APACHE
42501335110000
CORNELL UNIT
3019D
EXXON MOBIL
SE
asr
MONTOYA [PUJ
25
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Injection and Confinement Summary
The lithologic and petrophysical characteristics of the Faskeri and Fusseiman formations at the Rattlesnake
AGI #1 well location indicate the formations have sufficient thickness, porosity, permeability, and lateral
continuity to accept the proposed injection fluids. The Woodford formation shale at the Rattlesnake AGI #1
well has low permeability and is of sufficient thickness and lateral continuity to serve as the upper confining
zone. Beneath the injection interval, the low permeability, low porosity Montoya formation is unsuitable for
fluid migration and serves as the lower confining zone. Deeper, laterally continuous formations, including the
Simpson Group, provide additional confinement.
Groundwater Hydrology
Yoakum County falls within the boundary of the Sandy Land Underground Water Conservation District. Three
aquifers are identified by the Texas Water Development Board's Aquifers of Texas report in the vicinity of the
proposed Rattlesnake AGI #1 well: the Dockum Aquifer, Edwards-Trinity Aquifer, and Ogallala Aquifer
(George, Mace and Petrossian, 2011). Table 3 references the aquifers' positions in geologic time and the
associated geologic formations. A schematic cross section in Figure 15, near the proposed Rattlesnake AGI
#1 well, illustrates the structure and stratigraphy of these water-bearing formations. Groundwater flow
direction is the same for the three aquifers, generally from northwest to southeast, Figure 16 (Teeple, et al.,
2021).
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and Yoakum Counties, Texas
(Teeple, et al. 2021)
Era
Period
Epoch or series
Geologic unit group
or formation
Lithologic descriptions
Hydrogeologic unit
Cenozoic
Tertiary
Pliocene
Ogallala Formation
Gravel, sand, silt,
and clay
High Plains
aquifer system
(Ogallala aquifer)
Miocene
Mesozoic
Cretaceous'
Comanchean
Series
Washita Group2
Shale and limestone
Edwards-T rinity
(High Plains)
aquifer system
Fredericksburg Group
Clay, shale, and
limestone
Trinity Group
Sand and gravel
Triassic
Upper
Dockum Group
Sillstone, mudstone,
shale, and sandstone
Dockum aquifer
26
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Figure 15- NW-SE Cross Section of aquifers in the Rattlesnake AG! #1 well area (George, Mac and Petrossian, 2011)
27
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IOCKLEV COI NTY 8 103°0'
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HOC KLEV COl.Vn
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rrir
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-HOCKLEY COUNTY
0 5 10 (SMILES
1 . 1 r i1 1
0 5 tO T5 KILOMETERS
Base modified tram U S Geological Survey 1 250 000-scale to 1 2,000.000-scale digital data.
Universal Transverse Mercator projection, ione 13
North American Datum of 15&3
Groundwater-level altitude, in
leal above North American
Vertical Oatum of 1988
|^m" >3,750
Hj- 3,500
3,250
3,000
<2,750
EXPLANATION
Study area boundary
Edwards-Trinity I High Plains} nquilor downdip enfant
Underground water conservation district boundary
Llano Estacado Underground Water Conservation District
Sandy Land Underground Water Conservation District
South Plains Underground Water Conservation District
Potenriometric contour Shows altitude at
which water level would have stood in
tightly cased wells. Contour interval is
100 feel Datum it North American
Vertical Datum of 1988 Dashed where
mlerred.
Groundwater How pallia Dashed where
interred
• Groundwater tevol measurement (Payne
and others. 2020)
Figure 16 - Potentiometric surfaces from wells completed in A, Ogallala aquifer, B, the Edwards-Trinity aquifer and C, the Dockum
aquifer (George, Mace and Petrossian, 2011).
The Dockum Aquifer is the oldest of the three aquifers, formed from Triassic-age Dockum Group sediments,
and underlies the Cretaceous Trinity and Fredericksburg Groups (Teeple, et al., 2021). Figure 17 shows the
subsurface and outcrop extent of the Dockum Aquifer. As shown in Figure 18, the total dissolved solids in
western Yoakum County exceed 5,000 milligrams per liter ("mg/L"), therefore the aquifer is considered
brackish.
28
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Dockum
Aquifer
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDBj
Figure 18 - Total dissolved solids in groundwater from the Dockum Aquifer (Ewing et at, 2008)
The Edwards-Trinity Aquifer is a collection of Cretaceous age sediments - primarily the Trinity Group Antlers
formation sandstone and limestones of the Fredericksburg Group, specifically the Comanche Peak and
Edwards formations. Figure 19 shows the subsurface and outcrop extent of the Edwards-Trinity Aquifer.
Freshwater infiltration to this aquifer is primarily from the overlying Ogallala Aquifer (George, Mace and
Petrossian, 2011).
29
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The Ogallala aquifer consists of sand, gravel, clay and silt sediments (George, Mace and Petrossian, 2011) and
produces the majority of the freshwater for Yoakum County. Figure 20 shows the subsurface and outcrop
extent of the Ogallala Aquifer.
The base of the deepest aquifer is separated from the injection interval by approximately 8,600' of rock,
including 576' of Salado salt. Though unlikely for reasons outlined in the confinement and potential leaks
sections, if migration of injected fluid did occur above the Woodford Shale, thousands of feet of tight
sandstone, limestone, shale, salt and anhydrite beds occur between the injection interval and the lowest
water-bearing aquifer.
30
-------
The TRRC's Groundwater Advisory Unit ("GAU") identified the base of Underground Sources of Drinking
Water ("USDW") at 375' at the location of the Rattlesnake AGI #1 well. Therefore, there is approximately
10,661' 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
Rattlesnake AGI #1 well is provided in Appendix B.
Description of the Injection Process
Current Operations
The 30-30 Facility and its associated Rattlesnake AGI #1 well began operating in March of 2019. Since
operations began, 258 million cubic feet ("MMCF") of treated acid gas ("TAG") has been injected, which
equates to 12,316 metric tons of C02. Over the life of the injection period, the average daily injection rate
has been 223 MSCF/d. The approximate current composition of the TAG stream is as follows;
Table 4 - Gas Composition of 30-30 Facility outlet
Component
Mol %
C02
89.68%
H2S
9.20%
Other
1.12%
31
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The 30-30 Facility is designed to compress, treat, and process natural gas produced from the surrounding
counties in Texas and New Mexico. The gas is dehydrated to remove the water content, then processed to
separate natural gas liquids which are then sold, along with the pipeline quality natural gas, to various
customers. TAG is then directly routed from the plant amine regen system to the Rattlesnake AGI #1 well.
The facility is manned 24 hours per day, 7 days per week.
Planned Operations
Stakeholder anticipates increasing the amount of CO2 injected into Rattlesnake AGI #1 well from the current
rate up to 16 MMSCF/d. Additional growth is expected both at Stakeholder facilities and regionally as rising
sour gas production and flaring reduction mandates create the need for additional CO2 and H2S disposal
capacity. Stakeholder plans to inject into this AGI well for another 14 years for a total of 17 years from the
start of injection in 2019.
Figure 21 shows a high-level view of the current process flow plus the prospective additional operations over
time.
Amine Regen
System
>96% C02
1,090-1,150 psig
CO, Offta ke
13% H2S, 87% COj
1,400-2,200 psig
AGI
Compression
Prospective Facilities
Meter
er XV
Meter
&
XV
A
l_
"l
I
-L
596-13% HjS, 87%-
95% C02
1,400-2,500 psig
Injection
Pumps
XV
Current Operation
AGI
Well
Figure 21 - 30-30 Facility Process Flow Diagram
Reservoir Characterization Modeling
The modeling software used to evaluate this project was Computer Modelling Group's GEM 2020.11 ("GEM")
simulator. Computer Modelling Group ("CMG") has put together one of the most accurate and technically
sound reservoir simulation software packages for conventional, unconventional, and secondary recovery.
GEM utilizes equation-of-state ("EOS") algorithms along with some of the most advanced computational
methods to evaluate compositional, chemical, and geochemical processes and characteristics to produce
highly accurate and reliable simulation models for carbon injection and storage. The GEM model is
recognized by the EPA for use in area of review delineation modeling as listed in the Class VI Well Area of
Review Evaluation and Corrective Action Guidance document.
The Silurian (Fasken/Fusselman) formation is the target formation for Rattlesnake AGI #1 well. The Petra
software package was used to create the geologic model of the target formation. The faulting and geologic
structure was then imported into GEM and used to create contours for the model grid.
Porosity and permeability estimates were determined using the porosity log from the Rattlesnake AGI #1
well and a petrophysical analysis was performed to correlate porosity values by depth with core porosities
32
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as shown in the Holtz paper. The Coates permeability equation was then used to calculate permeability with
depth. Both porosity and permeability are assumed to be laterally homogeneous in the reservoir.
The reservoir is assumed to be at hydrostatic equilibrium and initially saturated with 100% brine. An infinite
acting reservoir was created to simulate boundary conditions. The gas injectate is composed of H2S, CO2,
CH4, and other components as shown in Table 5. Core data from literature review was used to determine
residual gas saturation (Ruppel and Holtz, 1994). The modeled composition only takes into consideration the
carbon dioxide and hydrogen sulfide as they comprise nearly 99% of total stream. For the initial injection
period, these compositions are normalized up to 100%. For the proposed additional injection period, it is
expected that a larger portion of the gas added is carbon dioxide, changing the composition to ~93% CO2 and
~7% H2S.
Table 5 - Modeled Initial Gas Composition
Measured Current
2019-2024 Model
2024-2036 Model
Component
Composition (mol%)
Composition (mol%)
Composition (mol%)
Carbon Dioxide (C02)
89.678
90.696
92.921
Hydrogen Sulfide (H2S)
9.200
9.304
7.079
Methane (CI)
0.303
0
0
Ethane (C2)
0.058
0
0
Propane (C3)
0.108
0
0
N-Butane (NC4)
0.025
0
0
Hexane Plus (C6+)
0.628
0
0
Core data from literature review was used to determine relative permeability curves between carbon dioxide
and the connate brine within the Silurian-Devonian carbonates (Ruppel and Holtz, 1994). The key inputs
used in the model include an irreducible water saturation of 25% and a maximum residual gas saturation of
21%.
The grid contains 141 blocks in the x-direction (E-W) and 201 blocks in the y-direction (N-S), totaling 28,341
grid blocks per layer. The grid blocks are each 150' by 150' by layer thickness as specified in Table 6. This
results in the grid being 21,150' by 30,150' totaling just over a 23-square mile area (14,640 acres). Each layer
in the model was determined by identifying higher permeability zones as targets for injection from the logs
and assigning each high permeability and intermediary low permeability zone its own layer. One zone was
identified as being a karst limestone (layers 2-7). Due to the "karsted" nature of this rock, it was determined
that most of the injectate would flow into this zone. Therefore, the karst limestone was further split into
layers by permeability to provide higher resolution and more accurately simulate which layer will have more
gas flow into it. Figure 22 provides a detailed breakdown of the "karsted" rock.
33
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Permeability Distribution of Karst Zone
2
3
4
l—
(D
_l
5
6
7
1 10 100 1000
Permeability (mD)
Figure 22 - Permeability Distribution of Karst Limestone
In total, there are sixteen (16) layers in the model, representing ten (10) layers of pay and six (6) layers of
intermediary low permeability zones. The properties of each of these layers are summarized in Table 6
below.
Table 6 - CMG Model Layer Properties
Layer #
Top (ft)
Thickness (ft)
Permeability (mD)
Porosity
1
11,037
71
1
2.8%
2
11,108
57
47
8.0%
3
11,165
19
223
11.9%
4
11,184
16
15
6.3%
5
11,200
39
70
9.2%
6
11,238
11
228
12.3%
7
11,249
21
49
8.3%
8
11,270
251
2
3.7%
9
11,520
46
9
5.6%
10
11,566
13
3
4.3%
11
11,579
19
17
6.5%
12
11,597
14
2
3.9%
13
11,611
103
13
6.0%
14
11,714
46
2
3.7%
15
11,759
67
23
6.1%
16
11,826
125
2
3.6%
34
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Simulation Modeling
The primary objectives of the model simulation were to:
1) Estimate the maximum areal extent and density drift of the acid gas plume after injection
2) Assess the impact of offset saltwater disposal ("SWD") well injection on density drift of the plume
3) Assess the impact of offset producing wells on the density drift of the plume
4) Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone
5) Assess the likelihood of the acid gas plume migrating into potential leak pathways
The reservoir is assumed to be an aquifer filled with 100% brine. The salinity of the formation is estimated
to be 53,000 ppm (Texas Water Development Board, 1972). The acid gas stream is primarily composed of
C02 and H2S as stated previously. Core data was used to help generate relative permeability curves. Cores,
from the literature reviews previously discussed, that most closely represent the vuggy carbonate seen in
this region were identified and the Corey-Brooks equations were used to develop the curves. The lowest
residual gas saturation found in the cores was then used for a conservative estimate of plume size. From
offset injection well analysis, the initial reservoir pressure was determined to be 5,132 psi which is equivalent
to a 0.465 psi/ft pressure gradient. The fracture gradient of the injection zone was estimated to be 0.72
psi/ft, which was determined using Eaton's equation. A 10% safety factor was then applied to this number,
putting the maximum bottom-hole pressure allowed in the model at 0.64 psi/ft which is equivalent to 7,064
psi.
The model also takes into account offset saltwater disposal ("SWD") injection volumes within five (5) miles
of the Rattlesnake AGI #1 well. These SWDs create a pressure front that push the plume further up-dip of
the formation. A total of twenty (20) offset wells currently injecting into the target formation were identified.
Eleven (11) of these offset SWDs were out of the confines of the grid, but were still accounted for in the
model. Nine (9) salt-water disposals were modeled within the boundaries of the 23-square-mile grid. Two
(2) of these offset injectors are currently only permitted (not drilled) but were assumed to start active
injection within the first year of the model. Both permits were simulated at the forecasted injection rate
schedule for 30 years. These forecasts were provided by the operators of these wells. Historical injection
rates of each of the other existing wells were analyzed and projected into the model. This simulation includes
the effect of water injection on the density drift of the plume and bottom hole pressure.
Further review of the area revealed production wells in the Silurian-Devonian formation that could impact
the density drift of the plume by creating a "pressure sink". A "pressure sink" is an area of lower pressure
caused by the production of formation fluids. To simulate this effect, nine (9) production wells were grouped
together and their respective production rates combined into a single well to add more conservatism into
the model. These producers were forecasted an additional 15 years to simulate their potential economic
lifespan. This simulation includes the effect of fluid production on the density drift of the plume and bottom
hole pressure. Overall, the "pressure sink" has little effect on the density drift and, as discussed below, the
plume never reaches the producing wells.
The model runs for a total of 814 years, starting in 1965 with the beginning of offset production until the
calculated stabilization of the plume in 2779. The injection of TAG from Rattlesnake AGI #1 is modeled from
the beginning of injection in 2019 through the planned 14 years of future injection. The model also includes
the 57 years of historical plus 15 years of forecasted future oil and gas production.
Additionally, historical monthly injection rates of all nearby SWDs were incorporated into the model to
simulate any additional near-wellbore pressure increase that may occur due to offset injection. The
35
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modelling of the saltwater injection begins in 1984 when the first offset SWD well became operational. The
SWDs to the North were grouped into four (4) separate groups to simulate their combined effect on the
density drift of the plume. All offset injection wells and their groupings are included in Table 7. All offset
production wells are listed in Table 8.
Table 7 - All Offset SI/l/Ds included in the model
Grouping
API
Well Name
Well#
42-501-32511
SAWYER, DESSIE
1
42-501-02068
WEST, M. M.
2
Group 1
42-501-02053
NORTH CENTRAL OIL CO. "A"
1
42-501-01453
SMITH, EDS. HEIRS "B"
1
42-501-02059
SMITH, ED "C"
1W
Group 2
42-501-30051
JOHNSON
2
42-501-30001
JOHNSON
ID
Group 3
42-501-37066
MISS KITTY SWD 669
1W
42-501-36650
RUSTY CRANE 604
1W
Group 4
42-501-36745
SUNDANCE 642
1
42-501-33887
WINFREY 602
3WD
42-501-37252
Miller SWD
7
42-501-37367
BLONDIE 704
1W
42-501-37206
BRUSHY BILL 707
1WD
42-501-36622
WISHBONE FARMS 710
1W
Standalone
42-501-35834
ROBERTS UNIT
2
42-501-33297
STATE ELMORE
1
42-501-10238
SHEPHERD SWD
1
42-501-33511
CORNELL UNIT
3019D
42-501-32868
WILLARD UNIT
1WD
Table 8 - All Offset Producers included in the model
API
Well Name
Well #
42-501-10046
ELLIOTT, C.A.
2
42-501-10079
RANDALL, E
32
42-501-337932
RANDALL, E
40
42-501-33885
RANDALL, E
41L
42-501-34016
RANDALL, E
43 L
42-501-34017
RANDALL, E.
45 L
42-501-34023
RANDALL, E
42L
42-501-34024
RANDALL, E
44
42-501-35418
RANDALL, E
46
Rattlesnake AGI #1 came online in 2019 and the model simulated its historical monthly injection rates until
2024. After this initial period, it is conservatively assumed that the injection rate increases to the maximum
permitted rate of 16 MMSCF/d for the remainder of the active injection period in 2036. At this point, the
36
-------
Rattlesnake AGI #1 well stops injection while the offset SWD injectors continue operations for thirty more
years. Density drift then occurs until plume stabilizes, which was determined to be 814 years from the start
of the model in 1965. Stabilization of the plume is determined to occur when the model shows no further
lateral movement horizontally or vertically. The plume boundary is then defined by a weighted average gas
saturation in the aquifer of 3%.
The maximum plume extent during the 17-year Rattlesnake injection period is shown in Figure 23. The final
extent after 743 years of density drift after injection ceases is shown in Figure 24. The extensive time of the
modeled density drift of the plume is driven by the buoyant forces of the gas, the permeability/porosity of
the rock, and the residual gas saturation. Initially, the karsted region takes on most of the injection, but due
to the buoyant forces, it is slowly pushed up higher into the less permeable layers of the injection interval.
These lower permeable layers, increase the amount of time it takes for the plume to reach its maximum areal
extent. As all the inputs to the model were based on the most conservative approach, the maximum extent
of the plume will likely be smaller and the effective impact on reaching potential leakage pathways will be
minimal as the amount of CO2 at those far extents will be small.
State Elmore
Brushy Bills 707
Shepherd SWD
Rattlesnake AGI Plume
Global Mote froction(CQ2) 2036-Jqn-Ol K Plone: 2 of 16
-0.70
¦ -060
1050
o.
-
0.20
Group 2 Group 4 Group 3 Group 1
Blondie 704
Mi ter SWD
Rattlesnake AGI
Willard Unit
Roberts Unit
Production Wells
Cornell Unit
Figure 23 - AreaI View Gas Saturation Plume, 2036 (End of Injection)
37
-------
Brushy Bills 707
19,215'
Miller SWD
6,900'
Blondie 704
Production Wells
Rattlesnake AGI
Willard Unit
Roberts Unit
Cornell Unit
Group 2 Group 4 Group 3 Group 1
State Elmore
Shepherd SWD
1.00-—
!¦
090
080
-070
-060
-
t
-030
020
Rattlesnake AGI Plume
Global Mole Fractlon{C02) 2779-Doc-OI K Plane: 2 of 16
Figure 24- Area! View Gas Saturation Plume, 2779 (End of Density Drift)
Figure 25 shows the surface injection rate and bottom hole pressure over the injection period and the period
of density drift after injection ceases. The bottomhole pressure increases the most as the injection rate
reaches its peak, reaching a maximum pressure of 5,413 psi. This buildup of 280 psi keeps the bottomhole
pressure well below the fracture pressure of 7,064 psi. The maximum surface pressure associated with the
maximum bottomhole pressure reached is 2,494 psi.
16.000,000
I" 14.000,000
£ 12,000,000
= 10,000,000
o
¦ 8,000,000
O
6,000,000
£
a 4,000,000
s 2.000,000
o
s
r
r
ltttf.ll
ij/"
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049 2051 2053 2055
5400 I
6370 J
S340 |
5310 b
O
5280 ®
T3
5250 ®
w
5220 c
at
5190 9*
v>
5160 —
— Rattlesnake AGI, Gas Rate SC - Daily
— Rattlesnake AGI, Well Bottom-hole Pressure
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time
38
-------
SECTION 3 - DELINATION OF MONITORING AREA
This section discusses the delineation of Maximum Monitoring Area ("MMA") and Active Monitoring Area
("AMA") as described in EPA 40 CFR §98.448(a)(l).
Maximum Monitoring Area
The MMA is defined as equal to or greater than the area expected to contain the free-phase C02 plume until
the C02 plume has stabilized plus an all-around buffer zone of at least one-half mile. 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 takes into account the
following considerations:
• 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 adequately predict the density drift of the plume
Acid gas injectate was analyzed by a third-party vendor to determine the initial composition used in the
model. The report is provided in Appendix C. The molar composition of the gas is primarily C02 with some
H2S and CH4. The change in molar composition was also incorporated into the model as future predominantly
C02 streams are added for injection. As discussed in Section 2, the gas was injected into the Silurian
formation, specifically, the Fasken/Fusselman formation. The geomodel was created based off the rock
properties seen in the Fasken/Fusselman.
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 2036, the areal
expanse of the plume will be 1,052 acres. The maximum distance between the wellbore and the edge of the
plume is approximately 0.87 miles to the southeast. After 743 additional years of density drift, the areal
extent of the plume is 2,177 acres with a maximum distance to the edge of the plume of approximately 1.35
miles to the southeast.
Figure 26 shows the plume boundary at the end of injection, the stabilized plume boundary and the MMA.
39
-------
f
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
6 Stabilized Plune
i
1/2-Mile Naxinua Monitoring Area CMHA)
Stakeholder Midstream
Yoakum Co., TX
Il J i
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PCS:
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Figure 26 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area
Active Monitoring Area
The initial AMA will cover a 14-year monitoring period. This period equates to the time of expected future
injection. The AMA will be established by superimposing the area based on a half-mile buffer around the
anticipated plume location at the end of injection (2036) with the area of the projected free-phase C02 plume
at five additional years (2041). In this case, the plume boundary in 2041 is within the plume at 2036 plus a
half-mile buffer. By 2036 at the latest, a revised MRV plan will be submitted to define a new AMA. Figure 27
shows the area covered by the AMA.
Larger size versions of Figures 26 and 27 are provided in Appendix D.
40
-------
ID
1 Inch = 0.51 Mile
1:32,000 m
&
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
& 19-Year Plume
wi th
1/Z-Hile Active Monitoring Area (AHA)
Stakeholder Midstream
Yoakum Co.. TX
PCS: NADB3 TX-NC FIPS 4202
-------
SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE
This section identifies the potential pathways for C02 to leak to the surface within the MMA and the
likelihood, magnitude and timing of such leakage. The potential leakage pathways are:
• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Natural or Induced Seismicity
• Drilling through the MMA
• Leakage through the confining layer
Leakage from Surface Equipment
The surface facilities at the 30-30 Facility are designed for injecting acid gas containing H2S, and therefore
minimize leakage points such as valves and flanges following industry standards and best practices. H2S gas
detectors are located around the facility and the well site. These gas detectors trigger alarms at 10 parts per
million ("ppm"). Additionally, all Stakeholder field personnel are required to wear H2S monitors which are
triggered at 5 ppm of H2S. A shut-in valve is located at the wellhead and is locally controlled by pressure,
with a high pressure and low pressure shut-off.
The facilities have been designed and constructed with additional safety systems to provide for safe
operations. These systems include Emergency Shutdown ("ESD") valves to isolate portions of the plant and
pipeline, pressure relief valves along the pipeline to prevent over pressurization, and flares to allow piping
and equipment to be de-pressured rapidly under safe and controlled operating conditions in the event of a
leak. Figures 28 and 29 display the facility safety plot plan, taken from the 30-30 H2S Contingency Plan, and
show the location of the H2S monitors in the vicinity of the plant and the Rattlesnake AGI #1 well. Should
Stakeholder construct additional C02 facilities, as indicated in Figure 21, a separate meter will be installed for
the additional stream in order to comply with the 40 CFR §98.448(a)(5) measurement. As this meter will be
in close proximity to the existing facilities, it will utilize the existing monitoring programs discussed previously.
Additionally, C02 monitors will be installed near the new meter and tied into the facility monitoring systems.
42
-------
Figure 28 - Site Plan, 30-30 Facility
43
-------
With the level of monitoring at the 30-30 Facility and the Rattlesnake AGI #1 well, any release of H2S and C02
would be quickly identified, and the safety systems would quickly minimize the volume of the release. The
C02 injected into the Rattlesnake AGI #1 is injected with H2S at a concentration of 10% (100,000 ppm). At
this high level of H2S concentration, even a small leakage would trigger personal and facility H2S monitors set
to alarm at 5 ppm and 10 ppm respectively. If any leakage were to be detected, the volume of C02 released
will 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).
A larger scale version of Figure 28 is provided in Appendix E.
Leakage from Wells in the Monitoring Area
Oil and Gas Operations within Monitoring Area
A significant number of wells have historically been drilled within the area of the Rattlesnake AGI #1 well,
however production has primarily been from the shallower San Andres formation in the Wasson Field. The
San Andres is separated from the Silurian-Devonian interval by 4,720' in this area. In addition to the primary
San Andres production, a few wells have produced from the Wolfcamp. The Wolfcamp is separated from the
Siluro-Devonian interval by is 1,800'. Within the projected plume area of the Rattlesnake AGI #1 well, there
are no penetrations of the injection interval. There are ten wells within the MMA that penetrate the
injection interval.
A review of the TRRC records for all of the wells which penetrate the injection interval within the MMA,
shows the wells were properly cased and cemented to prevent annular leakage of C02 to the surface. The
plugged wells are also adequately protected against migration from the Devonian by the placement of the
plugs within the wellbores. Additionally, the Rattlesnake AGI #1 well was designed to prevent migration from
the injection interval to the surface through the casing and cement placed in the well, as shown in Figure 29.
Mechanical integrity tests ("MIT") required under TRRC rules are run annually to verify the well and wellhead
can hold the appropriate amount of pressure. If the MIT were to indicate a leak, the well would be isolated
and the leak mitigated quickly to prevent leakage to the atmosphere.
A map of all wells within the MMA is shown in Figure 30. Figure 31 shows only those wells which penetrate
the injection interval within the MMA. The MMA review maps, a summary of all the wells in the MMA and
detailed wellbore schematics for those wells which penetrate the injection interval are provided in Appendix
F.
44
-------
Base of USDW@375'
Rustler @ 2,345'
Salado @ 2,443'
Yates @ 3,019'
Seven Rivers @ 3,440'
dH
Grayburg @ 4; 190'
San Andres @ 4,465'
DV Tool @ 4,275'
DV Tool @5,591'
Glorieta @ 6,316'
Clearfork @ 6,492'
Wichita @ 8,628'
12,500' -
13,000' -
15,500' -
GK
Upper Wolfcamp @ 9,239'
Strawn @ 10,030'
Atoka @ 10,230'
Woodford @ 10,973'
Devonian @ 11,036'
Wristen@ 11,268'
Fusselman@ 11,538' Ci)
Montoya @ 11,974'
¦
ir
DV Tool @9,575'
Packer @ 10,966'
TD@ 11,980'
KB:
N/A
BHF:
NA
GL:
3,627'
Spud:
5/27/2018
Casing/Tubing Information
Label
1
2
3
4
Type
Surface
Intermediate
Production
Tubing
OD
13-3/8"
9-5/8"
7"
3-1/2"
Weight
48
40
29
9,2
WT
.330
.395
.408
NA
Grade
H40/J55 STC
L- 80 BTC
L80 LTC
2535 Vam Top
L80 Vam Top:
G3 Vam Top'
Hole Size
17-1/2"
12-1/4"
8 3/4
6"
Depth Set
504'
5.498'
11,014'
10,966'
TOC
Surface
Surface
Surface
NA
Volume
510 sks
2,135 sks
760 sks
NA
LONQUIST & CO. LLC
PETROLEUM
ENER6Y
ENGINEERS
ADVISORS
HOUSTON'CALGARY
AUSTIN I WICHITA I DENVER
Stakeholder Midstream
Country: USA
Location: 33.07884, -103.904514
API No: 42-501-36998
Rattlesnake No. 1
State/Province: Texas
Site:
County/Parish: Yoakum
Survey:
Well Type/Status: AG I
Texas License F-9147
RRC District No:
Project No: LS 128
Date: 5/27/2022
12912 Hill Country Blvd Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Reviewed: SLP
Approved: SLP
Figure 29 - Rattlesnake AG! #1 Well bore Schematic
45
-------
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Figure 30 - Oil arid Gas Wells within the MMA
46
-------
1 Inch = 0.51 Mile
1:32,000 ^
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/„' $388$
BATTLES NAKCAOI NO. 1
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Yoakum Co.. TX
PCS: NAD S3 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER | Date: 6/1/2022 | Approved by: RH
LONQUIST & CO LLC
+ Rattlesnake ACI No. 1 SHL
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Figure 31 - Penetrating Oil and Gas Wells within the MMA
47
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Future Drilling
Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations, such as the Devonian, have proven to-date to be less productive or non-productive in this area,
which is why the location was selected for injection. Furthermore, any drilling permits issued by the TRRC in
the area of the Rattlesnake AGI #1 well include a list of formations for which oil and gas operators are
required to comply with TRRC Rule 13 (entitled "Casing, Cementing, Drilling, Well Control, and Completion
Requirements"). 16 TAC § 3.13. By way of example, see the Rattlesnake AGI #1 well drilling permit provided
in Appendix B. The Devonian is among the formations listed for which operators in Yoakum County (where
the Rattlesnake #1 is located) are required to comply with TRCC Rule 13 (Appendix B, pg. 5). TRRC Rule 13
requires oil and gas operators to set steel casing and cement across and above all formations permitted for
injection under TRRC Rule 9 or immediately above all formations permitted for injection under Rule 46 for
any well proposed within a one-quarter mile radius of an injection well. In this instance, any new well
permitted and drilled to the Rattlesnake AGI #1 well's injection zone, and located within a one-quarter mile
radius of the Rattlesnake AGI #1 well, will be required under TRRC Rule 13 to set steel casing and cement
above the Rattlesnake AGI #1 well injection zone. Additionally, Rule 13 requires operators to case and
cement across and above all potential flow zones and/or zones with corrosive formation fluids. The TRRC
maintains a list of such known zones by TRRC district and county and provides that list with each drilling
permit issued, which is also shown in the above-mentioned permit in Appendix B.
If any leakage were to be detected, the volume of C02 released will be quantified based on the operating
conditions at the time of release.
Groundwater wells
There are seven groundwater wells located within the MMA, as identified by the Texas Water Development
Board. All of the identified groundwater wells in the area have total depths less than or equal to 265', as
shown in Figure 32 and Table 9. One of the wells is located on the 30-30 facility property with a total depth
of 119'and is operated by Stakeholder.
The surface and intermediate casings of the Rattlesnake AGI #1 well, as shown in Figure 29, are designed to
protect the shallow freshwater aquifers consistent with applicable TRRC regulations and the GAU letter
issued for this location. See GAU letter included within Appendix B. The wellbore casings and cements also
serve to prevent C02 leakage to the surface along the borehole.
A larger scale version of Figure 32 is provided in Appendix F.
48
-------
1 Inch = 0.51 Mile
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Yoakum Co., TX
PCS: NAD 83 TX-NC FIPS 4202
-------
Table 9 - Groundwater Well Summary
State Well ID
Owner Name
Primary Use Well Depth Data Source
370449
Frances Barbini
Irrigation
237
SDRDB
443840
Frances Jean Barbini
Irrigation
250
SDRDB
482963
Santa Fe Midstream Permian
Industrial
119
SDRDB
510854
FRANCIS BARNINI
Irrigation
255
SDRDB
520249
Thomas Durham
Irrigation
264
SDRDB
543433
FRANCIS BARBIDI
Irrigation
240
SDRDB
84760
TEXACO PRODUCING INC
TWDB BW
Leakage Through Faults or Fractures
Faults were interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure
12. Faulting in this region terminates vertically below the Pennsylvanian-age rock. Secondary confining
shales within the Wolfcampian and younger strata provide additional, redundant confining layers that would
prevent C02from migrating into freshwater aquifers. None of the mapped faults project above the Wolfcamp
formation; rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. If, in
the unlikely event the faults' sealing properties are compromised post-injection, secondary confinement is
provided by the tight limestones found within the overlying Mississippianan Lime formation and the shale
layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the largest fault found SE of the
Rattlesnake AGI #1 well, terminates within the Atoka formation. Though it crosses the Silurian section, this
fault thrusts the Mississippian Lime upward against the Atoka shales. The tight reservoir characteristics of
the Mississippian Lime and shaley section of the Atoka create a confining environment vertically and laterally
to contain potential upward migration of buoyant fluids. Shales within the Wolfcamp formation provide
additional confining beds between overlying USDWs and the fault plane.
Should an unmapped fault exist within the plume boundary, the offset would be below 3D seismic resolution.
The offset would be less than the thickness of the Woodford shale, juxtaposing the Woodford against itself,
preventing vertical migration.
Fractures and subsequent subaerial exposure are responsible for porosity development within the injection
intervals. Open hole logs show little to no porosity development indicating the Woodford or Mississippian
Lime were not exposed at this location. Upward migration of injected gas through confining bed fractures is
unlikely.
50
-------
Leakage Through Confining Layers
The Silurian-Devonian injection zones have competent sealing rocks above and below the porous sub-aerially
exposed carbonate. The properties of the overlying transgressive Woodford shale (widespread deposition,
high illite clay and organic matter composition, and low porosity and permeability) make an excellent sealing
rock to the underlying Silurian formation. Tight Mississippian Lime of roughly 660 ft, lay between Atoka and
Woodford shale formations, forming an impermeable upper seal to the injection interval. Above this
confining unit, correlative shales of the Wolfcamp, Abo and Tubb formations will prevent any upper fluid
migration. These impermeable shales are capped by hundreds of feet of the regionally present Salado
formation evaporites. The USDW lies above the sealing properties of the formations outlined above, making
stratigraphic migration of fluids into the USDW highly unlikely. The underlying low porosity and permeability
Montoya carbonate minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injected gas to the in-situ reservoir fluid makes migration below the lower confining layer
unlikely.
Leakage from Natural or Induced Seismicitv
The location of Rattlesnake AGI #1 is in an area of the Permian Basin that is inactive from a seismicity
perspective, whether induced or natural. A review of historical seismic events on the USGS's Advanced
National Seismic System site (from 1971 to present) and the Bureau of Economic Geology's TexNet catalog
(from 2017 to present), as shown in Figure 33, indicates the nearest seismic event occurred more than 60
miles away.
A regional analysis of the probabilistic fault slip potential across the Permian Basin (Snee & Zoback 2016), as
seen in Figure 34, further demonstrates that the Rattlesnake AGI #1 well is located in a seismically inactive
area and confirms that this area has little to no potential for an induced seismicity event.
Therefore, there is no indication that seismic activity poses a risk for loss of C02 to the surface within the
MMA.
Pressures will be kept significantly below the fracture gradient of the injection and confining intervals.
Additionally, continuous well monitoring combined with seismic monitoring will identify any operational
anomalies associated with a seismicity event.
51
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LLANO E S TAC A DO
(STAKED PLAIN)
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0
#
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Sq.
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Figure 33 - Seismicity Review (TexNet - 06/01/2022)
52
-------
New MexJco
V Roosevelt
I 6 X d 5 izmo Male *
0«5>7cv Matador Arch
Cotrie
Lincoln
Cochran
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LUBBOCK
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— Cogdell field
(Snyder, TX)
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Fault slip potential (%):
0 10 2D 30 « 50+
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Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI ft1 location (Snee & Zobak 2016)
53
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SECTION 5 - MONITORING FOR LEAKAGE
This section discusses the strategy that Stakeholder 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). 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. Table 10 summarizes the
monitoring of potential leakage pathways to the surface. Monitoring will occur during the planned 17-year
injection period, or cessation of injection operations, plus a proposed 5-year post-injection period.
• Leakage from surface equipment
• Leakage through existing and future wells within MMA
• Leakage through faults and fractures
• Leakage through the confining layer
• Leakage through natural or induced seismicity
Because the acid gas injection stream also contains H2S, any leakage would be detected by the H2S alarms
located around the facility and would be quickly addressed which would minimize the release of C02 into the
atmosphere.
Table 10- Summary of Leakage Monitoring Methods
Leakage Pathway
Monitoring Method
Leakage from surface equipment
Fixed H2S monitors throughout the AGI facility
Daily visual inspections
Personal H2S monitors
Distributed Control System Monitoring (Volumes and Pressures)
Leakage through existing wells
Fixed H2S monitor at the AGI well
SCADA Continuous Monitoring at the AGI Well
Annual Mechanical Integrity Tests ("MIT") of the AGI Well
Visual Inspections
Quarterly C02 Measurements within AMA
Leakage through groundwater wells
Annual GroundwaterSamples on Property
Leakage from future wells
H2S Monitoring during offset drilling operations
Leakage through faults and fractures
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage through confining layer
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage from natural or induced
seismicity
Seismic monitoring station to be installed
54
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Leakage from Surface Equipment
As the 30-30 Facility and the Rattlesnake AGI #1 well are designed to handle H2S, leakage from surface
equipment is unlikely to occur and would be quickly detected and addressed. The facility design minimizes
leak points through the equipment used and the type of connections are designed to minimize corrosion
points. The H2S in the injectate serves as a proxy for the release of C02. The facility and well site contain a
number of H2S alarms, set with a high alarm setpoint of 10 ppm of H2S, which are shown in Figure 28 above.
Additionally, all Stakeholder field personnel are required to wear H2S monitors, which trigger the alarm at 5
ppm H2S.
The AGI facility is continuously monitored through automated systems. In addition, field personnel conduct
daily visual field inspections of gauges, monitors and leak indicators such as vapor plumes. The effectiveness
of the internal and external corrosion control program is monitored through the periodic inspection of the
system, analysis of liquids collected from the line, and inspection of the cathodic protection system. These
inspections, in addition to the automated systems, allow Stakeholder to quickly respond to any leakage
situation. Monitoring will occur for the duration of injection and the post-injection period. 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).
Leakage from Existing and Future Wells within Monitoring Area
Stakeholder continuously monitors and collects injection volumes, pressures, temperatures and gas
composition data, through their SCADA systems, for the Rattlesnake AGI #1 well. This data is reviewed by
qualified personnel and will follow response and reporting procedures when data is outside acceptable
performance limits. Rattlesnake AGI #1 has a pressure and temperature gauge placed in the injection stream
at its wellhead, and a pressure gauge on the casing annulus. A change of pressure on the annulus would
indicate the presence of a possible leak. Mechanical integrity tests ("MITs") performed annually would also
indicate the presence of a leak. Upon a negative MIT, the well would immediately be isolated and the leak
mitigated.
The ten offset penetrating wells within the MMA are adequately cased and cemented to prevent potential
leakage of C02 from the Rattlesnake AGI #1 well plume. Additionally, the plugged wells were done so in a
way to prevent migration of C02 as provided in Appendix E. As discussed previously, Rule 13 would ensure
that new wells in the field would be constructed in a manner to prevent migration from the injection interval.
In addition to the fixed and personal monitors described previously, Stakeholder will also establish and
operate an in-field monitoring program to detect any C02 leakage within the AMA. The scope of work will
include H2S and C02 monitoring at the AGI well site as well as minimum, quarterly atmospheric monitoring
near identified penetrations within the AMA. Upon approval of the MRV and through the post-injection
monitoring period, Stakeholder will have these monitoring systems in place. Additional monitoring will be
added as the AMA is updated over time.
At the well site, H2S and C02 concentrations will be monitored continuously with fixed monitors that detect
atmospheric concentrations of H2S and C02. At penetrating well sites, Stakeholder will similarly measure
atmospheric concentrations of C02 and H2S using mobile gas monitors. This data will be recorded at least
quarterly.
55
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Groundwater Quality Monitoring
Stakeholder will monitor the groundwater quality in fluids above the confining interval by sampling the well
on the facility property and analyzing the sample with a third-party laboratory on an annual basis. Any
significant changes to the water analysis would be investigated to determine if such change was a result of
leakage from the Rattlesnake AGI #1 well. The parameters to be measured will include pH, total dissolved
solids, total inorganic and organic carbons, density, temperature and other standard laboratory
measurements. Any significant differences in these parameters from the baseline sample will be evaluated
to determine if leakage of C02 to the USDW may have occurred.
Leakage through Faults, Fractures or Confining Seals
Stakeholder continuously monitors the operations of the Rattlesnake AGI #1 well through automated
systems. Any deviation from normal operating conditions indicating movement into a potential pathway
such as a fault or breakthrough of the confining seal would trigger an alert. Any such alert would be reviewed
by field personnel and action taken to shut in the well, if necessary. Field H2S monitoring systems would alert
field personnel for any release of H2S/CO2 caused by such leakage.
Leakage through Natural or Induced Seismicitv
While the likelihood of a natural or induced seismicity event is extremely low, Stakeholder plans to install a
seismic monitoring station in the general area of the Rattlesnake AGI #1 well. The installation of this station
would start upon approval of the MRV plan, with an expected in-service data within six months after the
commencement of the installation project. This monitoring station will be tied in to the Bureau of Economic
Geology's TexNet Seismic Monitoring system. If a seismic event of 3.0 magnitude or greater is detected,
Stakeholder will review the injection volumes and pressures at the Rattlesnake AGI #1 well to determine if
any significant changes occur that would indicate potential leakage.
56
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SECTION 6 - BASELINE DETERMINATIONS
This section identifies the strategies Stakeholder will undertake to establish the expected baselines for
monitoring C02 surface leakage per 40 CFR §98.448(a)(4). Stakeholder will use the existing SCADA monitoring
systems to identify changes from expected performance that may indicate leakage of C02.
Visual Inspections
Daily inspections will be conducted by field personnel at the 30-30 Facility and the Rattlesnake AGI #1 well.
These inspections will aid with identifying and addressing issues timely to minimize the possibility of leakage.
If any issues are identified, such as vapor clouds or ice formations, corrective actions would be taken to
address such issues.
H2S Detection
H2S will be initially injected into the AGI well at a concentration of approximately ten (10) percent or 100,000
ppm. The concentration will drop to approximately six (6) percent as additional volumes are added. H2S gas
detectors are located throughout the AGI facility and well site and are set to trigger the alarm at 10 ppm.
Additionally, all field personnel are required to wear personal H2S monitors, which are set to trigger the alarm
at 5 ppm. Any alarm would trigger an immediate response to protect personnel and verify that the monitors
are working properly. If monitors are working correctly, immediate actions would be taken to secure the
facility and mitigate potential leaks.
CO2 Detection
Any C02 release would be accompanied by H2S and therefore the H2S monitors at the facility would also serve
as a C02 release warning system. In addition to the fixed and personal monitors described previously,
Stakeholder will also establish and operate an in-field monitoring program to detect any C02 leakage within
the AMA. The scope of work will include H2S and C02 monitoring at the AGI well site as well as atmospheric
monitoring near identified penetrations within the AMA.
Operational Data
Upon starting injection operations, baseline measurements of injection volumes and pressures will be taken.
Any significant deviations over time will be analyzed for indication of leakage of C02.
Continuous Monitoring
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as per Texas regulations and Stakeholder's TRRC-
approved H2S Contingency Plan. Gas detectors and continuous monitoring systems would trigger an alarm
upon a release. The mass of the C02 released would be calculated for the operating conditions at the time,
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.
57
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No C02 emissions will occur from venting because of the high H2S concentrations. Blowdown emissions are
sent to flares and would be reported as part of the required reporting for the gas plant.
Groundwater Monitoring
An initial sample will be taken from the groundwater well on Stakeholder's property, identified as Well #
482963 in Table 9 above, upon approval of Stakeholder's MRV and prior to increasing injection. The sample
will be analyzed by a third-party laboratory to establish the baseline properties of the groundwater.
58
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SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE
EQUATION
This section identifies how Stakeholder will calculate the mass of C02 injected, emitted, and sequestered.
This also includes site-specific variables for calculating the C02 emissions from equipment leaks and vented
emissions of C02 between the injection flow meter and the injection well, per 40 CFR §98.448(a)(5).
Mass of CO2 Received
Per 40 CFR §98.443, the mass of C02 received must be calculated using the specified C02 received equations
"unless you follow the procedures in 40 CFR §98.444(a)(4)." 40 CFR §98.444(a)(4) states that "if the C02 you
receive is wholly injected and is not mixed with any other supply of C02, you may report the annual mass of
C02 injected that you determined following the requirements under paragraph (b) of this section as the total
annual mass of C02 received instead of using Equation RR-1 or RR-2 of this subpart to calculate C02 received."
The C02 received for this injection well is wholly injected and not mixed with any other supply and the annual
mass of C02 injected will equal the amount received. Any future streams would be metered separately before
being combined into the calculated stream.
Mass of CO2 Injected
Per 40 CFR §98.444(b), since the flow rate 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:
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 (metric tons per
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682
Cco2,P,u = Quarterly C02 concentration measurement in flow for flow meter u in quarter p (wt. percent
C02, expressed as a decimal fraction)
p = Quarter of the year
u = Flow meter
4
p = 1
where:
quarter)
59
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60
-------
Mass of CO2 Produced
The Rattlesnake AGI #1 well is not part of an enhanced oil recovery project; therefore, no C02 will be
produced.
Mass of CO2 Emitted by Surface Leakage
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as a major upset event. Gas detectors and continuous
monitoring systems would trigger an alarm upon a release. The mass of the C02 released would be calculated
for the operating conditions at the time, 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 C02 was released as a result 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:
C02 = 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 from subpart W will be used to calculate C02 emissions from equipment located on
the surface between the flow meter used to measure injection quantity and the injection wellhead
Mass of CO2 Sequestered
The mass of C02 sequestered in subsurface geologic formations will be calculated based off Equation RR-12,
as this well will not actively produce oil or natural gas or any other fluids, as follows:
X
X=1
Where:
CO 2 — C02i C02e C02fi
Where:
61
-------
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year
CO21 = 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
CO 2fi - 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
CO 2fi will be calculated in accordance with Subpart W reporting of GHGs. Because no venting would occur
due to the high H2S concentrations of the injectate stream, the calculations would be based on the blowdown
emissions that would be sent to flares and would be reported as part of the required GHG reporting for the
gas plant.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
62
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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN
The Rattlesnake AGI #1 well currently reports GHGs under Subpart UU, but Stakeholder has elected to submit
an MRV plan under, and otherwise comply with, Subpart RR. The MRV plan will be implemented upon
receiving EPA approval. The Annual Subpart RR Report will be filed on March 31st of the year following the
reporting year.
63
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SECTION 9 - QUALITY ASSURANCE
This section identifies how Stakeholder plans to manage quality assurance and control, to meet the
requirements of 40 CFR §98.444.
Monitoring QA/QC
C02 Injected
• The flow rate of the C02 being injected will be measured with a volumetric flow meter, consistent
with industry best practices. These flow rates will be compiled quarterly.
• The composition of the C02 stream will be measured upstream of the volumetric flow meter with a
continuous gas composition analyzer or representative sampling consistent with industry best
practices.
• The gas composition measurements of the injected stream will be averaged quarterly.
• The C02 measurement equipment will be calibrated according to manufacturer recommendations.
C02 Emissions from Leaks and Vented Emissions
• Gas detectors will be operated continuously, except for maintenance and calibration.
• Gas detectors will be calibrated according to manufacturer recommendations and API standards.
• Calculation methods from subpart W will be used to calculate C02 emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
Measurement Devices
• Flow meters will be continuously operated except for maintenance and calibration.
• Flow meters will be calibrated according to the requirements in 40 CFR §98.3(i).
• Flow meters will be operated per an appropriate standard method as published by a consensus-
based standards organization.
• Flow meter calibrations will be traceable to the National Institute of Standards and Technology
(NIST).
All measured volumes of C02 will be converted to standard cubic meters at a temperature of 60 degrees
Fahrenheit and an absolute pressure of 1 atmosphere.
Missing Data
In accordance with 40 CFR §98.445, Stakeholder 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 C02 injected is missing, the amount will be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.
• Fugitive C02 emissions from equipment leaks from facility surface equipment will be estimated and
reported per the procedures specified in subpart W of 40 CFR §98.
64
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MRV Plan Revisions
If any of the changes outlined in 40 CFR §98.448(d) occur, Stakeholder will revise and submit an amended
MRV plan within 180 days to the Administrator for approval.
65
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SECTION 10 - RECORDS RETENTION
Stakeholder will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
three years and include:
• Quarterly records of the C02 injected
o Volumetric flow at standard conditions
o Volumetric flow at operating conditions
o Operating temperature and pressure
o Concentration of the C02 stream
• Annual records of the information used to calculate the C02 emitted by surface leakage from leakage
pathways.
• Annual records of information used to calculate C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
66
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References
Broadhead, Ronald E., 2005. Regional Aspects of the Wristen petroleum system, southeastern New Mexico:
New Mexico Bureau of Geology and Mineral Resources Open File Report, no. 485.
Comer, John B., 1991. Stratigraphic Analysis of the Upper Devonian Woodford Formation, Permian Basin,
West Texas and Southeastern New Mexico: Bureau of Economic Geology Report of Investigations, no. 201.
George, Peter G., Mace, Robert E., and Petrossian, Rima, 2011. Aquifers of Texas: Texas Water Development
Board Report, no 380.
Hoak, T., Sundberg, K., and Ortoleva, P. Overview of the Structural Geology and Tectonics of the Central Basin
Platform, Delaware Basin, and Midland Basin, West Texas and New Mexico: Department of Energy Open File
Report.
Molina, Oscar, Vilarras, Victor, and Zeidouni, Mehdi, 2016. Geologic carbon storage for shale gas recovery:
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18.
Ruppel, Stephen C. and Holtz, Mark H., 1994. Depositional and Diagenetic Facies Patterns and Reservoir
Development in Silurian and Devonian Rocks of the Permian Basin: Bureau of Economic Geology Report of
Investigations, no. 216.
Snee, Jens-Erik Lund and Zoback, Mark D., 2016. State of stress in the Permian Basin, Texas and New Mexico:
Implications for induced seismicity.
Teeple, Andrew P., Ging, Patricia B., Thomas, Jonathan V., Wallace, David S., and Payne, Jason D., 2021.
Hydrogeologic Framework, Geochemistry, Groundwater-Flow System, and Aquifer Hydraulic Properties Used
in the Development of a Conceptual Model of the Ogallala, Edwards-Trinity (High Plains), and Dockum
Aquifers In and Near Gaines, Terry, and Yoakum Counties, Texas: USGS Scientific Investigations Report 2021-
5009.
67
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APPENDICES
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APPENDIX A-GEOLOGY
APPENDIX A-l: SILURIAN STRUCTURE MAP
APPENDIX A-2: NE-SW CROSS SECTION
APPENDIX A-3: NW-SE CROSS SECTION
APPENDIX A-4: FORMATION FLUID SAMPLE WELL MAP
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-------
mi
LONQU 1ST
SEQUESTRATION L
Stakeholder Midstream
-------
42501105700000
1-667
TEXAS CRUDE OIL CO
42501358340000
ROBERTS UNIT
2
APACHE
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
-------
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
Formation Fluid Sample Wells
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
| DENVER
• COLLEGE STATION |
[ BATON ROUGE • EDMONTON
-J- Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
-------
APPENDIX B - TRRC FORMS Rattlesnake AG I #1
APPENDIX B-l: UIC CLASS II ORDER
APPENDIX B-2: GAU GROUNDWATER PROTECTION DETERMINATION
APPENDIX B-3: DRILLING PERMIT
APPENDIX B-4: COMPLETION REPORT
-------
Christi Craddick, Chairman
Ryan Sitton, Commissioner
Wayne Christian, Commissioner
B-1
Danny Sorrells
Assistant Executive Director
Director, Oil and Gas Division
Leslie Savage
Assistant Director, Technical Permitting
Railroad Commission of Texas
OIL AND GAS DIVISION
PERMIT TO DISPOSE OF NON-HAZARDOUS OIL AND GAS WASTE BY INJECTION INTO A
POROUS FORMATION NOT PRODUCTIVE OF OIL AND GAS
PERMIT NO. 15848
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024
DOCKET NO. 8A-0312019
Authority is granted to inject Non-Hazardous Oil and Gas waste into the well identified herein in accordance
with Statewide Rule 9 of the Railroad Commission of Texas and based on information contained in the
application (Form W-14) dated March 12, 2018 for the permitted interval of the DEVONIAN formation and
subject to the following terms and special conditions:
RATTLESNAKE AGI (000000) LEASE
WASSON FIELD
YOAKUM COUNTY, DISTRICT 8A
WELL II
DENTIFIC ATION AND P]
ERMIT PA]
RAMET]
ERS:
Well No.
API No.
UIC Number
Permitted
Fluids
Top
Interval
(feet)
Bottom
Interval
(feet)
Maximum
Liquid
Daily
Injection
Volume
(BBL/day)
Maximum
Gas Daily
Injection
Volume
(MCF/day)
Maximum
Surface
Injection
Pressure
for Liquid
(PSIG)
Maximum
Surface
Injection
Pressure
for Gas
(PSIG)
1
50136998
000117143
C02, and
H2S
11,000
12,000
4,500
N/A
N/A
2,200
SPECIAL CONDITIONS:
Well No.
API No.
Special Conditions
1
50136998
1. Open hole completions shall have a plug back depth no deeper than the bottom of the
permitted injection interval.
2. The operator shall provide to the UIC section an annotated electric log, and a mud log if
available, of the subject well with the top(s) and bottom(s) of the permitted formation
indicated on the log. Top and bottom of the authorized injection interval may be modified
based on electric log or mud log indications of the top and bottom of the permitted
formations.
1701 NORTH CONGRESS AVENUE * POST OFFICE BOX 12967 * AUSTIN. TEXAS 78711-2967 * PHONE: 512/463-6792* FAX: 512/463-6780
TDD 800/735-2989 OR TDY 512/463-7284 * AN EQUAL OPPORTUNITY EMPLOYER* http://www.rrc.texas.gov
-------
STANDARD CONDITIONS:
1. Injection must be through tubing set on a packer. The packer must be set no higher than 100 feet above the
top of the permitted interval.
2. The District Office must be notified 48 hours prior to:
a. running tubing and setting packer;
b. beginning any work over or remedial operation;
c. conducting any required pressure tests or surveys.
3. The wellhead must be equipped with a pressure observation valve on the tubing and for each annulus.
4. Prior to beginning injection and subsequently after any work over, an annulus pressure test must be
performed. The test pressure must equal the maximum authorized injection pressure or 500 psig, whichever
is less, but must be at least 200 psig. The test must be performed, and the results submitted in accordance
with the instructions of Form H-5.
5. The injection pressure and injection volume must be monitored at least monthly and reported annually on
Form H-10 to the Commission's Austin office.
6. Within 30 days after completion, conversion to disposal, or any work over which results in a change in well
completion, a new Form W-2 or G-l must be filed to show the current completion status of the well. The
date of the disposal well permit, and the permit number must be included on the new Form W-2 or G-l.
7. Written notice of intent to transfer the permit to another operator by filing Form P-4 must be submitted to
the Commission at least 15 days prior to the date of the transfer.
8. This permit will expire when the Form W-3, Plugging Record, is filed with the Commission. Furthermore,
permits issued for wells to be drilled will expire three (3) years from the date of the permit unless drilling
operations have commenced.
Provided further that, should it be determined that such injection fluid is not confined to the approved interval, then
the permission given herein is suspended and the disposal operation must be stopped until the fluid migration from
such interval is eliminated. Failure to comply with all of the conditions of this permit may result in the operator
being referred to enforcement to consider assessment of administrative penalties and/or the cancellation of the
permit.
APPROVED AND ISSUED ON November 14. 2018.
Injection-Storage Permits Unit
IN-HOUSE AMENDMENT TO CORRECT THE RATE.
Note: This document will only be distributed electronically.
PERMIT NO. 15848
Page 2 of 2
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GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit
Form GW-2
B-2
Date Issued:
31 August 2017
GAU Number:
179154
Attention:
SANTA FE MIDSTREAM
API Number:
5700 GRANITE PARKWAY
County:
YOAKUM
PLANO, TX 75024
Lease Name:
Roberts Unit
Operator No.:
748093
Lease Number:
Well Number:
Total Vertical Depth:
Latitude:
Longitude:
Datum:
019212
1
11000
33.049990
-102.903464
NAD27
Purpose:
New Drill
Location:
Survey-Gibson, J H/Poole, J T; Block-D; Section-733
To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:
The interval from the land surface to a depth of 375 feet must be protected.
Note: Unless stated otherwise, this recommendation is intended to apply only to the subject well and not for area-wide use.
This recommendation is for normal drilling, production, and plugging operations only. It does not apply to saltwater disposal
operation into a nonproductive zone (RRC Form W-14).
This determination is based on information provided when the application was submitted on 08/30/2017. 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.gov
Rev. 02/2014
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APINa 42-501-36998
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
APPLICATION FOR PERMIT TO DRILL, RECOMPLETE, OR RE-ENTER
This facsimile W-l was generated electronically from data submitted to the RRC.
A certification of the automated data is available in the RRC's Austin office.
FORM W-l 07/2004
Drilling Permit #
839303
SWR Exception Case/Docket No.
Permit Status: Approved
B-3
1. RRC Operator No.
748093
2. Operator's Name (as shown on form P-5, Organization Report)
SANTA FE MIDSTREAM PERMIAN LLC
3. Operator Address (include street, city, state, zip):
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
4. Lease Name
RATTLESNAKE AGI
5. Well No.
1
GENERAL INFORMATION
6. Purpose of filing (mark ALL appropriate boxes): Ix] New Drill EH Recompletion EH Reclass EH Field Transfer EH Re-Enter
EH Amended EH Amended as Drilled (BHL) (Also File Form W-1D)
7. Wellbore Profile (mark ALL appropriate boxes): 0 Vertical EH Horizontal (Also File Form W-1H) EH Directional (Also File Form W-1D) EH Sidetrack
8. Total Depth
12000
9. Do you have the right to develop the [x] - | |
minerals under any right-of-way ?
10. Is this well subject to Statewide Rule 36 (hydrogen sulfide area)? IS Yes EH \0
SURFACE LOCATION AND ACREAGE INFORMATION
11. RRC District No.
8A
12. County I—, ,—, ,—, ,—¦
YOAKUM 13. Surface Location LXI Land 1—1 Bay/Estuary 1—1 Inland Waterway 1—1 Offshore
14. This well is to be located miles in a NW direction from DENVER CITY which is the nearest town in the county of the well site.
15. Section 16. Block 17. Survey 18. Abstract No.
733 D GIBSON, J H A-89
19. Distance to nearest lease line:
200 ft-
20. Number of contiguous acres in
lease, pooled unit, or unitized tract: 640
21. Lease ]
22. Survey
'erpendiculars: 200 ft from the NORTH line and 200 ft froi
nt
nt
ie WEST line.
PprppiiHii^iilars" 200 ft from the NORTH line and 200 ft froi
le WEST line.
23. Is this a pooled unit? EH Yes B No 24. Unitization Docket No:
25. Are you applying for Substandard Acreage Field? EH Yes (attach Form W-1A) S No
FIELD INFORMATION List all fields of anticipated completion including Wildcat. List one zone per line.
26. RRC
District No.
27. Field No.
28. Field Name (exactly as shown in RRC records)
29. Well Type
30. Completion Depth
31. Distance to Nearest
Well in this Reservoir
32. Number of Wells on
this lease in this
Reservoir
8A
95397001
WASSON
Injection Well
12000
0.00
1
8A
95399400
WASSON, NORTH (SAN ANDRES)
Injection Well
12000
0.00
1
BOTTOMHOLE LOCATION INFORMATION is required for DIRECTIONAL, HORIZONTAL, AND AMENDED AS DRILLED PERMIT APPLICATIONS
Remarks
[FILER Apr 16, 2018 5:16 PM]: Filing for an acid gas injection well.
Certificate:
I certify that information stated in this application is true and complete, to the
best of my knowledge.
Jessica Risien, Regulatory Compliance
Specialist Apr 25, 2018
Name of filer Date submitted
(281)8729300 jrisien@ntglobal.com
Phone E-mail Address (OPTIONAL)
RRC Use Only Data Validation Time Stamp: Apr 27, 2018 10:36 AM( As Approved' Version )
Page 1 of 1
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NOTE: Acreages shown hereon ere based on Information provided by others.
This plat represents a staked well location and does not represent a boundary survey.
The Information shown does not meet the current TBPLS minimum standards for boundary
surveys. Limited field measurements were acquired. Lease and tract line Information is
compiled from record information and additional sources.
NOTES:
1)
2)
3-J
ALL BEARINGS. DISTANCES ANO COORDINATES SHOWN
HEREON WERE DERIVED FROM <3. P S. OBSERVATIONS
CONVERTED TO THE TEXAS COORDINATE SYSTEM,
NORTH CENTRAL ZONE (NAD 1993). US FOOT AND ARE
REFERENCED TO THE LOCAL GNSS RTK NETWORK.
THE PROPOSED WELL LOCATION IS SITUATED N 37~W -
7.3 MILES FROM DENVER CITY, TX.
THE PROPOSED WELL LOCATION IS SITUATED SOW FROM
THE NSL AND 200 FROM THE WSL.
6
5°X'
rC-< liw
SECTION 704. BLOCK D
J. H. GIBSON SURVEY-
ABSTRACT NO. 1144
YOAKUM COUNTY. TX
704
733
RA TTLESMAKE AGf No.
(PROPOSED)
.0^
SURFACE L OCA T/ON
NAD 83, TX-NC, U.S. FT.
NORTH/NG/Y; 7093713.4ST
EASTING/X 619409-13"
LATITUDE (DDJ- 33.05134722°
LONGITUDE (DO)- -102.90450555*
NAD 27, TX-NC, US- FT,
NORTHfNG/Y: 546285.34*
EAST/NG/X; 344968.61'
LA TTTUDE (DO)- 33.05124473"
LONGITUDE (DO)- -102.90401331°
SURFACEELEVA T/ON- 3627.05-
732
*
83^8
2
5>^0
S
Af /=>&?AfMA/LLG
rtATTL£SA/j4/C£-s4G/A/o. 7
*/.M. G/&SOA/ SURWEK
SEGT/OA/ 733, &LOC/C0
yOAKt/AS GCHSA/TX TjEXAS
m Y aHcmws80i*a,7x:7B>
IhtebkityRk
i ] Positions, llc
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Railroad Commission of Texas
PERMIT TO DRILL, RE-COMPLETE, OR RE-ENTER ON REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
CONDITIONS AND INSTRUCTIONS
Permit Invalidation. It is the operator's responsibility to make sure that the permitted location complies with Commission density and
spacing rules in effect on the spud date. The permit becomes invalid automatically if, because of a field rule change or the drilling of another
well, the stated location is not in compliance with Commission field rules on the spud date. If this occurs, application for an exception to
Statewide Rules 37 and 38 must be made and a special permit granted prior to spudding. Failure to do so may result in an allowable not being
assigned and/or enforcement procedures being initiated.
Notice Requirements. Per H.B 630, signed May 8,2007, the operator is required to provide notice to the surface owner no later than the
15th business day after the Commission issues a permit to drill. Please refer to subchapter Q Sec. 91.751-91.755 of the Texas Natural
Resources Code for applicability.
Permit expiration. This permit expires two (2) years from the date of issuance shown on the original permit. The permit period will not
be extended.
Drilling Permit Number. The drilling permit number shown on the permit MUST be given as a reference with any notification to the
district (see below), correspondence, or application concerning this permit.
Rule 37 Exception Permits. This Statewide Rule 37 exception permit is granted under either provision Rule 37 (h)(2)(A) or 37(h)(2)(B).
Be advised that a permit granted under Rule 37(h)(2)(A), notice of application, is subject to the General Rules of Practice and Procedures
and if a protest is received under Section 1.3, "Filing of Documents," and/or Section 1.4, "Computation of Time," the permit may be deemed
invalid.
Before Drilling
Fresh Water Sand Protection. The operator must set and cement sufficient surface casing to protect all usable-quality water, as defined by
the Railroad Commission of Texas (RRC) Groundwater Advisory Unit (GWAU). Before drilling a well, the operator must obtain a letter from
the Railroad Commission of Texas stating the depth to which water needs protection, Write: Railroad Commission of Texas, Groundwater
Advisory Unit (GWAU), P.O. Box 12967, Austin, TX 78711-3087. File a copy of the letter with the appropriate district office.
Accessing the Well Site. If an OPERATOR, well equipment TRANSPORTER or WELL service provider must access the well site from a
roadway on the state highway system (Interstate, U.S. Highway, State Highway, Farm-to-Market Road, Ranch-to-Market Road, etc.), an
access permit is required from TxDOT. Permit applications are submitted to the respective TxDOT Area Office serving the county where the
well is located.
Water Transport to Well Site. If an operator intends to transport water to the well site through a temporary pipeline laid above
ground on the state's right-of-way, an additional TxDOT permit is required. Permit applications are submitted to the respective
TxDOT Area Office serving the county where the well is located.
^NOTIFICATION
The operator is REQUIRED to notify the district office when setting surface casing, intermediate casing, and production casing, or when
plugging a dry hole. The district office MUST also be notified if the operator intends to re-enter a plugged well or re-complete a well into a
different regulatory field. Time requirements are given below. The drilling permit number MUST be given with such notifications.
During Drilling
Permit at Drilling Site : A copy of the Form W-l Drilling Permit Application, the location plat, a copy of Statewide Rule 13
alternate surface casing setting depth approval from the district office, if applicable, and this drilling permit must be kept at the
permitted well site throughout drilling operations.
*Notification of Setting Casing : The operator MUST call in notification to the appropriate district office (phone number shown the
on permit) a minimum of eight (8) hours prior to the setting of surface casing, intermediate casing, AND production casing. The
individual giving notification MUST be able to advise the district office of the drilling permit number.
*Notification of Re-completion/Re-entry : The operator MUST call in notification to the appropriate district office (phone number
shown on permit) a minimum of eight (8) hours prior to the initiation of drilling or re-completion operations. The individual giving
notification MUST be able to advise the district office of the drilling permit number.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 1 of 5
-------
Completion and Plugging Reports
Hydraulic Fracture Stimulation using Diesel Fuel: Most operators in Texas do not use diesel fuel in hydraulic fracturing fluids.
Section 322 of the Energy Policy Act of 2005 amended the Underground Injection Control (UIC) portion of the federal Safe Drinking Water
Act (42 USC 300h(d)) to define "underground Injection" to EXCLUDE " ...the underground injection of fluids or propping agents (other
than dieselfluels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities." (italic and underlining
added.) Therefore, hydraulic fracturing may be subject to regulation under the federal UIC regulations if diesel fuel is injected or used as a
propping agent. EPA defined "diesel fuel" using the following five (5) Chemical Abstract Service numbers: 68334-30-5 Primary Name: Fuels,
diesel; 68476-34-6 Primary Name: Fuels, diesel, No. 2; 68476-30-2 Primary Name: Fuel oil No. 2; 68476-31-3 Primary Nmae: Fuel oil, No.
4; and 8008-20-6 Primary Name: Kerosene. As a result, an injection well permit would be required before performing hydraulic fracture
stimulation using diesel fuel as defined by EPA on any well in Texas. Hydraulic fracture stimulation using diesel fuel as defined by EPA on a
well in Texas without an injection well permit could result in enforcement action.
Producing Well: Statewide Rule 16 states that the operator of a well shall file with the Commission the appropriate completion report
within thirty (30) days after completion of the well or within ninety (90) days after the date on which the drilling operation is completed,
whichever is earlier. Completion of the well in a field authorized by this permit voids the permit for all other fields included in the permit
unless the operator indicates on the initial completion report that the well is to be a dual or multiple completion and promptly submits an
application for multiple completion. All zones are required to be completed before the expiration date on the existing permit. Statewide Rule
40(d) requires that upon successful completion of a well in the same reservoir as any other well previously assigned the same acreage,
proration plats and P-15s (if required) must be submitted with no double assignment of acreage.
Dry or Noncommercial Hole : Statewide Rule 14(b)(2) prohibits suspension of operations on each dry or non-commercial well without
plugging unless the hole is cased and the casing is cemented in compliance with Commission rules. If properly cased, Statewide Rule 14(b)(2)
requires that plugging operations must begin within a period of one (1) year after drilling or operations have ceased. Plugging operations must
proceed with due diligence until completed. An extension to the one-year plugging requirement may be granted under the provisions stated in
Statewide Rule 14(b)(2).
Intention to Plug : The operator must file a Form W-3 A (Notice of Intention to Plug and Abandon) with the district office at least five (5)
days prior to beginning plugging operations. If, however, a drilling rig is already at work on location and ready to begin plugging operations,
the district director or the director's delegate may waive this requirement upon request, and verbally approve the proposed plugging
procedures.
*Notification of Plugging a Dry Hole : The operator MUST call in notification to the appropriate district office (phone number shown on
permit) a minimum of four (4) hours prior to beginning plugging operations. The individual giving the notification MUST be able to advise
the district office of the drilling permit number and all water protection depths for that location as stated in the Texas Commission on
Environmental Quality letter.
DIRECT INQUIRIES TO: DRILLING PERMIT SECTION, OIL AND GAS DIVISION
PHONE
(512) 463-6751
MAIL:
PO Box 12967
Austin, Texas, 78711-2967
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 2 of 5
-------
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
PERMIT TO DRILL, DEEPEN, PLUG BACK, OR RE-ENTER ON A REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
PERMIT NUMBER
839303
DATE PERMIT ISSUED OR AMENDED
04/27/2018
DISTRICT
8A
API NUMBER
42-501-36998
FORM W-l RECEIVED
04/25/2018
COUNTY
YOAKUM
TYPE OF OPERATION
New Drill
WELLBORE PROFILE(S)
Vertical
ACRES
640.0
OPERATOR 748093
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
NOTICE
This permit and any allowable assigned may
be revoked if payment for fee(s) submitted to
the Commission is not honored.
District Office Telephone No:
(806) 698-6509
LEASE NAME
RATTLESNAKE AGI
WELL NUMBER
1
LOCATION
7.3 miles NW direction from DENVER CITY
TOTAL DEPTH
12000
Section, Block and/or
SECTION 733 BLOCK D ABSTRACT 89
SURVEY GIBSON, J H
DISTANCE TO SURVEY LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST LEASE LINE
200.0
DISTANCE TO LEASE LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST WELL ON LEASE
See FIELD(s) Below
FIELD(s) and LIMITATIONS:
* SEE FIELD DISTRICT FOR REPORTING PURPOSES *
FIELDNAME ACRES DEPTH WELL# DIST
LEASE NAME NEAREST LEASE NEAREST WELL
WASSON "640!0 12000 1 8A
RATTLESNAKE AGI 200 0 0.0
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
WASSON, NORTH (SAN ANDRES) "64o!o 12000 1 8A
RATTLESNAKE AGI 200.0 0.0
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 3 of 5
-------
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
THE FOLLOWING RESTRICTIONS APPLY TO ALL FIELDS
This well shall be completed and produced in compliance with applicable special field or statewide spacing and density rules. If this well is
to be used for brine mining, underground storage of liquid hydrocarbons in salt formations, or underground storage of gas in salt formations,
a permit for that specific purpose must be obtained from Environmental Services prior to construction, including drilling, of the well in
accordance with Statewide Rules 81, 95, and 97.
This well must comply to the new SWR 3.13 requirements concerning the isolation of any potential flow zones and zones with corrosive
formation fluids. See approved permit for those formations that have been identified for the county in which you are drilling the well in.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 4 of 5
-------
Railroad Commission of Texas
Oil and Gas Division
SWR #13 Formation Data
YOAKUM (501) COUNTY
l-'oniiiilioii
Koniiirks
Order
I.ITcc(i\c
Diilo
RED BED-SANTA ROSA
1
01/01/2014
YATES
2
01/01/2014
SAN ANDRES
high flows, H2S, corrosive
3
01/01/2014
GLORIETA
4
01/01/2014
CLEARFORK
Active C02 Flood
5
01/01/2014
WICHITA
6
01/01/2014
LEONARD
7
01/01/2014
WOLFCAMP
8
01/01/2014
PENNSYLVANIAN
9
01/01/2014
STRAWN
10
01/01/2014
MISSISSIPPIAN
11
01/01/2014
DEVONIAN
12
01/01/2014
DEVONIAN-SILURIAN
13
01/01/2014
The above list may not be all inclusive, and may also include formations that do not intersect all wellbores. The listing order of the Formation
information reflects the general stratigraphic order and relative geologic age. This is a dynamic list subject to updates and revisions. It is the
operator's responsibility to make sure that at the time of spudding the well the most current list is being referenced. Refer to the RRC website
at the following address for the most recent information, http://www.rrc.texas.gov/oil-gas/compliance-enforcement/rule-13-geologic-
formation-info
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 5 of 5
-------
B-4
RAILROAD COMMISSION OF TEXAS Form G-1
1701 N. Congress Status: Approved
P.O. Box 12967 Date: 07/25/2019
Austin, Texas 78701-2967 Tracking No.: 205926
GAS WELL BACK PRESSURE TEST, COMPLETION OR RECOMPLETION REPORT, AND LOG
OPERATOR INFORMATION
Operator Name: santa fe midstream permian llc Operator No.: 748093
Operator Address: 5830 granite pkwy ste 1025 plano, tx 75024-0000
WELL INFORMATION
API No.: 42-501-36998
County: YOAKUM
Well No.: 1
RRC District No.: 8A
Lease Name: RATTLESNAKE AG I
Field Name: WASSON
RRC Gas ID No.: 286838
Field No.: 95397001
Location: Section: 733, Block: D, Survey: GIBSON, J H, Abstract: 89
Latitude:
Longitude:
This well is located 7.3 miles in a nw
direction from Denver city,
which is the nearest town in the county.
FILING INFORMATION
Purpose of filing: Well Record Only
Type of completion: New Well
Well Type: Active UIC
Completion or Recompletion Date: 08/31/2018
Type of Permit
Date Permit No.
Permit to Drill, Plug Back, or Deepen
04/27/2018 839303
Rule 37 Exception
Fluid Injection Permit
O&G Waste Disposal Permit
11/14/2018 15848
Other:
COMPLETION INFORMATION
ISpud date: 07/16/2018
Date of first production after rig released: 08/31/2018 I
Date plug back, deepening, recompletion, or Date plug back, deepening, recompletion, or
drilling operation commenced: 07/16/2018
drilling operation ended: 08/31/2018
Number of producing wells on this lease in
Distance to nearest well in lease &
this field (reservoir) including this well:
1 reservoir (ft.): 0.0
Total number of acres in lease: 640.00
Elevation (ft.): 3627 GR
Total depth TVD (ft.): 11980
Total depth MD (ft.):
Plug back depth TVD (ft.): 11980
Plug back depth MD (ft.):
Was directional survey made other than
Rotation time within surface casing (hours): 72.0
inclination (Form W-12)? Yes
Is Cementing Affidavit (Form W-15) attached? Yes
Recompletion or reclass? No
Multiple completion? No
Type(s) of electric or other log(s) run: Combo of Induction/Neutron/Density/Sonic
Electric Log Other Description:
Location of well, relative to nearest lease boundaries Off Lease: No
of lease on which this well is located:
200.0 Feet from the North Line and
200 0 Feet from the West Line of the
rattlesnake agi Lease.
FORMER FIELD (WITH RESERVOIR) & GAS ID OR OIL LEASE NO.
Field & Reservoir
Gas ID or Oil Lease No. Well No. Prior Service Type
Page 1 of4
-------
G1: N/A
PACKET: N/A
FOR NEW DRILL OR RE-ENTRY, SURFACE CASING DEPTH DETERMINED BY:
GAU Groundwater Protection Determination Depth (ft.): 2025.0 Date: 01/12/2018
SWR 13 Exception Depth (ft.):
GAS MEASUREMENT DATA
I Date of test: Gas measurement method(s):
Gas production during test (MCF):
Was the well preflowed for 48 hours? No
Orif. or 24 hr. Coeff.
Run Line Choke Orif. Or Choke Static Pm or Diff
No. size Size (in.) (in.) Choke (in.) (hw)
Flow
Temp Temp. Gravity
(°F) (l-tt) (hg)
Compress
(Fpv)
Volume
(MCF/day)
N/A
FIELD DATA AND PRESSURE CALCULATIONS
Gravity (dry gas):
Gas-Liquid Hydro Ratio (CF/Bbl):
Avg. shut in temp. (°F):
Gravity (liquid hydrocarbons) (Deg. API):
Gravity (mixture): Gmix=
Bottom hole temp, and depth: °F@ ft
Run No. Time of Run (Min.)
Choke Size (in.) Wellhead Pressure (PSIA) Wellhead Flow Temp (°F )
N/A
CASING RECORD
Casing Hole Setting Multi - Multi - Cement Slurry Top of TOC
Type of
Size
Size
Depth Stage Tool Stage Shoe Cement Amount Volume Cement Determined
Row Casing
(in.)
(in.)
(ft.)
Depth (ft.) Depth (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
1 Surface
13 3/8
17 1/2
504
c
510
687.5
0
Circulated to Surface
3 Intermediate
9 5/8
12 1/4
5498
5498
c
485
797.0
4275
Circulated to Surface
2 Intermediate
13 3/8
17 1/2
5498
4275
c
1650
3045.0
0
Circulated to Surface
6 Conventional Production
7
8 3/4
11023
WELL
60
337.0
9575
Calculation
LOCK
5 Conventional Production
7
8 3/4
11023
5591
PREM
380
906.5
0
Circulated to Surface
PLUS
4 Conventional Production
7
8 3/4
11023
9575
PREM
380
906.5
5591
Calculation
PLUS
LINER RECORD
Cement
Slurry
Top of
TOC
Liner Hole
Liner
Liner
Cement
Amount
Volume
Cement
Determined
Row Size (in.) Size (in.)
Top (ft.)
Bottom (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
N/A
TUBING RECORD
Row
Size (in.)
Depth Size (ft.)
Packer Depth (ft.)/Type
1
3 1/2
10966
10966 / HALLIBURTON
BWD
PRODUCING/INJECTION/DISPOSAL INTERVAL
Row
Open hole?
From (ft.)
To (ft.)
1
Yes
L 11025
11980
Page 2 of4
-------
ACID, FRACTURE, CEMENT SQUEEZE,
CAST IRON BRIDGE PLUG, RETAINER, ETC.
Was hydraulic fracturing treatment performed? No
Is well equipped with a downhole actuation
sleeve? No
If yes, actuation pressure (PSIG):
Production casing test pressure (PSIG) prior to
Actual maximum pressure (PSIG) during hydraulic
hydraulic fracturing treatment:
fracturing:
Has the hydraulic fracturing fluid disclosure been
reported to FracFocus disclosure registry (SWR29)?
No
Row Type of Operation Amount and Kind of Material Used Depth Interval (ft.)
N/A
FORMATION RECORD
Is formation
Formations Encountered Depth TVD (ft.) Depth MP (ft.) isolated? Remarks
YATES
Yes
3019.0
Yes
SAN ANDRES - HIGH FLOWS, H2S,
Yes
4465.0
Yes
CORROSIVE
GLORIETA
Yes
6316.0
Yes
CLEARFORK - ACTIVE C02 FLOOD
Yes
6492.0
Yes
WICHITA
Yes
8628.0
Yes
UPPER WOLFCAMP
Yes
9239.0
Yes
STRAWN
Yes
10030.0
Yes
ATOKA
Yes
10230.0
Yes
WOODFORD
Yes
10973.0
Yes
DEVONIAN
Yes
11036.0
No
DISPOSAL
WRISTEN
Yes
11268.0
No
DISPOSAL
FUSSELMAN
Yes
11538.0
No
DISPOSAL
MONTOYA
Yes
11974.0
No
DISPOSAL
RED BED-SANTA ROSA
No
No
NOT IN AREA
LEONARD
No
No
NOT IN AREA
WOLFCAMP
No
No
NOT IN AREA
PENNSYLVANIAN
No
No
NOT IN AREA
STRAWN
No
No
NOT IN AREA
MISSISSIPPIAN
No
No
NOT IN AREA
Do the producing interval of this well produce H2S with a concentration in excess of 100 ppm (SWR 36)? No
s the completion being downhole commingled (SWR 10)? No
REMARKS
NEW WELL PUTTING ON SCHEDULE.
Page 3 of4
-------
OPERATOR'S CERTIFICATION
Printed Name: Karen Zornes
Title:
Telephone No.: (281) 872-9300
Date Certified: 06/25/2019
Page 4 of4
-------
APPENDIX C - GAS COMPOSITION
-------
C-1
1 rv » n,,
natural Gas Analysis
www.permianls.com
575.397.3713 2609 W Marland HobbS NM 88240
11093G
30/30 Acid Gas
Sample Point Code
Sample Point Name
C6+ Gas Analysis Report
30/30 Acid Gas
Sample Point Location
Laboratory Services
Date Sampled
2021048523
1781
E Benavides - Spot
Source Laboratory
Lab File No
Container Identity
Sampler
USA
USA
USA
Texas
District
Area Name
Field Name
Facility Name
Nov 16, 2021
Nov 16, 2021
Nov 19, 2021 09:59
Nov 19, 2021
Date Effective
System Administrator
Ambient Temp (°F)
Flow Rate (Mcf)
Analyst
Date Received
21 @ 129
Press PSI @ Temp °F
Source Conditions
Date Reported
Stakeholder Midstream
30/30
Operator
Lab Source Description
Component
Normalized
Mol %
Un-Normalized
Mol %
GPM
H2S (H2S)
9.2000
9.2
Nitrogen (N2)
0.0000
0
C02 (C02)
89.6780
98.775
Methane (CI)
0.3030
0.331
Ethane (C2)
0.0580
0.063
0.0150
Propane (C3)
0.1080
0.118
0.0300
I-Butane (IC4)
0.0000
0
0.0000
N-Butane (NC4)
0.0250
0.027
0.0080
I-Pentane (IC5)
0.0000
0
0.0000
N-Pentane (NC5)
0.0000
0
0.0000
Hexanes Plus (C6+)
0.6280
0.686
0.2710
TOTAL
100.0000
109.2000
0.3240
Method(s): Gas C6+ - GPA 2261, Extended Gas - GPA 2286, Calculations - GPA 2172
Analyzer Information
Device Type: Gas Chromatograph Device Make: Shimadzu
Device Model: GC-2014 Last Cal Date: Nov 14, 2021
Gross Heating Values (Real, BTU/ft3)
14.696 PSI @ 60.00 A°F 14.65 PSI @ 60.00 A°F
Dry Saturated Dry Saturated
98.7 98.00 98.4 97.7
Calculated Total Sample Properties
GPA2145-16 Calculated at Contract Conditions
Relative Density Real Relative Density Ideal
1.5042 1.4956
Molecular Weight
43.3157
C6 - 60.000%
C6+ Group Properties
Assumed Composition
C7 - 30.000%
C8 - 10.000%
Field H2S
92000 PPM
PROTREND STATUS: DATA SOURCE:
Passed By Validator on Nov 21, 2021 Imported
PASSED BY VALIDATOR REASON:
Close enough to be considered reasonable.
VALIDATOR:
Dustin Armstrong
VALIDATOR COMMENTS:
OK
Nov 22, 2021 7:57 a
Powered By ProTrend -www.criticalcontrol.com
Page 1 of 1
-------
APPENDIX D - MONITORING AREA MAPS
APPENDIX D-l: MMA MAP
APPENDIX D-2: AMA MAP
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
1560
-------
APPENDIX E - FACILITY SAFETY PLOT PLANS
-------
PLANT NORTH
LEGEND
•
FIRE EXTINGUISHER
~
SCBA/ESCAPE PACK
~
WIND SOCK
®
LEL/H2S MONITOR
ESD BUTTON
H
STROBE LIGHTS
HORN
E-1
r
i| 1 | |—1 l\ 71 1 k 1 A 1 \ W—1 / \ 1 1
—\
JKI 1 IMINAKY 1 ()l>
pn/ic\A/
0
NO.
05/11 / 22
DATE
INITIAL RELEASE K C V 1 C V V
REVISION DESCRIPTION
KLD
BY
BEC
FCE
JB
CLIENT
CHAR1S ENGINEERING. LLC
"IX ENG. FIRM NO. F-1B8B4
MIDLAND. IX
STAKEHOLDER
MIDSTREAM
CLIENT ;
PROJECT ;
TITLE :
STAKEHOLDER MIDSTREAM
30-30 GAS PLANT
SAFETY EQUIPMENT PLOT PLAN
1" = 50'—0"
DATE
5/11/22
ME—PLNP—AOOO—0004
A
-------
APPENDIX F - MMA/AMA REVIEW MAPS
APPENDIX F-l: PLUME BOUNDARY AT END OF INJECTION, STABILIZED PLUME BOUNDARY AND MAXIMUM
MONITORING AREA MAP
APPENDIX F-2: ACTIVE MONITORING AREA MAP
APPENDIX F-3: OIL AND GAS WELLS WITHIN THE MMA MAP
APPENDIX F-4: OIL AND GAS WELLS WITHIN THE MMA LIST
APPENDIX F-5: INJECTION INTERVAL PENETRATING WELLS WITHIN THE MMA MAP
APPENDIX F-6: GROUNDWATER WELLS WITHIN THE MMA
APPENDIX F-7: WELLBORE SCHEMATICS FOR INJECTION INTERVAL PENETRATING WELLS
-------
A-1143
A-545
A-1866
A-572
A-£ 58
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
A-1314
A-549
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
J Plume Boundary at End of Injection
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-2
Rattlesnake AGI No. 1 SHL
1 Active Monitoring Area Boundary
1 9-Year Plume
J Plume Boundary at End of Injection
Abstract
Note: All coordinates shown are in NAD83 (DD).
MAP EXTENT
~
-------
A-1866
A-1314
iiiiiiiiij
36998 l\
RATTLESNAKE AGI NO
33.0513499,1
-102.90450576
00000
32541
00261
32531
00000
iiiiiiiiii
00000"
00000
00262
000
\ 00645 •
00050
00643s
00644
00000
33349.
33530
00057
33173
32702
34984\
32065
00059
33172
33531
A-1484
33531'
32703
33351
32064
,00061
00000
00060
00058
32704
33 no 3
00065
00068
00064
^067 ^
32945
32975
32077
32075
: 30600
32076
36156
00267
00266
00066 3271 i
00063
02992
02991
02990
02989 35820
A-1816
34878
32070
36155
36151 30604 35791 30602
30606
JO fyy
36152
35821
30630
32072
36153
30601
30605
35794
35793 30598
36150
30603
36048
36154
35180
35703
35701
35705
30000
=3058.4;
32270
33065
1:34099;
00755
30583
30629
35961'
34797
56428 00000
• °l
36098
-34023 •
00768J
34124
30580
36327
33843
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
+ Rattlesnake AC I No. 1 SHL
| ~ ~ ™ 1/2-Mile Buffer from Max. Plume Extent (MMA)
I ~ Z Z Z Combined Maximum Plume Extent
1 Stabilized Plume
I ~ ~ ~ Z Plume Boundary at End of Injection
Abstract
Lateral (21)
API (42-501-...) SHL Status - Type (Count)
O Horizontal Surface Location (21)
• Active - Oil (93)
Active - Injection/Disposal (21)
•» Active - Injection/Disposal from Oil (22)
X Plugged - Oil (69)
^ Plugged - Gas (1)
Plugged- Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal (3)
TA - Injection/Disposal from Oil (7)
"0" Dry Hole (6)
o Permitted Location (2)
0 Canceled/Abandoned Location (6)
X Expired Permit (7)
API (42-501-...) BHL Status - Type (Count)
• Active - Oil (11)
•A Active - Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal from Oil (1)
o Permitted Location (4)
X Expired Permit (3)
Sou rce:
1.) Oil/Cas Well SHL Data: DI-2022
2.) Oil/Cas Well BHL Data: DI-2022
3.) Oil/Cas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD). *
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
1
A-1531
A-1064
A-87
A-1483
A-1641
A-499
VI55 !
i .-1777
A
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
F-4
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101829
DENVER UNIT
2215W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5300
5300
2215W
4250101835
DENVER UNIT
2207
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5185
5185
2207
4250130914
DENVER UNIT
2222
OCCIDENTAL PERMIAN LTD.
Active - Oil
2222
4250101832
DENVER UNIT
2201W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5190
5190
2201W
4250101826
DENVER UNIT
2203
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2203
4250101319
ROBERTS UNIT
4532W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5200
5200
4532W
4250130629
ROBERTS UNIT
4535
APACHE CORPORATION
Active - Oil
5280
5280
4535
4250130583
ROBERTS UNIT
4525
APACHE CORPORATION
Active - Oil
5286
5286
4525
4250101318
ROBERTS UNIT
4541
APACHE CORPORATION
TA - Injection/Disposal from Oil
5240
5240
4541
4250101889
ROBERTS UNIT
3614
APACHE CORPORATION
Plugged - Oil
5180
5180
3614
4250130598
Roberts Unit
3647
APACHE CORPORATION
Plugged - Oil
5281
5281
3647
4250130603
ROBERTS UNIT
3626
APACHE CORPORATION
Plugged - Oil
5289
5289
3626
4250102992
ROBERTS UNIT
3612W
APACHE CORPORATION
Plugged - Oil
5226
5226
3612W
4250100066
ROBERTS UNIT
3532
APACHE CORPORATION
Plugged - Oil
5231
5231
3532
4250101886
ROBERTS UNIT
3631
APACHE CORPORATION
Plugged - Oil
3631
4250101885
ROBERTS UNIT
3641
APACHE CORPORATION
Plugged - Oil
5212
5212
3641
4250100068
ROBERTS UNIT
3521
APACHE CORPORATION
Plugged - Oil
5225
5225
3521
4250100064
ROBERTS UNIT
3541
APACHE CORPORATION
Plugged - Oil
5264
5264
3541
4250102014
ROBERTS UNIT
2443
APACHE CORPORATION
Plugged - Oil
5226
5226
2443
4250100050
ROBERTS UNIT
1654
APACHE CORPORATION
Plugged - Oil
5198
5198
1654
4250133531
ROBERTS UNIT
2443A
Active - Injection/Disposal
5325
5325
2443A
4250133502
ROBERTS UNIT
2527A
Plugged - Oil
5308
5308
2527A
4250100000
C. A. ELLIOTT
6
AMERICAN LIBERTY OIL CO
Plugged - Oil
5229
5229
6
4250100000
C. A. ELLIOTT
7
AMERICAN LIBERTY AND ATLANTIC
Active - Oil
5182
5182
7
4250100000
GEO CLEVELAND
1
DELFERN OIL CO
Dry Hole
5071
5071
1
4250100000
JAMES H. LYNN
1614
AMERICAN LIBERTY
Active - Oil
5169
5169
1614
4250100000
J. H. LYNN
1634
AMERICAN LIBERTY
Active - Oil
5160
5160
1634
4250100000
A. T. MORRIS
1
ATLANTIC
Active - Oil
5235
5235
1
4250100000
A. T. MORRIS
2
AMERICAN LIBERTY OIL CO
Plugged - Oil
5179
5179
2
4250100000
W.J. CARPENTER
1642
AMERICAN LIBERTY OIL COMPANY
Plugged - Oil
5183
5183
1642
4250100000
E.S.SMITH
1
CREAT WESTERN FROD
Dry Hole
5216
5216
1
4250130607
ROBERTS UNIT
3546
Active - Oil
3546
4250135958
DENVER UNIT
2247
OCCIDENTAL PERMIAN LTD.
Active - Oil
2333
2333
2247
4250131542
DENVER UNIT
2229
SHELL OIL COMPANY
Dry Hole
2409
2409
2229
4250101320
ROBERTS UNIT
4543
APACHE CORPORATION
Active - Injection/Disposal from Oil
5120
5120
4543
4250137301
MILLER
8H
AMTEX ENERGY, INC.
Active - Oil
5157
5157
8H
4250137304
MILLER 732 C
10H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
10H
4250137305
MILLER 732 D
11H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
11H
4250101888
ROBERTS UNIT
3634W
APACHE CORPORATION
Plugged - Oil
5160
5160
3634W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101031
ROBERTS UNIT
3534W
APACHE CORPORATION
Plugged - Oil
5164
5164
3534W
4250101828
DENVER UNIT
2208
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5170
5170
2208
4250101032
ROBERTS UNIT
3544
APACHE CORPORATION
Plugged - Oil
5170
5170
3544
4250101841
DENVER UNIT
2206
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5177
5177
2206
4250101842
ROBERTS UNIT
3643W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3643W
4250101035
ROBERTS UNIT
3533W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3533W
4250132704
ROBERTS UNIT
2615
APACHE CORPORATION
Active - Oil
5180
5180
2615
4250100261
ROBERTS UNIT
1643W
APACHE CORPORATION
Plugged - Oil
5180
5180
1643W
4250101323
ROBERTS UNIT
4542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
4542W
4250102989
ROBERTS UNIT
3642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
3642W
4250102991
ROBERTS UNIT
3622W
APACHE CORPORATION
Plugged - Oil
5185
5185
3622W
4250132417
MILLER
3
AMTEX ENERGY, INC.
Active - Oil
5186
5186
3
4250101025
ROBERTS UNIT
2613W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5188
5188
2613W
4250101887
ROBERTS UNIT
3644
APACHE CORPORATION
Active - Injection/Disposal from Oil
5189
5189
3644
4250101830
DENVER UNIT
2214WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5190
5190
2214WC
4250101103
ROBERTS UNIT
3621
APACHE CORPORATION
Plugged - Oil
5190
5190
3621
4250101024
ROBERTS UNIT
2623
APACHE CORPORATION
Plugged - Oil
5190
5190
2623
4250101023
ROBERTS UNIT
2622W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5190
5190
2622W
4250101022
ROBERTS UNIT
2632
APACHE CORPORATION
Active - Oil
5190
5190
2632
4250101019
ROBERTS UNIT
2621
APACHE CORPORATION
Active - Oil
5190
5190
2621
4250101030
ROBERTS UNIT
3524W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5193
5193
3524W
4250101829
DENVER UNIT
2205
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5195
5195
2205
4250101836
DENVER UNIT
2213WC
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5200
5200
2213WC
4250101833
DENVER UNIT
2202WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5200
5200
2202WC
4250134099
DENVER UNIT
2239WC
OCCIDENTAL PERMIAN LTD.
Dry Hole
5200
5200
2239WC
4250132717
ROBERTS UNIT
3531A
APACHE CORPORATION
TA - Injection/Disposal
5200
5200
3531A
4250101014
ROBERTS UNIT
2624W
APACHE CORPORATION
Plugged - Oil
5200
5200
2624W
4250101028
ROBERTS UNIT
3523
APACHE CORPORATION
Plugged - Oil
5205
5205
3523
4250101102
ROBERTS UNIT
3611
APACHE CORPORATION
Plugged - Oil
5206
5206
3611
4250101827
DENVER UNIT
2209W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5210
5210
2209W
4250101015
2643
TEXACO INCORPORATED
Active - Injection/Disposal from Oil
5210
5210
2643
4250100266
ROBERTS UNIT
3522W
APACHE CORPORATION
Plugged - Oil
5211
5211
3522W
4250132632
MILLER
5
AMTEX ENERGY, INC.
Active - Oil
5213
5213
5
4250100057
ROBERTS UNIT
2512W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5213
5213
2512W
4250101890
ROBERTS UNIT
3624W
APACHE CORPORATION
Plugged - Oil
5214
5214
3624W
4250101033
ROBERTS UNIT
3543W
APACHE CORPORATION
Plugged - Oil
5215
5215
3543W
4250101012
ROBERTS UNIT
2634W
APACHE CORPORATION
Plugged- Injection/Disposal from Oil
5215
5215
2634W
4250101734
ROBERTS UNIT
2442
APACHE CORPORATION
Plugged - Oil
5215
5215
2442
4250101020
ROBERTS UNIT
2611W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5215
5215
2611W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100067
ROBERTS UNIT
3531
APACHE CORPORATION
Plugged - Oil
5216
5216
3531
4250101013
ROBERTS UNIT
2614W
APACHE CORPORATION
Plugged - Oil
5216
5216
2614W
4250101844
ROBERTS UNIT
3623W
APACHE CORPORATION
Plugged - Oil
5217
5217
3623W
4250131869
ROBERTS UNIT
A3534W
APACHE CORPORATION
Plugged - Oil
5220
5220
A3534W
4250102990
ROBERTS UNIT
3632W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5220
5220
3632W
4250100262
ROBERTS UNIT
1644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5220
5220
1644W
4250132858
DENVER UNIT
2235
OCCIDENTAL PERMIAN LTD.
Shut-In - Oil
5225
5225
2235
4250100058
ROBERTS UNIT
2544W
APACHE CORPORATION
Plugged - Oil
5225
5225
2544W
4250130584
ROBERTS UNIT
4520
APACHE CORPORATION
Active - Oil
5230
5230
4520
4250130630
ROBERTS UNIT
3535
APACHE CORPORATION
Active - Oil
5230
5230
3535
4250100063
ROBERTS UNIT
3542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5230
5230
3542W
4250132076
ROBERTS UNIT
3627
APACHE CORPORATION
Active - Oil
5230
5230
3627
4250100267
ROBERTS UNIT
3512W
APACHE CORPORATION
Plugged - Oil
5233
5233
3512W
4250101016
ROBERTS UNIT
2642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5234
5234
2642W
4250134716
DENVER UNIT
2242
OCCIDENTAL PERMIAN LTD.
Active - Oil
5236
5236
2242
4250100061
ROBERTS UNIT
2524W
APACHE CORPORATION
Plugged - Oil
5238
5238
2524W
4250101021
ROBERTS UNIT
2633
APACHE CORPORATION
Plugged - Oil
5240
5240
2633
4250101011
ROBERTS UNIT
2644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5241
5241
2644W
4250132541
FUTCH
1
AMTEX ENERGY, INC.
Active - Oil
5244
5244
1
4250101026
ROBERTS UNIT
2612W
APACHE CORPORATION
Plugged - Oil
5245
5245
2612W
4250100059
ROBERTS UNIT
2513W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5246
5246
2513W
4250132531
MILLER
4
AMTEX ENERGY, INC.
Plugged - Oil
5248
5248
4
4250132687
ROBERTS UNIT
2635
APACHE CORPORATION
Plugged - Oil
5248
5248
2635
4250131656
DENVER UNIT
2232WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2232WC
4250131791
DENVER UNIT
2231
SHELL OIL COMPANY
Canceled/Abandoned Location
5250
5250
2231
4250134118
DENVER UNIT
2238
OCCIDENTAL PERMIAN LTD.
Active - Oil
5250
5250
2238
4250101342
ROBERTS UNIT
APACHE CORPORATION
Plugged - Gas
5250
5250
4250132269
ROBERTS UNIT
3601
APACHE CORPORATION
Plugged - Oil
5250
5250
3601
4250101843
ROBERTS UNIT
3633W
APACHE CORPORATION
Plugged - Oil
5250
5250
3633W
4250130608
ROBERTS UNIT
3545
APACHE CORPORATION
Active - Oil
5250
5250
3545
4250132077
ROBERTS UNIT
3617
APACHE CORPORATION
Active - Oil
5250
5250
3617
4250134963
DENVER UNIT
2244WC
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal
5251
5251
2244WC
4250100060
ROBERTS UNIT
2514
APACHE CORPORATION
Plugged - Oil
5251
5251
2514
4250101459
DENVER UNIT
2211
OCCIDENTAL PERMIAN LTD.
Active - Oil
5252
5252
2211
4250132521
DENVER UNIT
2233W
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal from Oil
5253
5253
2233W
4250135211
DENVER UNIT
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5253
5253
2241
4250101837
DENVER UNIT
2212W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5255
5255
2212W
4250132793
MILLER
6
AMTEX ENERGY, INC.
Active - Oil
5258
5258
6
4250132356
MILLER
1
AMTEX ENERGY, INC.
Active - Oil
5260
5260
1
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101017
ROBERTS UNIT
2641
APACHE CORPORATION
Active - Oil
5260
5260
2641
4250101825
DENVER UNIT
2204W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5264
5264
2204W
4250132416
MILLER
2
AMTEX ENERGY, INC.
Active - Oil
5269
5269
2
4250100065
ROBERTS UNIT
3511W
APACHE CORPORATION
Plugged - Oil
5270
5270
3511W
4250101018
ROBERTS UNIT
2631
APACHE CORPORATION
Active - Oil
5270
5270
2631
4250130600
ROBERTS UNIT
3645
APACHE CORPORATION
Active - Oil
5273
5273
3645
4250130580
ROBERTS UNIT
4536
APACHE CORPORATION
Active - Oil
5279
5279
4536
4250130599
ROBERTS UNIT
3646
APACHE CORPORATION
Active - Oil
5279
5279
3646
4250130602
ROBERTS UNIT
3635
APACHE CORPORATION
Active - Oil
5283
5283
3635
4250132997
DENVER UNIT
2208WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5284
5284
2208WC
4250130601
ROBERTS UNIT
3636
APACHE CORPORATION
Active - Oil
5286
5286
3636
4250132174
SHEPHERD
1
YOUNG, MARSHALL R., OIL CO.
Dry Hole
5286
5286
1
4250130604
ROBERTS UNIT
3625
APACHE CORPORATION
Active - Oil
5287
5287
3625
4250130912
DENVER UNIT
2224
OCCIDENTAL PERMIAN LTD.
Active - Oil
5288
5288
2224
4250130911
DENVER UNIT
2225
OCCIDENTAL PERMIAN LTD.
Active - Oil
5290
5290
2225
4250130609
ROBERTS UNIT
4530
APACHE CORPORATION
Active - Oil
5291
5291
4530
4250130605
ROBERTS UNIT
3616
APACHE CORPORATION
Plugged - Oil
5291
5291
3616
4250130606
ROBERTS UNIT
3615
APACHE CORPORATION
Active - Oil
5293
5293
3615
4250133172
ROBERTS UNIT
2523
CONOCOPHILLIPS COMPANY
Plugged - Oil
5295
5295
2523
4250132739
CLEVELAND
1
HIGHLAND PRODUCTION COMPANY
Plugged - Oil
5300
5300
1
4250133064
DENVER UNIT
2238
SHELL WESTERN E&P INC.
Canceled/Abandoned Location
5300
5300
2238
4250132927
DENVER UNIT
2236
OCCIDENTAL PERMIAN LTD.
Active - Oil
5300
5300
2236
4250133065
DENVER UNIT
2237
SHELL WESTERN E&P INC.
Expired Permit
5300
5300
2237
4250132270
ROBERTS UNIT
4540
APACHE CORPORATION
Active - Oil
5300
5300
4540
4250132414
ROBERTS UNIT
3523A
APACHE CORPORATION
Active - Injection/Disposal
5300
5300
3523A
4250132712
ROBERTS UNIT
3537
APACHE CORPORATION
Plugged - Oil
5300
5300
3537
4250132722
ROBERTS UNIT
3547
APACHE CORPORATION
Active - Oil
5300
5300
3547
4250132945
ROBERTS UNIT
3541A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3541A
4250132975
ROBERTS UNIT
3641A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3641A
4250132711
ROBERTS UNIT
3620
APACHE CORPORATION
Active - Oil
5300
5300
3620
4250133527
ROBERTS UNIT
2518
APACHE CORPORATION
Active - Oil
5300
5300
2518
4250132714
ROBERTS UNIT
2637
APACHE CORPORATION
Plugged - Oil
5300
5300
2637
4250133351
ROBERTS UNIT
2526
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2526
4250132703
ROBERTS UNIT
2516
APACHE CORPORATION
Plugged - Oil
5300
5300
2516
4250133348
ROBERTS UNIT
2533
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2533
4250132702
ROBERTS UNIT
2515
APACHE CORPORATION
Active - Oil
5300
5300
2515
4250133350
ROBERTS UNIT
2525
APACHE CORPORATION
Active - Oil
5300
5300
2525
4250133498
ROBERTS UNIT
2532
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2532
4250133173
ROBERTS UNIT
2522
APACHE CORPORATION
Active - Oil
5300
5300
2522
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250133499
ROBERTS UNIT
2527
TEXACO PRODUCING INC.
Dry Hole
5300
5300
2527
4250133530
ROBERTS UNIT
2507
APACHE CORPORATION
Active - Oil
5300
5300
2507
4250132685
ROBERTS UNIT
2638
APACHE CORPORATION
Plugged - Oil
5302
5302
2638
4250133349
ROBERTS UNIT
2517
APACHE CORPORATION
Active - Oil
5302
5302
2517
4250132718
ROBERTS UNIT
3532A
APACHE CORPORATION
Active - Injection/Disposal
5304
5304
3532A
4250132713
ROBERTS UNIT
2625
APACHE CORPORATION
Active - Oil
5308
5308
2625
4250133502
ROBERTS UNIT
2527A
APACHE CORPORATION
Plugged - Oil
5308
5308
2527A
4250132716
ROBERTS UNIT
3526
APACHE CORPORATION
Active - Oil
5309
5309
3526
4250100645
ROBERTS UNIT
1624W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5309
5309
1624W
4250130913
DENVER UNIT
2223
OCCIDENTAL PERMIAN LTD.
Active - Oil
5310
5310
2223
4250132686
ROBERTS UNIT
2636
APACHE CORPORATION
Active - Oil
5310
5310
2636
4250101457
DENVER UNIT
2210
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5325
5325
2210
4250133529
ROBERTS UNIT
2508
APACHE CORPORATION
Plugged - Oil
5325
5325
2508
4250133531
ROBERTS UNIT
2443A
APACHE CORPORATION
Active - Injection/Disposal
5325
5325
2443A
4250133528
ROBERTS UNIT
2511
APACHE CORPORATION
Active - Oil
5325
5325
2511
4250135912
ROBERTS UNIT
3771W
APACHE CORPORATION
Active - Injection/Disposal
5330
5330
3771W
4250132075
ROBERTS UNIT
3637
APACHE CORPORATION
Active - Oil
5330
5330
3637
4250132063
ROBERTS UNIT
2705
APACHE CORPORATION
Active - Oil
5330
5330
2705
4250135793
ROBERTS UNIT
3672
APACHE CORPORATION
Active - Oil
5334
5334
3672
4250135819
ROBERTS UNIT
3674W
APACHE CORPORATION
Active - Injection/Disposal
5336
5336
3674W
4250135792
ROBERTS UNIT
3671
APACHE CORPORATION
Active - Oil
5339
5339
3671
4250135820
ROBERTS UNIT
3675W
APACHE CORPORATION
Active - Injection/Disposal
5341
5341
3675W
4250135818
ROBERTS UNIT
3633RW
APACHE CORPORATION
Active - Injection/Disposal
5344
5344
3633RW
4250135790
ROBERTS UNIT
3647R
APACHE CORPORATION
Active - Oil
5345
5345
3647R
4250100768
CORNELL UNIT
3107W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5350
5350
3107W
4250130915
DENVER UNIT
2221
OCCIDENTAL PERMIAN LTD.
Active - Oil
5350
5350
2221
4250136048
ROBERTS UNIT
3634RW
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3634RW
4250135908
ROBERTS UNIT
3678W
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3678W
4250132072
ROBERTS UNIT
3525
APACHE CORPORATION
Active - Oil
5350
5350
3525
4250135915
ROBERTS UNIT
3626R
APACHE CORPORATION
Active - Oil
5350
5350
3626R
4250132281
ROBERTS UNIT
2446
APACHE CORPORATION
Active - Oil
5350
5350
2446
4250132064
ROBERTS UNIT
2704
APACHE CORPORATION
Active - Oil
5350
5350
2704
4250132280
ROBERTS UNIT
2445
APACHE CORPORATION
Plugged - Oil
5350
5350
2445
4250135791
ROBERTS UNIT
3670
APACHE CORPORATION
Active - Oil
5351
5351
3670
4250135794
ROBERTS UNIT
3673
APACHE CORPORATION
Active - Oil
5352
5352
3673
4250135821
ROBERTS UNIT
3676W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3676W
4250135914
ROBERTS UNIT
3681W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3681W
4250100643
ROBERTS UNIT
1634W
APACHE CORPORATION
Plugged - Oil
5353
5353
1634W
4250135796
ROBERTS UNIT
3669
APACHE CORPORATION
Active - Oil
5356
5356
3669
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100644
ROBERTS UNIT
1614
APACHE CORPORATION
Plugged - Oil
5356
5356
1614
4250135913
ROBERTS UNIT
3680W
APACHE CORPORATION
Active - Injection/Disposal
5357
5357
3680W
4250135705
ROBERTS UNIT
3752
APACHE CORPORATION
Active - Oil
5360
5360
3752
4250135822
ROBERTS UNIT
3677W
APACHE CORPORATION
Active - Injection/Disposal
5362
5362
3677W
4250134984
ROBERTS UNIT
2626W
APACHE CORPORATION
Active - Injection/Disposal
5364
5364
2626W
4250135701
ROBERTS UNIT
3667
APACHE CORPORATION
Active - Oil
5365
5365
3667
4250132070
ROBERTS UNIT
3536
APACHE CORPORATION
Active - Oil
5370
5370
3536
4250132065
ROBERTS UNIT
2703
APACHE CORPORATION
Active - Oil
5370
5370
2703
4250100755
CORNELL UNIT
3101W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5373
5373
3101W
4250135703
ROBERTS UNIT
3668
APACHE CORPORATION
Active - Oil
5380
5380
3668
4250135229
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5388
5388
2240
4250136152
ROBERTS UNIT
3682W
APACHE CORPORATION
Active - Injection/Disposal
5397
5397
3682W
4250131539
DENVER UNIT
2230
SHELL OIL COMPANY
Canceled/Abandoned Location
5400
5400
2230
4250136327
ROBERTS UNIT
4547
APACHE CORPORATION
Active - Oil
5400
5400
4547
4250136154
ROBERTS UNIT
3624RW
APACHE CORPORATION
Active - Injection/Disposal
5400
5400
3624RW
4250136155
ROBERTS UNIT
3683W
APACHE CORPORATION
Active - Injection/Disposal
5402
5402
3683W
4250136156
ROBERTS UNIT
3686
APACHE CORPORATION
Active - Oil
5404
5404
3686
4250134797
CORNELL UNIT
3194
XTO ENERGY INC.
Active - Oil
5405
5405
3194
4250135696
CORNELL UNIT
113
XTO ENERGY INC.
Active - Oil
5406
5406
113
4250136150
ROBERTS UNIT
3684
APACHE CORPORATION
Active - Oil
5421
5421
3684
4250133629
CORNELL UNIT
3156
XTO ENERGY INC.
Active - Oil
5425
5425
3156
4250135961
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Active - Oil
5425
5425
2246
4250135960
DENVER UNIT
2249
OCCIDENTAL PERMIAN LTD.
Active - Oil
5431
5431
2249
4250136153
ROBERTS UNIT
3623RW
APACHE CORPORATION
Active - Injection/Disposal
5439
5439
3623RW
4250135353
CORNELL UNIT
107
XTO ENERGY INC.
Active - Oil
5450
5450
107
4250135528
ROBERTS UNIT
3549
APACHE CORPORATION
Active - Oil
5452
5452
3549
4250136151
ROBERTS UNIT
3685
APACHE CORPORATION
Active - Oil
5463
5463
3685
4250135963
DENVER UNIT
2252
OCCIDENTAL PERMIAN LTD.
Active - Oil
5476
5476
2252
4250136434
ROBERTS UNIT
263H
APACHE CORPORATION
Expired Permit
5500
5500
263H
4250136433
ROBERTS UNIT
262H
APACHE CORPORATION
Expired Permit
5500
5500
262H
4250136098
CORNELL UNIT
110
XTO ENERGY INC.
Active - Injection/Disposal
5510
5510
110
4250133615
ROBERTS UNIT
2442A
APACHE CORPORATION
TA - Injection/Disposal
5516
5516
2442A
4250135180
ROBERTS UNIT
3534B
APACHE CORPORATION
Active - Injection/Disposal
5517
5517
3534B
4250136428
CORNELL UNIT
124
XTO ENERGY INC.
Active - Oil
5532
5532
124
4250134878
ROBERTS UNIT
3548
APACHE CORPORATION
Active - Oil
5550
5550
3548
4250135966
DENVER UNIT
2251
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2251
4250135962
DENVER UNIT
2250
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2250
4250135356
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Expired Permit
5600
5600
2246
4250135959
DENVER UNIT
2248
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2248
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250135210
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250135211
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2241
4250134710
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250101845
ROBERTS UNIT
3613
APACHE CORPORATION
Active - Oil
7000
7000
3613
4250110083
RANDALL, E.
36
EXXON CORP.
Plugged - Oil
8595
8595
36
4250110046
ELLIOTT, C.A.
2
MCCLURE OIL COMPANY, INC.
Plugged - Oil
9000
9000
2
4250136692
MISS KITTY 704-669
3XH
RILEY EXPLORATION OPG CO, LLC
Expired Permit
9000
9000
3XH
4250133793
RANDALL, E.
39
XTO ENERGY INC.
Active - Oil
9000
9000
39
4250137375
RIP WHEELER 705-668
5XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
5XH
4250137358
RIP WHEELER 705-668
1XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
1XH
4250133843
ELLIOTT
1
DELTA C02, LLC
Plugged - Oil
9050
9050
1
4250134124
RANDALL, E
46
EXXON CORP.
Canceled/Abandoned Location
9100
9100
46
4250133792
RANDALL, E.
40
XTO ENERGY INC.
Plugged - Oil
9591
9591
40
4250110079
RANDALL, E.
32
EXXON CORP.
Plugged - Oil
9615
9615
32
4250135418
RANDALL, E.
46
XTO ENERGY INC.
Active - Oil
9650
9650
46
4250134023
RANDALL, E.
42
XTO ENERGY INC.
Active - Oil
9660
9660
42
4250134016
RANDALL, E.
43
XTO ENERGY INC.
Active - Oil
9740
9740
43
4250132388
RANDALL, E.
38
EXXON CORP.
Canceled/Abandoned Location
10300
10300
38
4250137302
MILLER 732 B
9H
AMTEX ENERGY, INC.
Active - Oil
5183
10662
9H
4250136432
ROBERTS UNIT
261 H
APACHE CORPORATION
Active - Oil
5151
11117
261 H
4250136998
RATTLESNAKE AGI
1
SANTA FE MIDSTREAM PERMIAN LLC
Active - Injection/Disposal
11980
11980
1
4250137252
MILLER SWD
7
AMTEX ENERGY, INC.
Permitted Location
13000
13000
7
4250136984
MADCAP 731-706
1XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5261
13274
1XH
4250137127
MISS KITTY A 669-704
25XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5321
13428
25XH
4250137287
MISS KITTY A 669-704
4XH
RILEY PERMIAN OPERATING CO, LLC
Shut-In - Oil
5340
13452
4XH
4250137236
MISS KITTY 669-704
2XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5317
13622
2XH
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well Penetrators
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
1
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
F-5
+ Rattlesnake AGI No. 1 SHL
I '
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
API (42-501-...) SHL Status - Type (Count)
• Active - Oil (4)
Active - Injection/Disposal (1)
Plugged - Oil (4)
® Permitted Location (1)
Sou rce:
1.) Oil/Gas Well SHL Data: DI-2022
2.) Oil/Gas Well BHL Data: DI-2022
3.) Oil/Gas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD).
1560
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Groundwater Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
F-6
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
+ Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
SDRDB Groundwater Wells [TWDB-2022]
Proposed Use (Labeled with Well Report No.)
A Industrial (1)
Irrigation (5)
TWDB Groundwater Wells [TWDB-2022]
Well Type (Labeled with State Well No.)
¦ Withdrawal of Water (1)
Sou rce:
1.) SDRDB Groundwater Well SHL Data: TWDB-2022
2.) TWDB Groundwater Well SHL Data: TWDB-2022
3.) Brackish Groundwater Well SHL Data: TWDB-2022
* Note: All coordinates shown are in NAD83 (DD). *
1560
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Cement Plug #9
@7'-1,013'
Cement Plug #8
@ 1,730'- 1,800'
Cement Plug #7
@ 2,031' - 2,100
Cement Plug #6
@2,430'-2,500'
Cement Plug #5
@2,660'-2,719'
Cement Plug #4
@2,790'-2,860'
Cement Plug #3
@3,172'-3,239'
Cement Plug #2
@3,765'-3,831'
Cement Plug #1
@ 3,900'-3,960'
Perfs @ 8,231
8,396', 8,420'
8,447', 8,462'
Casing Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
4-1/2"
Depth Set
2,134'
9,601'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-10079
RRC District No: 8-A
Drawn: KAS
E. Randall No. 32
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18231
Date: 05/31/2022
Approved: SLP
-------
Cement Plug #5
@ 0' - 458'
Cement Plug #4
@2,070'-2,295'
Cement Plug #3
@2,780'- 3,009'
Cement Plug #2
@4,450'-4,870'
Cement Plug #1
@5,184'-5,266'
Perfs@ 9,496'-9,516'
TD@ 9,591'
PBTD @ 9,560'
DV Tool ® 4,522'
DV Tool @ 5,676'
Casing Information
Label
1
3
Type
Surface
Production
OD
9-5/8"
5-1/2"
Weight
36 lb/ft
UNK
Depth Set
2,162'
9,569'
Hole Size
12-1/4"
7-7/8"
TOC
Surface
2,350'
Volume
880 sks
5,450 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-337932
RRC District No: 8-A
Drawn: KAS
E. Randall No. 40
State/Province: Texas
Spud Date: 12/04/1992
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
A
Perfs (5) 9,536' - 9,540'
SI
[S
: . I
DV Tool @ 5,968'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54 lb/ft
36 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,129'
5,606'
9,699'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
1,790 sks
2,910 sks
1,590 sks
2-3/8" Tubing & Packer Set @ 9,331'
TD @ 9,700'
PBTD @ 9,654'
MD
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-33885
RRC District No: 8-A
Drawn: KAS
E. Randall No. 41L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,533' - 9,553'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,167'
5,830'
9,658'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
440'
1,800'
Volume
1,530 sks
3,500 sks
1,050 sks
DV Tool ® 7,414'
2-3/8" Tubing & Packer Set @ 8,970'
TD @ 9,660' \-(3)
PBTD @ 9,623' W
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34023
RRC District No: 8-A
Drawn: KAS
E. Randall No. 42L
State/Province: Texas
Spud Date: 07/01/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Li;.
Perfs @ 9,550' - 9,538'
9,603'-9,610'
sf.
.... «¦
*'¦ •-
4/?
¦A ¦
" B ¦'
" ¦ /
?
, 4' i
,
"4
t" '
'*¦ ?r
. v.
> .¦
"A
' 'i
;
¦ 'v
„ .: '
4* •"
/
CIBP ® 8,917'
CIBP @ 9,590'
TD @ 9,740'
PBTD @ 8,917'
rv@
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,166'
5,902'
9,735'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
2,000'
Volume
1,530 sks
3,505 sks
967 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-34016
RRC District No: 8-A
Drawn: KAS
E. Randall No. 43L
State/Province: Texas
Spud Date: 04/08/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs @ 8,762' - 8,782'
(Sqz w/100 sx)
Perfs @8,822'-8,831'
(Sqz w/ 75 sx)
Perfs @ 9,562' - 9,570'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
29 lb/ft
Depth Set
2,158'
5,904'
9,620'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,600'
Volume
1,450 sks
5,190 sks
1,100 sks
DV Tool ® 7,482'
2-3/8" Tubing & Packer Set @ 9,552'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34024
RRC District No: 8-A
Drawn: KAS
E. Randall No. 44
State/Province: Texas
Spud Date: 08/09/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,565' - 9,575'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,175'
5,898'
9,615'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,500'
Volume
1,530 sks
3,525 sks
1,170 sks
DV Tool ® 7,508'
2-3/8" Tubing Set @ 9,580'
Packer Set (5) 9,394'
TD @ 9,684'
PBTD @ 9,593'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34017
RRC District No: 8-A
Drawn: KAS
E. Randall No. 45L
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
Perfs (5) 9,504' - 9,512'
TD @ 9,650'
PBTD @ 9,594'
Casing/Tubing
Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
5-1/2"
Weight
24 lb/ft
17 lb/ft
Depth Set
2,120'
9,650'
Hole Size
11"
7-7/8"
TOC
Surface
Surface
Volume
900 sks
3,400 sks
DV Tool ® 8,656' & 8,674'
2-7/8" Tubing & Packer Set @ 9,184'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy, Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-35418
RRC District No: 8-A
Drawn: KAS
E. Randall No. 46
State/Province: Texas
Spud Date: 05/23/2007
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
u
Cement Plug #4
@48'-60'
Cement Plug #3
@ 270' - 450'
Cement Plug #1
@7,549'-8,000'
Perfs @ 8,292' - 8,428'
Cement Plug #2
@3,273'-3,439'
Top of Cut @ 750'
Top of Cut @ 1,439'
TD ® 9,645'
v@
Casing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
5-1/2"
Depth Set
300'
3,200'
9,610'
TOC
Surface
Surface
Surface
Volume
400 sks
300 sks
425 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Bonanza Oil Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-10046
RRC District No: 8-A
Drawn: KAS
C.A. Elliott No. 2
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18875
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
w
if.
II
: .
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
48 lb/ft
40 lb/ft
26 lb/ft
28 lb/ft
Depth Set
500'
5,500'
10,695'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
350 sks
1,705 sks
1,635 sks
3-1/2" Tubing & Packer Set @ 10,650'
MD
TD @ 13,000'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Amtex Energy, Inc.
Country: USA
Location: Section 732, Block D
API No: 42-501-37252
RRC District No: 7-C
Drawn: KAS
Miller SWD No. 7 (Permitted)
State/Province: Texas
Spud Date: 08/09/1995
Field: Wasson
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
Permit Number: 16637
Date: 05/31/2022
Approved: SLP
-------
Request for Additional Information: 30-30 Gas Plant
July 25, 2022
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references,
or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
NA
NA
Several map figures in the MRV plan have difficult to
read text within the map legends. We recommend
increasing the font size where needed. For example,
Figures 11, 26, 27, etc.
Larger scale versions of all maps have been included in the Appendices and references
to the maps added
2.
INTRO
1
'This AGI well is associated with Stakeholder's 30-30
gas treating and processing plant ("30-30") located in
a rural, sparsely populated area of Yoakum County,
Texas, approximately seven miles northwest of the
town of Plains."
Please add a reference for Figure 1.
"as shown in Figure 1." Added to the last sentence in paragraph 1 (pg 1)
3.
INTRO
2
Please define MMSCF/d and other acronyms upon
first use.
Added: "16 million standard cubic feet per day ("MMSCF/d")." (pg 2)
4.
2
9
'The Rattlesnake AGI #1 well is located and designed
to protect against migration of CO2 into productive oil
and gas formations and freshwater aquifers and to
prevent surface releases."
This sentence is awkwardly worded. We recommend
adjusting to improve clarity.
Sentence modified to "The Rattlesnake AGI #1 well is located and designed to protect
against migration of C02 out of the injection interval and to prevent surface releases."
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
5.
2
9
"in the area and 8,593' below the base of the lowest
useable quality water table, as Shown in Figure 2."
Please fix capitalization.
Capitalization fixed (pg 9)
6.
2
13
'The Wristen Group is composed of three formations;
Fasken, Frame, and Wink formations."
Please consider changing the semicolon to a colon in
the above sentence.
Semicolon changed to colon (pg 13)
7.
2
16
'The Woodford is a late Devonian-aged..."
Consider changing "aged" to "age"
Changed "aged" to "age" (pg 16)
8.
2
19
Please clarify why the Rattlesnake AGI #1 (42-501-
36998) well log is used in Figure 10, but an offset well
(45-501-10238) is used in Figure 7.
Added "An offset well log was used to depict the upper confining intervals as electric
logs were only run in the Rattlesnake AGI #1 well across the injection zone." to the
paragraph discussing Figure 7 (pg 15)
9.
2
20
The pH values in Table 1 are the same as the values
used in the Campo Viejo Gas Processing Plant MRV
plan. Please confirm whether these values are
accurate for the 30-30 Plant.
The pH values are correct for the Rattlesnake area
10.
2
30
"Figure 19 shows the subsurface and outcrop extent
of the Ogallala Aquifer."
We believe the reference here is to Figure 20. Please
address.
Corrected to "Figure 20" (pg 30)
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
11.
2
30
"... by approximately 9,500' of rock..."
Section 2 of the MRV plan gives the figure of 8,593
feet. Please clarify.
Corrected to "approximately 8,600' of rock" (pg 30). Also corrected "650' of Salado
salt" to "576' of Salado salt"
12.
2
32
Figure 21 is the exact same as the figure used in the
Campo Viejo Gas Processing Plant MRV plan. Please
clarify whether this figure and values are applicable to
the 30-30 Gas Plant.
The ranges provided for H2S/C02 compositions is applicable, as confirmed in Table 5 -
Modeled Initial Gas Composition. However, the high pressure for the injection pumps
has been updated to reflect the expected permitted MASIP
13.
2
33
'The grid contains 141 blocks in the x-direction (E-W)
and 201 blocks in the y-direction (N-S), totaling 28,341
grid blocks per layer. This results in the grid being
21,150' by 30,150' totaling just over a 23-square mile
area (14,640 acres)."
The MRV plan does not provide the dimensions of the
individual blocks themselves. Please add for clarity.
'The grid blocks are each 150' by 150' by layer thickness as specified in Table 6." added
to provide dimensions (pg 33)
14.
3
40
"In this case, the plume boundary in 2041 is within the
plume at 2036 plus a half-mile buffer. By 2036 at the
latest, a revised MRV will be submitted to define a
new AMA. Figure 27 shows the area covered by the
AMA."
Please add "plan" after "MRV".
"plan" added after MRV (pg 40)
15.
4
44
"A larger scale version of Figure 27 is provided in
Appendix D."
Is this supposed to be Figure 28? Please address.
Figure 27 changed to Figure 28 (pg 44)
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
16.
4
44
"... a few wells have produced from the Wolfcamp
The Wolfcamp is separated from the..."
It appears that a punctuation mark is missing. Please
address.
Period added after sentence (pg 44)
17.
4
44
"All of the wells which penetrate the injection interval
within the MMA were properly cased and cemented
to prevent annular leakage of CO2 to the surface."
Please clarify whether this is a determination made by
the 30-30 Gas Plant operators or if this is according to
TRRC records.
Sentence changed to "A review of the TRRC records for all of the wells which penetrate
the injection interval within the MMA, shows the wells were properly cased and
cemented to prevent annular leakage of C02 to the surface." to clarify that the TRRC
records show that the wells are properly constructed, (pg 44)
18.
4
48
"In this instance, any new well permitted and drilled
to the Rattlesnake AGI #1 well's injection zone located
within a one-quarter mile radius of the Rattlesnake
AGI #1 well will be required under TRRC Rule 13 to set
steel casing and cement above the Rattlesnake AGI #1
well injection zone."
This sentence is confusing to read. We recommend
adjusting with punctuation or rewording.
Sentence clarified "In this instance, any new well permitted and drilled to the
Rattlesnake AGI #1 well's injection zone, and located within a one-quarter mile radius of
the Rattlesnake AGI #1 well, will be required under TRRC Rule 13 to set steel casing and
cement above the Rattlesnake AGI #1 well injection zone." (pg 48)
19.
4
48
"See GAU letter attached included within Appendix B"
Should this read, "See GAU letter attached in
Appendix B"?
"Attached" removed from sentence (pg 48)
20.
4
50
In Table 9, owners are referred to both as FRANCIS
BARBINI and FRANCIS BARBIDI. Are these two
different owners, or is one a misspelling?
Likely "Barbidi" is a misspelling, but listed as perTWDB records
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
21.
4
51
"Leakage from Natural or Induced Seismicity" is
discussed primarily from the perspective historical
seismicity in the area. Will there be any operational
practices implemented to ensure that the risk of
induced seismicity is mitigated?
The following: "Pressures will be kept significantly below the fracture gradient of the
injection and confining intervals. Additionally, continuous well monitoring combined
with seismic monitoring will identify any operational anomalies associated with a
seismicity event." was added to this section (pg 51)
22.
5
54
'Table 8 summarizes the monitoring of potential
leakage pathways to the surface."
Should this refer to Table 10?
Table 8 corrected to Table 10 (pg 54)
23.
5
54
"Monitoring will occur during the planned 25-year
injection period, or cessation of injection operations,
plus a proposed 5-year post-injection period."
Other parts of the MRV plan reference an injection
period of 17 years. Please clarify and update the MRV
plan as necessary
"25-year" corrected to "17-year" (pg 54)
24.
5
55
"...which are shown in Figure 28above"
It appears there is a space missing. Please address.
Space added (pg 55)
25.
5
55
'The scope of work will include H2S and CO2
monitoring at the AGI well site as well as minimum,
quarterly atmospheric monitoring near identified
penetrations within the AMA."
Please describe what atmospheric monitoring will be
conducted. E.g., what types of parameters will be
measured?
"At the well site, H2S and C02 concentrations will be monitored continuously with fixed
monitors that detect atmospheric concentrations of H2S and C02. At penetrating well
sites, Stakeholder will similarly measure atmospheric concentrations of C02 and H2S
using mobile gas monitors. This data will be recorded at least quarterly." was added to
clarify the parameters to be measured (pg 55)
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
26.
5
55
"Stakeholder will monitor the groundwater quality in
fluids above the confining interval by sampling the
well on the facility property and analyzing the sample
with a third-party laboratory on an annual basis."
What types of parameters will be measured in the
groundwater samples?
'The parameters to be measured will include pH, total dissolved solids, total inorganic
and organic carbons, density, temperature and other standard laboratory
measurements. Any significant differences in these parameters from the baseline
sample will be evaluated to determine if leakage of C02 to the USDW may have
occurred." was added to clarify the parameters to be measured (pg 56)
27.
5
56
"Stakeholder plans to install a seismic monitoring
station in the general area of the Rattlesnake AGI #1
well."
When is the seismic monitoring station planned to be
installed?
'The installation of this station would start upon approval of the MRV plan, with an
expected in-service data within six months after the commencement of the installation
project." added to this paragraph (pg 56)
28.
7
59
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-4:"
When using a volumetric flow meter, you must use
Equation RR-5. Equation RR-4 is used when a mass
flow meter is used to measure the injection quantity.
Please clarify what type of flow meter will be used and
which equation will be used to calculate mass of CO2
injected.
Corrected to Equation RR-5 (pg 59)
29.
2
31
Corrected depths and thickness to those provided by GAU letter (pg 30)
30.
-------
STAKEHOLDER
fMIDSTREAM
Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan
Rattlesnake AGI #1
Yoakum County, Texas
Prepared for Stakeholder Gas Services, LLC
San Antonio, TX
By
Lonquist Sequestration, LLC
Austin, TX
Version 1
June 2022
LONQUIST
SEQUESTRATION LLC
i
-------
INTRODUCTION
Stakeholder Gas Services, LLC ("Stakeholder") currently has a Class II acid gas injection ("AGI") permit, issued
by the Texas Railroad Commission ("TRRC") in November 2018, for the Rattlesnake AGI #1 well, API No. 42-
501-36998. This permit was originally issued to Santa Fe Midstream Permian, LLC, in 2018 and the asset was
subsequently acquired by Stakeholder in December of 2020. This permit currently authorizes Stakeholder to
inject up to 4,500 barrels per day ("bbls/d") of treated acid gas ("TAG") into the Devonian formation at a
depth of 11,000' to 12,000' with a maximum allowable surface pressure of 2,200 psi. Since being permitted,
injection has proceeded without incident. This AGI well is associated with Stakeholder's 30-30 gas treating
and processing plant ("30-30") located in a rural, sparsely populated area of Yoakum County, Texas,
approximately seven miles northwest of the town of Plains.
Colorado
p±d
OkU ho
ma
-
'
STAKEHOLDER
fMIDSTREAM
iW -
i L
"I
1
1
M
LD
I
¦
WE S
OIL F
IELD
Yoakum
Basin
Rattlesnake
AGI (RS#1)
•
WASSON
OIL
FIELD
$
i our Mar Rd
YOAKUM
GAINES
Gaines
0 0.5 1 2 Miles
0EORGE At
LBN
OIL FIELD
# Stakeholder AGI Well
Figure 1 - Location of Rattlesnake AGI #1 Well
1
-------
Stakeholder 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, Stakeholder is also applying to the TRRC for an amendment to the
Rattlesnake AGI #1 well's Class II permit to increase its authorized injection volume and maximum allowable
surface injection pressure ("MASIP"). Approval of the permit amendment will allow Stakeholder to increase
the capacity of its existing 30-30 Facility, which removes H2S and C02 from natural gas production using amine
treating, as well as increase the injection well capacity for a future gas processing facility which is currently
under development by Stakeholder. Additionally, expanded capacity allows Stakeholder to potentially
provide future disposal in its AGI well for oil and gas waste derived TAG from similar third-party gas processing
facilities. Increased disposal capacity will allow for greater gas processing capacity in the region, ultimately
helping to reduce flaring and its associated emissions. Throughout this document, both in written reference
and in modeling inputs, Stakeholder has used the applied-for expanded permit capacity of 16 MMSCF/d.
Stakeholder plans to inject C02 for approximately 14 more years.
2
-------
ACRONYMS AND ABBREVIATIONS
%
°c
°F
AMA
BCF
CH4
CMG
C02
E
EOS
EPA
ESD
FG
ft
GAU
GEM
GHGs
GHGRP
H2S
md
mi
MIT
MM
MMA
MCF
MMCF
MMSCF
Feet
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)
Groundwater Advisory Unit
Computer Modelling Group's GEM 2020.11
Greenhouse Gases
Greenhouse Gas Reporting Program
Hydrogen Sulfide
Millidarcy(ies)
Mile(s)
Mechanical Integrity Test
Million
Maximum Monitoring Area
Thousand Cubic Feet
Million Cubic Feet
Million Standard Cubic Feet
-------
MSCF/D Thousand 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
4
-------
TABLE OF CONTENTS
INTRODUCTION 1
ACRONYMS AND ABBREVIATIONS 3
SECTION 1 - FACILITY INFORMATION 8
Reporter number 8
Underground Injection Control (UIC) Class II Permit 8
UlCWell Identification Number 8
SECTION 2 - PROJECT DESCRIPTION 9
Regional Geology 10
Regional Faulting 15
Site Characterization 15
Stratigraphy and Lithologic Characteristics 15
Upper Confining Interval - Woodford Shale 16
Injection Interval - Fasken Formation 17
Lower Confining Zone - Fusselman Formation 21
Local Structure 21
Injection and Confinement Summary 26
Groundwater Hydrology 26
Description of the Injection Process 31
Current Operations 31
Planned Operations 32
Reservoir Characterization Modeling 32
Simulation Modeling 35
SECTION 3 - DELINATION OF MONITORING AREA 39
Maximum Monitoring Area 39
Active Monitoring Area 40
SECTION 4- POTENTIAL PATHWAYS FOR LEAKAGE 42
Leakage from Surface Equipment 42
Leakage from Wells in the Monitoring Area 44
Oil and Gas Operations within Monitoring Area 44
Groundwater wells 48
Leakage Through Faults or Fractures 50
Leakage Through Confining Layers 51
Leakage from Natural or Induced Seismicity 51
SECTION 5 - MONITORING FOR LEAKAGE 54
Leakage from Surface Equipment 54
Leakage from Existing and Future Wells within Monitoring Area 55
Leakage through Faults, Fractures or Confining Seals 56
Leakage through Natural or Induced Seismicity 56
SECTION 6 - BASELINE DETERMINATIONS 57
Visual Inspections 57
H2S Detection 57
CO2 Detection 57
Operational Data 57
Continuous Monitoring 57
Groundwater Monitoring 58
SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE EQUATION 59
5
-------
Mass of C02 Received 59
Mass of CO2 Injected 59
Mass of CO2 Produced 60
Mass of CO2 Emitted by Surface Leakage 60
Mass of CO2 Sequestered 60
SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN 62
SECTION 9 - QUALITY ASSURANCE 63
Monitoring QA/QC 63
Missing Data 63
MRV Plan Revisions 64
SECTION 10 - RECORDS RETENTION 65
References 66
APPENDICES 67
LIST OF FIGURES
Figure 1 - Location of Rattlesnake AGI #1 well 1
Figure 2 - Illustrative overview of Rattlesnake AGI #1 and 30-30 Facility 9
Figure 3 - Regional Map of the Permian Basin 10
Figure 4 - Stratigraphic column of the Northwest Shelf 11
Figure 5 - Stratigraphic column depicting the composition of the Silurian group 12
Figure 6 - Thickness map of the Silurian system which composes the Fusselman and Wristen group 14
Figure 7 - Type Log (42-501-10238) with tops, confining and injection zones depicted 15
Figure 8 - Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994) 16
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays 18
Figure 10 - Rattlesnake AGI #1 open hole log (42-501-36998) 19
Figure 11 - Offset wells used for Formation Fluid Characterization 20
Figure 12 - Silurian Structure Map (subsea depths) 23
Figure 13 - Structural Northeast-Southwest Cross Section 24
Figure 14- Structural Northwest-Southeast Cross Section 25
Figure 15 - Northwest-Southeast Cross Section of aquifers in the Rattlesnake AGI #1 well area 27
Figure 16 - Potentiometric surfaces from wells completed in A Ogallala aquifer, B the Edwards-Trinity aquifer
and Cthe Dockum aquifer 28
Figure 17 - Regional extent of the Dockum freshwater aquifer (TWDB) 29
Figure 18-Total dissolved solids in groundwater from the Dockum Aquifer 29
Figure 19- Regional extent of the Edwards-Trinity freshwater aquifer 30
Figure 20 - Regional extent of the Ogallala freshwater aquifer 31
Figure 21 - 30-30 Facility Process Flow Diagram 32
Figure 22 - Permeability Distribution of Karst Limestone 34
Figure 23 - Areal View Gas Saturation Plume, 2036 (End of Injection) 37
Figure 24 - Areal View Gas Saturation Plume, 2779 (End of Density Drift) 38
Figure 25 - Well Injection Rate and Bottomhole Pressure over Time 38
Figure 26 - Plume Boundary at End of Injection, Stabilized Plume, and Maximum Monitoring Area 40
Figure 27 - Active Monitoring Area 41
Figure 28 - Site Plan, 30-30 Facility 43
Figure 29 - Rattlesnake AGI #1 Wellbore Schematic 45
Figure 30 - Oil and Gas Wells within the MMA 46
6
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Figure 31 - Penetrating Oil and Gas Wells within the MMA 47
Figure 32 - Groundwater Wells within MMA 49
Figure 33 - Seismicity Review (TexNet - 06/01/2022) 52
Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI #1 location 53
LIST OF TABLES
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples 20
Table 2 - Fracture Gradient Assumptions 21
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and
Yoakum Counties, Texas 26
Table 4 - Gas Composition of 30-30 Facility outlet 31
Table 5 - Modeled Initial Gas Composition 33
Table 6 - CMG Model Layer Properties 34
Table 7 - All Offset SWDs included in the model 36
Table 8 - All Offset Producers included in the model 36
Table 9 - Groundwater Well Summary 50
Table 10 - Summary of Leakage Monitoring Methods 54
7
-------
SECTION 1 - FACILITY INFORMATION
This section contains key information regarding the Acid Gas and C02 injection facility.
Reporter number:
• Gas Plant Facility Name: 30-30 Gas Plant
• Greenhouse Gas Reporting Program ID: 574501
o Currently reporting under Subpart UU
• Operator: Stakeholder Gas Services, LLC
Underground Injection Control (UIC) 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 Rattlesnake AGI #1 well as a UIC Class II well. A Class II
permit was issued to Stakeholder under TRRC Rule 9 (entitled "Disposal into Non-Productive Formations")
and Rule 36 (entitled "Oil, Gas, orGeothermal Resource Operation in Hydrogen Sulfide Areas").
UIC Well Identification Number:
Rattlesnake AGI #1, API No. 42-501-36998, UIC #000117143.
8
-------
SECTION 2 - PROJECT DESCRIPTION
This Project Description discusses the geologic setting, planned injection volumes and process, and the
reservoir modeling performed for the Rattlesnake AGI #1 well. The Class II UIC permit was initially applied
for and received by Santa Fe Midstream Permian, LLC. The asset was acquired in 2020 by Stakeholder and
has been in operation since that time. Since the original application, Lonquist has revised and updated the
geology and the plume modeling within the reservoir in preparing this MRV Plan.
The Rattlesnake AGI #1 well is located and designed to protect against migration of CO2 into productive oil
and gas formations and freshwater aquifers and to prevent surface releases. The injection interval for
Rattlesnake AGI #1 is located over 4,720' below the primary producing formation, the San Andres, in the area
and 8,593' below the base of the lowest useable quality water table, as Shown in Figure 2. This well injects
both H2S and C02, therefore the well and the facility are designed to minimize any leakage to the surface.
2,450'
LOWEST
WATER TABLE
DEPTH
5,500'
CASING DEPTH
Casing consists of
reinforced steel
and concrete
11,000'
INJECTION WELL
DEPTH
>8,500'
BELOWTHE
WATER TABLE
Figure 2 - Illustrative overview of Rattlesnake AGI ffl and 30-30 Facility
9
-------
Regional Geology
The Rattlesnake AGI #1 well is located on the southern portion of the Northwestern Shelf within the larger
Permian Basin as seen in Figure 3. The Northwestern Shelf is a broad marine shelf located in the northern
portion of the Permian Basin.
Basin
Matador Arch
Midlam
rBasIm
new.m_exico'
Ttexa's "J
Delaware^
Basin \
Ozona
, Arch
>Val Verde
' Basin
.Ouach/tj
Nj
NEW
[MEXICO
^Permian Basin
Figure 3 - Regional Map of the Permian Basin. Red Star is approximate location of Rattlesnake AGIffl well
Figure 4 depicts the stratigraphic column found at the Rattlesnake AGI #1 well location with red stars
referencing the injection formation and green stars indicating the productive intervals in the area. The
primary injection interval is found within the Wristen group, of Silurian-age, as seen in Figure 5. The TRRC
refers to this sequence under the general terms "Devonian", "Silurian-Devonian" or "Siluro-Devonian".
10
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Period
Epoch
Formation
General Lithology
Dewey Lake
Redbeds/Anhydrite
Ochoan
Rustler
Halite
Salado
Halite/Anhydrite
Tansil
Anhydrite/Dolomite
Yates
Anhydrite/Dolomite
Guadalupian
Seven Rivers
Dolomite/Anhydrite
Queen
Sandy Dolomite/Anhydrite/Sandstone
Permian
Grayburg
Dolomite/Anhydrite/Shale/Sandstone
~ San Andres
Dolomite/Anhydrite
Glorieta
Sandy Dolomite
Paddock
Leonardian
Yeso
Blinebry
Dolomite/Anhydrite/Sandstone
Tubb
Drinkard
Abo
Dolomite/Anhydrite/Shale
Wolfcampian
^ Wolfcamp
Limestone/Dolomite
Virgilian
Cisco
Limestone/Dolomite
Missourian
Canyon
Limestone/Shale
Pennsylvanian
Des Moinesian
Strawn
Limestone/Sandstone
Atokan
Bend
Limestone/Sandstone/Shale
Morrowan
Morrow
Mississippian
Mississippian Lime
Limestone
Devonian
Woodford
Shale
Silurian
^Wristen Group
Dolomite/Limestone
Fusselman
Dolomite/Chert
Upper
Ordovician
Montoya
Dolomite/Chert
Middle
Simspson Gp
Limestone/Sandstone/Shale
Lower
Ellenburger
Dolomite
Figure 4 - Stratigraphic column of the Northwest Shelf, Red stars indicate injection interval. Green stars indicate productive
intervals.
-------
c
03
¦ MB
Q.
Q.
'
a5
-------
secondary porosity development and increased permeability. Dolomite and solution-related features are the
most prominent diagenetic characteristics found within the Silurian. The Wristen Group is composed of three
formations; Fasken, Frame, and Wink formations. The Frame and Wink formations are found near the ramp
boundary to the south, while the Fasken formation is found predominantly in the inner platform, where the
Rattlesnake AGI #1 well is located. The Fasken formation is predominately dolomite grading to limestone,
occurring as cycles, down section. This dolomitization is due in part to sub-areal exposure, during which
karsts and secondary porosity developed. Additional dolomitization was possible during successive sea level
fluctuations via movement of magnesium-rich solution through karsts and vugs, which acted as channels for
fluid flow (Ruppel and Holtz, 1994).
Figure 6 shows a regional isopach map of the Silurian (combined Fasken and Fusselman formations) with a
red star depicting the Rattlesnake AGI #1 well location. Thickness of the Silurian-age rock is approximately
1,000' at the Rattlesnake AGI #1 well location.
North of Andrews County there is little differentiation between the Fasken and Fusselman formations which
are both carbonate deposits with the potential for sub-areal exposure and porosity development. For
purposes of this MRV Plan, the combined Fasken and Fusselman formations are defined as the injection
interval, and the underlying Montoya formation serves as the lower confining unit.
13
-------
LJS8C-C*
."OCKVt*
Explanation
<0*KU«
tHjcicsess tfi)
Apptot «t pn»r\
Wt>lt«n ploltO'ir m/j'Qtn *•
isr«f»5
ME«U
-------
Regional Faulting
A major uplift that began during the Pennsylvanian Period to the south, the Central Basin Platform, ceased
in the Early Permian (Wolfcampian), which caused a regional unconformity of the underlying formations
(Hoak, Sundberg, and Ortoleva). Faulting on the Northwest Shelf can be seen through high angle basement
faults that tend to die within the Pennsylvanian strata. These faults predominately represent contractional
(thrust) faults that were initiated during the Pennsylvanian as a result of regional tectonics. Hydrocarbon
traps within the Wristen group are primarily anticlinal structures dependent upon reservoir development
(Broadhead, 2005).
Site Characterization
The Rattlesnake AGI #1 well is located in Section 733, Block D, John H. Gibson Survey, in Yoakum County,
Texas. Stakeholder owns the 82.42-acre surface tract where the plant and Rattlesnake AGI #1 well are
located. The following discusses the geological character of this site.
Stratigraphy and Lithologic Characteristics
Figure 7 depicts an open hole log from an offset well (API No. 42-501-10238) to the Rattlesnake AGI #1 well
indicating the injection and primary upper confining zone. This well is approximately 1.8 miles to the
northwest of the Rattlesnake AGI #1 well.
GR
DT
) 15C
120 1C
{
g
^5
F
-f
4
y
1
L
c
=-
RUSTLER [PUJ=21760
SALADO (PU)=2287 6
TANSIL (PU]=2938 1
YATES (PU]=3022 6
SEVEN_RJVERS [PUl=3273
QUEEN (PU)=3867 4
GRAYBURG (PLJ)=4251 9
SAN ADREAS [PU]=4467 9
TUBB (PU]=7079 2
GLORIETA [PU]=5908 4
CLEARFORK [PU]=6516 0
ABO (PUJ=7678 5
Injection
Zone
WOLFCAMP [PU)=8847 9
E
STRAWN|PU]= 100634
ATOKA IPU]*10261 0
M1SS UME (PU]» 10401 1
WOOOFOKD |PLJ)«11018 5
SILURIAN [PLJl311073 4
Figure 7- Type Log (42-501-10238) with tops, confining and injection zones depicted
15
-------
Upper Confining Interval - Woodford Shale
The Woodford is a late Devonian-aged organic-rich shale deposited as a result of a widespread marine
transgression. The flooding event occurred over the majority of the Permian basin, which produced a low-
relief blanket-like shale deposit of the Woodford. Two major lithofacies found within the Woodford are black
shale and siltstone. Nutrient-rich surface waters promoted the decay of abundant organic matter within the
Woodford, resulting in a high total organic carbon ("TOC") percentage. The Woodford shale acts as the
primary source and sealant rock for the Wristen Group (Comer, 1991).
Figure 8 is a description of a core sample taken in Lea County, New Mexico just southwest of the Rattlesnake
AGI #1 well location. This sample is referenced as C9 in the reference map with the blue star representing
the Rattlesnake AGI #1 well. In the core description, black shale with abundant illitic clays is observed in the
upper section, and medium gray dolomitic siltstone found in the basal section. The mineralogic and lithologic
properties recorded in this description serve as excellent sealant characteristics to prohibit any injected fluids
from migrating above the injection interval.
The Woodford at the Rattlesnake AGI #1 well location is encountered at 10,973' and is approximately 63'
thick.
C9
Shell No. 5 Pacific Royalty
Lea County, New Mexico
Section 10, T 15 S - R 37 E
Elevation 3814 ft
I Boilgy
| Cochron
¦»
| Roosevelt |
jjP
I Yookum
I
I
"a I ~
CI3 ' Goines
Figure 8 - Core description of the Woodford Shale and Upper Silurian (Ruppel and Holtz, 1994)
a
<
I Formation |
'c
ZD
TOC
Weight
percent
1 2 3 4 5
GR
ngm Ra-
eq/ton
12 3 4
Sample no.
Uthology
Thickness 1
xz
s.
-------
Injection Interval - Fasken Formation
The Rattlesnake AGI #1 well reaches total depth in the Fasken/Fusselman formation (Silurian in age), directly
below the Woodford formation. Dolomites at the top of the Fasken formation underwent multiple leaching
and diagenetic episodes which developed secondary porosity. This is evidenced in offset wells by the practice
of only drilling through the top 30' of the Fasken, in anticipation of encountering the best reservoir quality.
In Figure 8, the uppermost Silurian section is described as 'vuggy dolostone' in the core description. Beds
below the top of the Fasken section may also have similar petrophysical attributes if exposed to multiple
diagenetic events. Solution-collapse and karst breccia horizons can be found within inner platform deposits,
some occurring as much as 100' below the Fasken top (Ruppel and Holtz, 1994).
Porositv/Permeabilitv Development
Porosity in the Fasken formation at the Rattlesnake AGI #1 well location is typically moldic and intercrystalline
associated with leaching of allochem-rich intervals. Porosity is directly related to these leaching events which
occurred during and post-deposition, resulting in vugs and karst-like features. Figure 9 provides reservoir
information from core data within fields in the Wristen buildup and platform carbonate play. The average
porosity of these cores is 7.1% with an average permeability of 45.28 millidarcies (Ruppel and Holtz, 1994).
The porosity and permeability described in the offset core data indicate the Fasken formation provides
sufficient accessible pore space for the amount of fluid injection proposed.
Using the above values as reference points, the Rattlesnake AGI #1 porosity log (API No. 42-501-36998) was
evaluated. Figure 10 is the product of the petrophysical analysis performed on the open hole logs run within
the injection interval at the Rattlesnake AGI #1 well. A permeability curve was generated from the effective
porosity curve using the table in Figure 9 to establish the porosity-permeability relationship. In Figure 10,
the majority of the injection interval's porosity and permeability is found at the top of the Fasken formation,
which correlates with the diagenetic processes described above. These curves are extrapolated to the
injection site and used to establish reservoir characteristics in the plume model.
17
-------
Wristen
Fusselman
Buildups and
Thirtyone
Thirtyone
Shallow Platform
Platform
Ramp
Deep-Water
Carbonate play
Carbonate play
Carbonate play
Chert play
Porosity (%)
Number of data points
33
30
16
35
Mean
7.93
7.10
6.41
14.85
Minimum
1.00
2.70
3.50
2.00
Maximum
17.70
14.00
Q.50
30.00
Standard deviation
4.01
2.67
1.75
6.76
Permeability (md)
Number of data points
21
24
12
33
Mean
11.61
45.28
1.51
8.56
Mnimum
0.60
2.90
0.40
1.00
Maximum
84.80
400.00
30.00
100.00
Standard deviation
22.48
99.17
8.36
22.23
Initial water saturation (%)
Number of data points
24
28
10
31
Mean
26.96
31.55
24.70
31.46
Mnimum
10.00
20.00
16.00
10.00
Maximum
50.00
55.00
40.00
45.00
Standard deviation
9.31
10.45
7.39
8.33
Residual oil saturation (%)
Number of data points
8
13
5
22
Mean
34.06
30.54
21.30
29.17
Mnimum
30.00
20.00
9.00
14.00
Maximum
50.00
35.00
35.00
48.20
Standard deviation
6.99
4.61
11.66
9.76
Oil viscosity (cp)
Number of data points
11
12
5
21
Mean
0.69
1.16
0.33
0.68
Minimum
0.13
0.32
0.04
0.07
Maximum
1.08
2.00
1.00
1.03
Standard deviation
0.81
0.75
0.40
0.42
Oil formation volume factor
Number of data points
21
22
6
32
Mean
1.67
1.22
1.65
1.50
Mnimum
1.05
1.05
1.31
1.30
Maximum
1.91
1.55
1.66
1.73
Standard deviation
0.28
0.14
0.48
0.16
Bubble-point pressure (psi)
Number of data points
9
9
5
19
Mean
2.272
1,055
3,750
2,752
Minimum
798
450
2,660
1,755
Maximum
4,050
2,600
4,440
4,656
Standard deviation
1.300
689
756
667
Figure 9 - Table of reservoir properties found within the Wristen buildups and platform plays (Ruppel and Holtz, 1994)
-------
Low Perm
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
0
[PLJ]=11036.9
Figure 10 - Rattlesnake AGI ffl open hole log (42-501-36998) with effective porosity (green) and permeability (black)
Formation Fluid
Four wells were identified through a review of chemical analyses of oil-field brines from the U.S. Geological
Survey National Produced Waters Geochemical Database v2.1 within the Devonian, Silurian-Devonian, or
Fusselman formations within 20 miles of the Rattlesnake AGI #1 well. The location of these wells is shown in
Figure 11. Water chemistry analyses conducted on oil-field brines in Gaines County, as reported to the Texas
19
-------
Water Development Board, provided additional data on Devonian and Silurian reservoir fluids. Results from
the synthesis of these two sources are provided in Table 1. The fluids have greater than 20,000 parts per
million ("ppm") total dissolved solids, therefore these aquifers are considered saline. These analyses indicate
the in-situ reservoir fluid of the Devonian, Silurian, and Fusselman formations are compatible with the
proposed injection fluids.
Table 1 - Analysis of Silurian-Devonian age formation fluids from nearby oil-field brine samples
Average
Low
High
Total Dissolved Solids (ppm)
41,428
23,100
55,953
pH
7,2
7.0
7.3
Sodium (ppm)
12,458
7,426
15,948
Calcium (ppm)
1,759
1,010
2,320
Chlorides (ppm)
23,423
12,810
31,930
Fracture Pressure Gradient
Fracture pressure gradient was estimated using Eaton's equation. Eaton's equation is commonly accepted
as the standard practice for the determination of fracture gradients. Poisson's ratio ("v"), overburden
gradient ("OBG"), and pore gradient ("PG") are all variables that can be changed to match the site-specific
injection zone. Through literature review and industry standards, we are able to determine the expected
20
-------
fracture gradient. First, 1.05 psi/ft and 0.465 psi/ft were assumed for both the overburden and pore
gradients, respectively. These values are considered best practice values when there are no site-specific
numbers available. For limestone/dolomite rock, the Poisson's ratio to be assumed to be 0.3 through
literature review (Molina, Vilarras, Zeidouni 2016). Using these values in the equation below, a fracture
gradient of 0.72 psi/ft was calculated. A 10% safety factor was then applied to this number resulting in
maximum allowed bottom hole pressure of 0.64 psi/ft. This was done to ensure that the injection pressure
would never exceed the fracture pressure of the injection zone.
For the upper confining interval, a similar fracture gradient as the limestone was calculated. Shale has an
increased chance to vertically fracture if the injection interval is fractured (Molina, Vilarras, Zeidouni 2016),
so assuming a Poisson's ratio equal to the injection interval was used as a conservative estimate. The lower
confining zone was assumed to be of a similar matrix to that of the injection interval, with the key difference
being that the formation is much tighter (lower porosity/permeability). The Poisson's ratio was assumed to
be slightly higher in this rock. As seen in Table 2, the fracture gradient is slightly higher than the upper zones.
Table 2 - Fracture Gradient Assumptions
Injection Interval
Upper Confining
Lower Confining
Overburden Gradient (psi/ft)
1.05
1.05
1.05
Pore Gradient (psi/ft)
0.465
0.465
0.465
Poisson's Ratio
0.30
0.30
0.31
Fracture Gradient psi/ft
0.72
0.72
0.73
FG +10% Safety Factor (psi/ft)
0.64
0.64
0.66
The following steps were taken to calculate fracture gradient:
FG = —— (OBG - PG) + PG
1 — v
0.3
FG = l_Q3(1.05 - 0.465) + 0.465 = 0.72
FG with SF = 0.72 x (1 - 0.1) = 0.64
Lower Confining Zone - Montoya Formation
The low-permeability Montoya Formation is a tight limestone/dolomite that will act as the lower confining
unit for the injection interval. Figure 10 shows the decreasing trend in porosity of the limestone rock in the
lower section that was not exposed to leaching diagenesis. Porosity in the lower section can range from 2-
3% with permeabilities below 1 millidarcy. The Rattlesnake AGI #1 well drilled 6' into the Montoya formation,
but the section was not logged. The Montoya is anticipated to be roughly 250' thick. These petrophysical
characteristics represent ideal sealing properties to prohibit any migration of injected fluid outside of the
injection interval.
Local Structure
Regional structure in the area of the Rattlesnake AGI #1 well is dictated by carbonate buildups and structural
events causing anticlinal to synclinal features throughout the area. The Rattlesnake AGI #1 well is specifically
located at the base of a syncline with anticlinal features to the northeast, south, and east. Figure 12 is a
21
-------
structure map of the Silurian formation of subsea depths with the star representing the location of the
Rattlesnake AGI #1 well. The red and blue lines represent the cross-section reference lines.
Faulting can be seen to the south and east of the Rattlesnake AGI #1 well location. These faults were
interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure 12. Many of
these faults are minor, with offsets less than 50'. The nearest large fault is found southeast of the Rattlesnake
AGI #1 well and has an offset of roughly 120'. None of these faults project above the Wolfcamp formation,
rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. Production is
associated with a hydrocarbon trap set up by the larger fault to the southeast, indicating the fault is vertically
sealing in nature. If, in the unlikely event the faults' sealing properties are compromised post-injection,
secondary confinement is provided by the tight limestones found within the overlying Mississippian Lime
formation along with shale layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the
largest fault found southeast of the Rattlesnake AGI #1 well terminates within the Atoka formation. Though
it crosses the Silurian section, this fault thrusts the Mississippian Lime upward against the Atoka shales. The
tight reservoir characteristics of the Mississippian Lime and shaley section of the Atoka create a confining
environment vertically and laterally to contain potential upward migration of buoyant fluids. Shales within
the Wolfcamp formation provide additional confining beds between overlying USDWs and the fault plane.
Figures 13 and 14 are north-south and west-east structural cross sections showing the structural dips. As
seen in these figures, the Woodford formation is laterally present above the injection interval, alleviating risk
of erosion of the upper sealant formation.
Larger versions of Figures 12, 13 and 14 are provided in Appendix A.
22
-------
I
5600
M50
5700
5750
5800
5850
5900
•5950
-6000
¦6050
-©100
-6150
-6200
•6250
•6300
•6350
-6400
-6450
-6500
•6550
-6600
•6650
•6700
¦6750
-6800
-€850
•6900
-6950
-7000
-7050
-7100
-7150
-7200
•7250 |
-7300
-7350
-7400
-7450
-7500
•7550
•7600
-7650
-7700
-7750
-7800
-7850
-7900
-7950
-8000
-8050
-8100
-8150
B Any Raster
Figure 12 - Silurian Structure Mop (subsea depths)
23
-------
42501340160000
RANDALL. E
43
EXXON MOBIL
ABOIPU1
VYOLFCAMP IplJ1
Figure 13 - Structural Northeast-Southwest Cross Section
24
-------
42501358340000
ROBERTS UNIT
2
APACHE
a
42501335110000
CORNELL UNIT
3019D
EXXON MOBIL
42501105700000
1-667
TEXAS CRUDE OIL CO
+
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
<-1 n 51 fiFT^,
-------
Injection and Confinement Summary
The Iithologic and petrophysical characteristics of the Faskeri and Fusselman formations at the Rattlesnake
AGI #1 well location indicate the formations have sufficient thickness, porosity, permeability, and lateral
continuity to accept the proposed injection fluids. The Woodford formation shale at the Rattlesnake AGI #1
well has low permeability and is of sufficient thickness and lateral continuity to serve as the upper confining
zone. Beneath the injection interval, the low permeability, low porosity Montoya formation is unsuitable for
fluid migration and serves as the lower confining zone. Deeper, laterally continuous formations, including the
Simpson Group, provide additional confinement.
Groundwater Hydrology
Yoakum County falls within the boundary of the Sandy Land Underground Water Conservation District. Three
aquifers are identified by the Texas Water Development Board's Aquifers of Texas report in the vicinity of the
proposed Rattlesnake AGI #1 well: the Dockum Aquifer, Edwards-Trinity Aquifer, and Ogallala Aquifer
(George, Mace and Petrossian, 2011). Table 3 references the aquifers' positions in geologic time and the
associated geologic formations. A schematic cross section in Figure 15, near the proposed Rattlesnake AGI
#1 well, illustrates the structure and stratigraphy of these water-bearing formations. Groundwater flow
direction is the same for the three aquifers, generally from northwest to southeast, Figure 16 (Teeple, et al.,
2021).
Table 3 - Geologic and hydrogeologic units with accompanying lithologic descriptions near Gaines, Terry and Yoakum Counties, Texas
(Teeple, etal. 2021)
Era
Period
Epoch or series
Geologic unit group
or formation
Lithologic descriptions
Hydrogeologic unit
Cenozoic
Tertiary
Pliocene
Ogallala Formation
Gravel, sand, silt,
and clay
High Plains
aquifer system
(Ogallala aquifer)
Miocene
Mesozoic
Cretaceous1
Comanchean
Series
Washita Group"
Shale and limestone
Ed wards-T rinity
(High Plains)
aquifer system
Fredericksburg Group
Clay, shale, and
limestone
Trinity Group
Sand and gravel
T riassic
Upper
Dockum Group
Siltstone, mudstone,
shale, and sandstone
Dockum aquifer
26
-------
Cretaceous
clay/shale
3,600
3,500
~ 3'400
J3 3,300
£ 3,200
nj 3.100
^ 3,000
2,900
2,800
2.700
Gaines < Yoakum
' *
Terry ! Hockley
B-B1
Lubbock
Ogallala
Formation
Triassic
Dockum Group
Cretaceous Antters Formation
Figure 15 - NW-SE Cross Section of aquifers in the Rattlesnake AGlttl well area (George, Mac and Petrossian, 2011)
27
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•HOCKLfcVCOrXTV B 103^'
33=70'
4IOC'KLE\ CQI'NTV
I /C^a 7 • V •
i• " / 62 \ . # , "
L^Z-HOCKLEY C 01 NT\
ft
I I w r |
33°ai - vbakim V ~' rr-5'-cr) ~
V \ ,/imm A }*!J Uii
jvi- . ' \ ' kchlMtA'
l'
GSS,*f \ ,
y,/ n«uu s y "
WoytMl+ifiL-
r x '< V' \ <'''
i- .Y J ' \ -l
I Denscry«y^~-^s.« Ys— - ^^ 1 ' ^
I. * a / iv'r.i -V%« i1 gi I
D 5 10 IS MILES
i i 11 i1—J
o 5 ra iskmmetbb
Base modified from U S Geological Survey 1 250,000-seals to 1.2,000,000- scale digital data,
Universal rransverne Mercator projection, zone 13
North American Datum of 1983
Groundwater love I altitude, in
feel above North American
Vertical Datum of 1983
¦ >3.750
kiT 3-MO
3,250
3,000
<2,750
I
EXPLANATION
Study area boundary
Edwards-Trinity IHigh Plains! aquifer downdip extent
Underground water conservation district boundary
llano Estacado Underground Water Conservation District
Sandy Land Underground Water Conservation District
South Plaint Underground Water Conservation District
Potantiometric contour Shows attitude at
which water level would have stood in
tightly cased wells. Contour interval i$
100 feet Datum is North American
Vertical Datum of 1968 Dashed where
inferred.
Groundwater low paths - Dashed whero
inferred
Groundwater level measurement I Payne
end others, 2020)
Figure 16 - Potentiometric surfaces from wells completed in A, Ogallala aquifer, B, the Edwards-Trinity aquifer and C, the Dockum
aquifer (George, Mace and Petrossian, 2011).
The Dockum Aquifer is the oldest of the three aquifers, formed from Triassic-age Dockum Group sediments,
and underlies the Cretaceous Trinity and Fredericksburg Groups (Teeple, et al., 2021). Figure 17 shows the
subsurface and outcrop extent of the Dockum Aquifer. As shown in Figure 18, the total dissolved solids in
western Yoakum County exceed 5,000 milligrams per liter ("rrig/L"), therefore the aquifer is considered
brackish.
28
-------
Dockum
Aquifer
Figure 17- Regional extent of the Dockum freshwater aquifer (TWDB)
Figure 18 - Total dissolved solids in groundwater from the Dockum Aquifer (Ewing et at, 2008)
The Edwards-Trinity Aquifer is a collection of Cretaceous age sediments - primarily the Trinity Group Antlers
formation sandstone and limestones of the Fredericksburg Group, specifically the Comanche Peak and
Edwards formations. Figure 19 shows the subsurface and outcrop extent of the Edwards-Trinity Aquifer.
Freshwater infiltration to this aquifer is primarily from the overlying Ogallala Aquifer (George, Mace and
Petrossian, 2011).
29
-------
The Ogallala aquifer consists of sand, gravel, clay and silt sediments (George, Mace and Petrossian, 2011) and
produces the majority of the freshwater for Yoakum County. Figure 19 shows the subsurface and outcrop
extent of the Ogallala Aquifer.
The base of the deepest aquifer is separated from the injection interval by approximately 9,500' of rock,
including 650' of Salado salt. Though unlikely for reasons outlined in the confinement and potential leaks
sections, if migration of injected fluid did occur above the Woodford Shale, thousands of feet of tight
sandstone, limestone, shale, salt and anhydrite beds occur between the injection interval and the lowest
water-bearing aquifer.
30
-------
The TRRC's Groundwater Advisory Unit ("GAU") identified the base of Underground Sources of Drinking
Water ("USDW") at 2,250' at the location of the Rattlesnake AGI #1 well. Therefore, there is approximately
9,470' 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
Rattlesnake AGI #1 well is provided in Appendix B
Description of the Injection Process
Current Operations
The 30-30 Facility and its associated Rattlesnake AGI #1 well began operating in March of 2019. Since
operations began, 258 million cubic feet ("MMCF") of treated acid gas ("TAG") has been injected, which
equates to 12,316 metric tons of C02. Over the life of the injection period, the average daily injection rate
has been 223 MSCF/d. The approximate current composition of the TAG stream is as follows:
Table 4 - Gas Composition of 30-30 Facility outlet
Component
Mol %
1.12%
31
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The 30-30 Facility is designed to compress, treat, and process natural gas produced from the surrounding
counties in Texas and New Mexico. The gas is dehydrated to remove the water content, then processed to
separate natural gas liquids which are then sold, along with the pipeline quality natural gas, to various
customers. TAG is then directly routed from the plant amine regen system to the Rattlesnake AGI #1 well.
The facility is manned 24 hours per day, 7 days per week.
Planned Operations
Stakeholder anticipates increasing the amount of C02 injected into Rattlesnake AGI #1 well from the current
rate up to 16 MMSCF/d. Additional growth is expected both at Stakeholder facilities and regionally as rising
sour gas production and flaring reduction mandates create the need for additional CO2 and H2S disposal
capacity. Stakeholder plans to inject into this AGI well for another 14 years for a total of 17 years from the
start of injection in 2019.
Figure 21 shows a high-level view of the current process flow plus the prospective additional operations over
time.
>96% C02
1,090-1,150 psig
CO, Offtake
13% H2S, 87% C02
Prospective Facilities
Meter
I
er XV
1,400-2,200 psig
|
Amine Regen
AGI 1
*j, 1 ~r
System
Compression |
11 w i
Meter :
~
!_
1
1
£-13% H2S, 87%-
95% C02
1,400-5,900 psig
Injection
Pumps
H£It
S-1
XV
Current Operation
AGI
Well
Figure 21 - 30-30 Facility Process Flow Diagram
Reservoir Characterization Modeling
The modeling software used to evaluate this project was Computer Modelling Group's GEM 2020.11 ("GEM")
simulator. Computer Modelling Group ("CMG") has put together one of the most accurate and technically
sound reservoir simulation software packages for conventional, unconventional, and secondary recovery.
GEM utilizes equation-of-state ("EOS") algorithms along with some of the most advanced computational
methods to evaluate compositional, chemical, and geochemical processes and characteristics to produce
highly accurate and reliable simulation models for carbon injection and storage. The GEM model is
recognized by the EPA for use in area of review delineation modeling as listed in the Class VI Well Area of
Review Evaluation and Corrective Action Guidance document.
The Silurian (Fasken/Fusselman) formation is the target formation for Rattlesnake AGI #1 well. The Petra
software package was used to create the geologic model of the target formation. The faulting and geologic
structure was then imported into GEM and used to create contours for the model grid.
32
-------
Porosity and permeability estimates were determined using the porosity log from the Rattlesnake AGI #1
well and a petrophysical analysis was performed to correlate porosity values by depth with core porosities
as shown in the Holtz paper. The Coates permeability equation was then used to calculate permeability with
depth. Both porosity and permeability are assumed to be laterally homogeneous in the reservoir.
The reservoir is assumed to be at hydrostatic equilibrium and initially saturated with 100% brine. An infinite
acting reservoir was created to simulate boundary conditions. The gas injectate is composed of H2S, C02,
CH4, and other components as shown in Table 5. Core data from literature review was used to determine
residual gas saturation (Ruppel and Holtz, 1994). The modeled composition only takes into consideration the
carbon dioxide and hydrogen sulfide as they comprise nearly 99% of total stream. For the initial injection
period, these compositions are normalized up to 100%. For the proposed additional injection period, it is
expected that a larger portion of the gas added is carbon dioxide, changing the composition to ~93% C02 and
~7% H2S.
Table 5 - Modeled Initial Gas Composition
Measured Current
2019-2024 Model
2024-2036 Model
Component
Composition (mol%)
Composition (mol%)
Composition (mol%)
Carbon Dioxide (C02)
89.678
90.696
92.921
Hydrogen Sulfide (H2S)
9.200
9.304
7.079
Methane (CI)
0.303
0
0
Ethane (C2)
0.058
0
0
Propane (C3)
0.108
0
0
N-Butane (NC4)
0.025
0
0
Hexane Plus (C6+)
0.628
0
0
Core data from literature review was used to determine relative permeability curves between carbon dioxide
and the connate brine within the Silurian-Devonian carbonates (Ruppel and Holtz, 1994). The key inputs
used in the model include an irreducible water saturation of 25% and a maximum residual gas saturation of
21%.
The grid contains 141 blocks in the x-direction (E-W) and 201 blocks in the y-direction (N-S), totaling 28,341
grid blocks per layer. This results in the grid being 21,150' by 30,150' totaling just over a 23-square mile area
(14,640 acres). Each layer in the model was determined by identifying higher permeability zones as targets
for injection from the logs and assigning each high permeability and intermediary low permeability zone its
own layer. One zone was identified as being a karst limestone (layers 2-7). Due to the "karsted" nature of
this rock, it was determined that most of the injectate would flow into this zone. Therefore, the karst
limestone was further split into layers by permeability to provide higher resolution and more accurately
simulate which layer will have the greatest gas flows. Figure 22 provides a detailed breakdown of the
"karsted" rock.
33
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Permeability Distribution of Karst Zone
2
3
4
n:
—i
5
6
7
1 10 100 1000
Permeability (mD)
Figure 22 - Permeability Distribution of Karst Limestone
In total, there are sixteen (16) layers in the model, representing ten (10) layers of pay and six (6) layers of
intermediary low permeability zones. The properties of each of these layers are summarized in Table 6
below.
Table 6 - CMG Model Layer Properties
Layer #
Top (ft)
Thickness (ft)
Permeability (mD)
Porosity
1
11,037
71
1
2.8%
2
11,108
57
47
8.0%
3
11,165
19
223
11.9%
4
11,184
16
15
6.3%
5
11,200
39
70
9.2%
6
11,238
11
228
12.3%
7
11,249
21
49
8.3%
8
11,270
251
2
3.7%
9
11,520
46
9
5.6%
10
11,566
13
3
4.3%
11
11,579
19
17
6.5%
12
11,597
14
2
3.9%
13
11,611
103
13
6.0%
14
11,714
46
2
3.7%
15
11,759
67
23
6.1%
16
11,826
125
2
3.6%
34
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Simulation Modeling
The primary objectives of the model simulation were to:
1) Estimate the maximum areal extent and density drift of the acid gas plume after injection
2) Assess the impact of offset saltwater disposal ("SWD") well injection on density drift of the plume
3) Assess the impact of offset producing wells on the density drift of the plume
4) Determine the ability of the target formation to handle the required injection rate without
fracturing the injection zone
5) Assess the likelihood of the acid gas plume migrating into potential leak pathways
The reservoir is assumed to be an aquifer filled with 100% brine. The salinity of the formation is estimated
to be 53,000 ppm (Texas Water Development Board, 1972). The acid gas stream is primarily composed of
C02 and H2S as stated previously. Core data was used to help generate relative permeability curves. Cores,
from the literature reviews previously discussed, that most closely represent the vuggy carbonate seen in
this region were identified and the Corey-Brooks equations were used to develop the curves. The lowest
residual gas saturation found in the cores was then used for a conservative estimate of plume size. From
offset injection well analysis, the initial reservoir pressure was determined to be 5,132 psi which is equivalent
to a 0.465 psi/ft pressure gradient. The fracture gradient of the injection zone was estimated to be 0.72
psi/ft, which was determined using Eaton's equation. A 10% safety factor was then applied to this number,
putting the maximum bottom-hole pressure allowed in the model at 0.64 psi/ft which is equivalent to 7,064
psi.
The model also takes into account offset saltwater disposal ("SWD") injection volumes within five (5) miles
of the Rattlesnake AGI #1 well. These SWDs create a pressure front that push the plume further up-dip of
the formation. A total of twenty (20) offset wells currently injecting into the target formation were identified.
Eleven (11) of these offset SWDs were out of the confines of the grid, but were still accounted for in the
model. Nine (9) salt-water disposals were modeled within the boundaries of the 23-square-mile grid. Two
(2) of these offset injectors are currently only permitted (not drilled) but were assumed to start active
injection within the first year of the model. Both permits were simulated at the forecasted injection rate
schedule for 30 years. These forecasts were provided by the operators of these wells. Historical injection
rates of each of the other existing wells were analyzed and projected into the model. This simulation includes
the effect of water injection on the density drift of the plume and bottom hole pressure.
Further review of the area revealed production wells in the Silurian-Devonian formation that could impact
the density drift of the plume by creating a "pressure sink". A "pressure sink" is an area of lower pressure
caused by the production of formation fluids. To simulate this effect, nine (9) production wells were grouped
together and their respective production rates combined into a single well to add more conservatism into
the model. These producers were forecasted an additional 15 years to simulate their potential economic
lifespan. This simulation includes the effect of fluid production on the density drift of the plume and bottom
hole pressure. Overall, the "pressure sink" has little effect on the density drift and, as discussed below, the
plume never reaches the producing wells.
The model runs for a total of 814 years, starting in 1965 with the beginning of offset production until the
calculated stabilization of the plume in 2779. The injection of TAG from Rattlesnake AGI #1 is modeled from
the beginning of injection in 2019 through the planned 14 years of future injection. The model also includes
the 57 years of historical plus 15 years of forecasted future oil and gas production.
Additionally, historical monthly injection rates of all nearby SWDs were incorporated into the model to
simulate any additional near-wellbore pressure increase that may occur due to offset injection. The
35
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modelling of the saltwater injection begins in 1984 when the first offset SWD well became operational. The
SWDs to the North were grouped into four (4) separate groups to simulate their combined effect on the
density drift of the plume. All offset injection wells and their groupings are included in Table 7. All offset
production wells are listed in Table 8.
Table 7-All Offset SWDs included in the model
Grouping
API
Well Name
Well#
42-501-32511
SAWYER, DESSIE
1
42-501-02068
WEST, M. M.
2
Group 1
42-501-02053
NORTH CENTRAL OIL CO. "A"
1
42-501-01453
SMITH, EDS. HEIRS "B"
1
42-501-02059
SMITH, ED "C"
1W
Group 2
42-501-30051
JOHNSON
2
42-501-30001
JOHNSON
ID
Group 3
42-501-37066
MISS KITTY SWD 669
1W
42-501-36650
RUSTY CRANE 604
1W
Group 4
42-501-36745
SUNDANCE 642
1
42-501-33887
WINFREY 602
3WD
42-501-37252
Miller SWD
7
42-501-37367
BLONDIE 704
1W
42-501-37206
BRUSHY BILL 707
1WD
42-501-36622
WISHBONE FARMS 710
1W
Standalone
42-501-35834
ROBERTS UNIT
2
42-501-33297
STATE ELMORE
1
42-501-10238
SHEPHERD SWD
1
42-501-33511
CORNELL UNIT
3019D
42-501-32868
WILLARD UNIT
1WD
Table 8 - All Offset Producers included in the model
API
Well Name
Well#
42-501-10046
ELLIOTT, C.A.
2
42-501-10079
RANDALL, E
32
42-501-337932
RANDALL, E
40
42-501-33885
RANDALL, E
41L
42-501-34016
RANDALL, E
43 L
42-501-34017
RANDALL, E.
45 L
42-501-34023
RANDALL, E
42 L
42-501-34024
RANDALL, E
44
42-501-35418
RANDALL, E
46
Rattlesnake AGI #1 came online in 2019 and the model simulated its historical monthly injection rates until
2024. After this initial period, it is conservatively assumed that the injection rate increases to the maximum
permitted rate of 16 MMSCF/d for the remainder of the active injection period in 2036. At this point, the
36
-------
Rattlesnake AGI #1 well stops injection while the offset SWD injectors continue operations for thirty more
years. Density drift then occurs until plume stabilizes, which was determined to be 814 years from the start
of the model in 1965. Stabilization of the plume is determined to occur when the model shows no further
lateral movement horizontally or vertically. The plume boundary is then defined by a weighted average gas
saturation in the aquifer of 3%.
The maximum plume extent during the 17-year Rattlesnake injection period is shown in Figure 23. The final
extent after 743 years of density drift after injection ceases is shown in Figure 24. The extensive time of the
modeled density drift of the plume is driven by the buoyant forces of the gas, the permeability/porosity of
the rock, and the residual gas saturation. Initially, the karsted region takes on most of the injection, but due
to the buoyant forces, it is slowly pushed up higher into the less permeable layers of the injection interval.
These lower permeable layers increase the amount of time it takes for the plume to reach its maximum areal
extent. As all the inputs to the model were based on the most conservative approach, the maximum extent
of the plume will likely be smaller and the effective impact on reaching potential leakage pathways will be
minimal as the amount of C02 at those far extents will be small. Throughout the entirety of the density drift
period the plume does not intersect any likely leakage pathways.
State Elmore
Brushy Bills 707
Shepherd SWD
Rattlesnake AGI Plume
Global Mole Fraction(CQ2) 2036-Jan-0) K Rone: 2 of 16
Group 2 Group 4 Group 3 Group 1
9,170'
Blondie 704
Miller SWD
I
1
i
Rattlesnake AGI
6,452' ] ¦
*¦
S
Willard Unit
~
Roberts Unit
Production Wells
Cornell Unit
Figure 23 -Areal View Gas Saturation Plume, 2036 (End of Injection)
37
-------
Rattlesnake AGI
State Elmore
Brushy Bills 707
Shepherd SWD
Rattlesnake AGI Hume
Global Mole Froctior*(CQ2) 2779-Dec-OI K Plane: 2 of 16
-0.70
¦ -0 60
0.90
-080
Blondie 704
Miller SWD
6,900
Willard Unit
Roberts Unit
Cornell Unit
Group 2
Group 4
Group 3
Group 1
Production Wells
Figure 24 - AreaI View Gas Saturation Plume, 2779 (End of Density Drift)
Figure 25 shows the surface injection rate and bottom hole pressure over the injection period and the period
of density drift after injection ceases. The bottomhoie pressure increases the most as the injection rate
reaches its peak, reaching a maximum pressure of 5,413 psi. This buildup of 280 psi keeps the bottomhoie
pressure well below the fracture pressure of 7,064 psi. The maximum surface pressure associated with the
maximum bottomhoie pressure reached is 2,494 psi.
V
mufii
ipr
C—1
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049 2051 2053 2055
— Rattlesnake AGI, Gas Rate SC - Daily
— Rattlesnake AGI, Well Bottom-hole Pressure
Figure 25 - Well Injection Rate and Bottomhoie Pressure over Time
38
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SECTION 3 - DELINATION OF MONITORING AREA
This section discusses the delineation of Maximum Monitoring Area ("MMA") and Active Monitoring Area
("AMA") as described in EPA 40 CFR §98.448(a)(l).
Maximum Monitoring Area
The MMA is defined as equal to or greater than the area expected to contain the free-phase C02 plume until
the CO2 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 takes into account the
following considerations:
• 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 adequately predict the density drift of the plume
Acid gas injectate was analyzed by a third-party vendor to determine the initial composition used in the
model. The report is provided in Appendix C. The molar composition of the gas is primarily C02 with some
H2S and CH4. The change in molar composition was also incorporated into the model as future predominantly
CO2 streams are added for injection. As discussed in Section 2, the gas was injected into the Silurian
formation, specifically, the Fasken/Fusselman formation. The geomodel was created based off the rock
properties seen in the Fasken/Fusselman.
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 2036, the areal
expanse of the plume will be 1,052 acres. The maximum distance between the wellbore and the edge of the
plume is approximately 0.87 miles to the southeast. After 743 additional years of density drift, the areal
extent of the plume is 2,177 acres with a maximum distance to the edge of the plume of approximately 1.35
miles to the southeast.
Figure 26 shows the plume boundary at the end of injection, the stabilized plume boundary and the MMA.
39
-------
Rattlesnake ACI No. 1
luee Boundary at End of Injection
& Stabilized Plume
with
1/2-Hile Maximun Monitoring Area (MH/
Stakeholder Midstream
Yoakum Co,. TX
PCS: KADB3 TX-NC FIPS 4202 (US 1.)
Drawn ay: ER | Pre: 5/31/2022 | Approved by R1
LONQUIST & CO LLC
+ R«t*sn»kt Ml No. 1 $H I
ile luffer from Mm, Hume E«tent IMMAj
©
I
3
S !
' Plume lousdtry at End of Iryeciion
1 Inch = 0.S1 Mile
0 54 V, X 1
\
m
~
Figure 26 - Plume Boundary at End of Injection, Stabilized Plume Boundary, and Maximum Monitoring Area
Active Monitoring Area
The initial AMA will cover a 14-year monitoring period. This period equates to the time of expected future
injection. The AMA will be established by superimposing the area based on a half-mile buffer around the
anticipated plume location at the end of injection (2036) with the area of the projected free-phase C02 plume
at five additional years (2041). In this case, the plume boundary in 2041 is within the plume at 2036 plus a
half-mile buffer. By 2036 at the latest, a revised MRV will be submitted to define a new AMA. Figure 27 shows
the area covered by the AMA.
40
-------
1 Inch = 0.51 Nile
1:32,000 gj
ffi
fl}
Rattlesnake ACI No. 1
PI use Boundary at End of Injection
& 19-Year PI use
with
l/2-H-ile Active Monitoring Area (AHA)
Stakeholder Midstream
Yoakum Co.. TX
PCS: NAD S3 TX-NC Fl^S 4202 (US Ft.)
Prawn ny. EP | 5; 31 /20: | Apcr:ved by- RH
LtMQUIST t CO LLC
I'liili"!
+ Rct«:-ikt I
ne louadarv *t End of iwj
m
r ~
Figure 27-Active Monitoring Area
41
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SECTION 4 - POTENTIAL PATHWAYS FOR LEAKAGE
This section identifies the potential pathways for C02 to leak to the surface within the MMA and the
likelihood, magnitude and timing of such leakage. The potential leakage pathways are:
• Leakage from surface equipment
• Leakage through existing wells within MMA
• Leakage through faults and fractures
• Natural or Induced Seismicity
• Drilling through the MMA
• Leakage through the confining layer
Leakage from Surface Equipment
The surface facilities at the 30-30 Facility are designed for injecting acid gas containing H2S, and therefore
minimize leakage points such as valves and flanges following industry standards and best practices. H2S gas
detectors are located around the facility and the well site. These gas detectors trigger alarms at 10 parts per
million ("ppm"). Additionally, all Stakeholder field personnel are required to wear H2S monitors which are
triggered at 5 ppm of H2S. A shut-in valve is located at the wellhead and is locally controlled by pressure,
with a high pressure and low pressure shut-off.
The facilities have been designed and constructed with additional safety systems to provide for safe
operations. These systems include Emergency Shutdown ("ESD") valves to isolate portions of the plant and
pipeline, pressure relief valves along the pipeline to prevent over pressurization, and flares to allow piping
and equipment to be de-pressured rapidly under safe and controlled operating conditions in the event of a
leak. Figures 28 and 29 display the facility safety plot plan, taken from the 30-30 H2S Contingency Plan, and
show the location of the H2S monitors in the vicinity of the plant and the Rattlesnake AGI #1 well. Should
Stakeholder construct additional C02 facilities, as indicated in Figure 21, a separate meter will be installed for
the additional stream in order to comply with the 40 CFR §98.448(a)(5) measurement. As this meter will be
in close proximity to the existing facilities, it will utilize the existing monitoring programs discussed previously.
Additionally, C02 monitors will be installed near the new meter and tied into the facility monitoring systems.
42
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Figure 28 - Site Plan, 30-30 Facility
43
-------
With the level of monitoring at the 30-30 Facility and the Rattlesnake AGI #1 well, any release of H2S and C02
would be quickly identified, and the safety systems would quickly minimize the volume of the release. The
CO2 injected into the Rattlesnake AGI #1 is injected with H2S at a concentration of 10% (100,000 ppm). At
this high level of H2S concentration, even a small leakage would trigger personal and facility H2S monitors set
to alarm at 5 ppm and 10 ppm respectively. If any leakage were to be detected, the volume of CO2 released
will 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).
A larger scale version of Figure 27 is provided in Appendix D.
Leakage from Wells in the Monitoring Area
Oil and Gas Operations within Monitoring Area
A significant number of wells have historically been drilled within the area of the Rattlesnake AGI #1 well,
however production has primarily been from the shallower San Andres formation in the Wasson Field. The
San Andres is separated from the Silurian-Devonian interval by 4,720' in this area. In addition to the primary
San Andres production, a few wells have produced from the Wolfcamp The Wolfcamp is separated from the
Siluro-Devonian interval by is 1,800'. Within the projected plume area of the Rattlesnake AGI #1 well, there
are no penetrations of the injection interval. There are ten wells within the MMA that penetrate the
injection interval.
All of the wells which penetrate the injection interval within the MMA were properly cased and cemented to
prevent annular leakage of CO2 to the surface. The plugged wells are also adequately protected against
migration from the Devonian by the placement of the plugs within the wellbores. Additionally, the
Rattlesnake AGI #1 well was designed to prevent migration from the injection interval to the surface through
the casing and cement placed in the well, as shown in Figure 29. Mechanical integrity tests ("MIT") required
under TRRC rules are run annually to verify the well and wellhead can hold the appropriate amount of
pressure. If the MIT were to indicate a leak, the well would be isolated and the leak mitigated quickly to
prevent leakage to the atmosphere.
A map of all wells within the MMA is shown in Figure 30. Figure 31 shows only those wells which penetrate
the injection interval within the MMA. The MMA review maps, a summary of all the wells in the MMA and
detailed wellbore schematics for those wells which penetrate the injection interval are provided in Appendix
D.
44
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4.500' -
5,000- -
5.500' -
Base of USDW@375'
Rustler @ 2,345'
Salado @ 2,443'
Yates @ 3,019'
Seven Rivers @ 3,440' *
dK
Grayburg @ 4,190'
San Andres @ 4,465'
DV Tool @4,275'
DV Tool @5,591'
Glorieta @ 6,316'
Clearfork @ 6,492'
Wichita @ 8,628'
13.000'
13.500'
Upper Wolfcamp @ 9,239'
Strawn @ 10,030'
Atoka @ 10,230*
Woodford @ 10,973'
Devonian @11,036'
Wristen @ 11,268'
Fusselman @ 11,538'
Montoya @ 11,974'
Lr
DV Tool @9,575'
Packer @ 10,966'
TD@ 11,980'
KB:
N/A
BHF:
NA
GL:
3,627'
Spud:
5/27/2018
Casing/Tubing Information
Label
1
2
3
4
Type
Surface
Intermediate
Production
Tubing
OD
13-3/8"
9-5/8"
7"
3-1/2"
Weight
48
40
29
9.2
WT
.330
.395
408
NA
Grade
H40/J55 STC
L- 80 BTC
L80 LTC
2535 Vam Top:
L80 Vam Top:
G3 Vam Top'
Hole Size
17-1/2"
12-1/4"
8 3/4
6"
Depth Set
504'
5,498'
11,014'
10,966'
TOC
Surface
Surface
Surface
NA
Volume
510 sks
2,135 sks
760 sks
NA
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
HOUSTONICALGARY
AUSTIN I WICHITA I DENVER
Stakeholder Midstream
Country: USA
Location: 33.07884, -103.904514
API No: 42-501-36998
Rattlesnake No. 1
State/Province: Texas
Site:
County/Parish: Yoakum
Survey:
Well Type/Status: AGI
Texas License F-9147
RRC District No:
Project No: LS 128
Date: 5/27/2022
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Reviewed: SLP
Approved: SLP
Figure 29 - Rattlesnake AGI ttl Wellbore Schematic
45
-------
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Figure 30 - Oil and Gas Wells within the MMA
46
-------
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RATTLESNAKE AGI NO. 1
38.5613.4891
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Stakeholder Midstream
Yoakum Co., TX
PCS: KADB3 TX-NC FIPS 4202 (US Ft.)
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AJI <4-2-501-—1 SHL Status - Type (Count >
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Figure 31 - Penetrating Oil and Gas Wells within the MMA
47
-------
Future Drilling
Potential leak pathways caused by future drilling in the area are not expected to occur. The deeper
formations, such as the Devonian, have proven to-date to be less productive or non-productive in this area,
which is why the location was selected for injection. Furthermore, any drilling permits issued by the TRRC in
the area of the Rattlesnake AGI #1 well include a list of formations for which oil and gas operators are
required to comply with TRRC Rule 13 (entitled "Casing, Cementing, Drilling, Well Control, and Completion
Requirements"). 16 TAC § 3.13. By way of example, see the Rattlesnake AGI #1 well drilling permit provided
in Appendix B. The Devonian is among the formations listed for which operators in Yoakum County (where
the Rattlesnake #1 is located) are required to comply with TRCC Rule 13 (Appendix B, pg. 5). TRRC Rule 13
requires oil and gas operators to set steel casing and cement across and above all formations permitted for
injection under TRRC Rule 9 or immediately above all formations permitted for injection under Rule 46 for
any well proposed within a one-quarter mile radius of an injection well. In this instance, any new well
permitted and drilled to the Rattlesnake AGI #1 well's injection zone located within a one-quarter mile radius
of the Rattlesnake AGI #1 well will be required under TRRC Rule 13 to set steel casing and cement above the
Rattlesnake AGI #1 well injection zone. Additionally, Rule 13 requires operators to case and cement across
and above all potential flow zones and/or zones with corrosive formation fluids. The TRRC maintains a list of
such known zones by TRRC district and county and provides that list with each drilling permit issued, which
is also shown in the above-mentioned permit in Appendix B.
If any leakage were to be detected, the volume of C02 released will be quantified based on the operating
conditions at the time of release.
Groundwater wells
There are seven groundwater wells located within the MMA, as identified by the Texas Water Development
Board. All of the identified groundwater wells in the area have total depths less than or equal to 265', as
shown in Figure 32 and Table 9. One of the wells is located on the 30-30 facility property with a total depth
of 119'and is operated by Stakeholder.
The surface and intermediate casings of the Rattlesnake AGI #1 well, as shown in Figure 29, are designed to
protect the shallow freshwater aquifers consistent with applicable TRRC regulations and the GAU letter
issued for this location. See GAU letter attached included within Appendix B. The wellbore casings and
cements also serve to prevent CO2 leakage to the surface along the borehole.
48
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to
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Rattlesnake ACI No. 1
Maximum Monitoring Area
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Stakeholder Midstream
Yoakum Co., TX
PCS: NADB3 TX-NC FI=S 4202 Stabilizes Plunt
_ J Plume lousdiry at End of Injection
Abstract
50R0B Groundwater Wetls [TWDB-2G22I
Propcatd U»e :L Bbzkti w.-tti WeH Report Ho J
A Industrial (I)
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We)! Type ¦Ubcfct) wit* State Wei! No.)
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Figure 32 - Groundwater Wells within MMA
49
-------
Table 9 - Groundwater Well Summary
State Well ID
Owner Name
Primary Use Well Depth Data Source
370449
Frances Barbini
Irrigation
237
SDRDB
443840
Frances Jean Barbini
Irrigation
250
SDRDB
482963
Santa Fe Midstream Permian
Industrial
119
SDRDB
510854
FRANCIS BARNINI
Irrigation
255
SDRDB
520249
Thomas Durham
Irrigation
264
SDRDB
543433
FRANCIS BARBIDI
Irrigation
240
SDRDB
84760
TEXACO PRODUCING INC
TWDB BW
Leakage Through Faults or Fractures
Faults were interpreted from roughly 9 square miles of 3D seismic indicated by the purple outline in Figure
12. Faulting in this region terminates vertically below the Pennsylvanian-age rock. Secondary confining
shales within the Wolfcampian and younger strata provide additional, redundant confining layers that would
prevent C02from migrating into freshwater aquifers. None of the mapped faults project above the Wolfcamp
formation; rather, they appear to terminate between the Strawn and base of the Wolfcamp formation. If in
the unlikely event the faults' sealing properties are compromised post-injection, secondary confinement is
provided by the tight limestones found within the overlying Mississippianan Lime formation and the shale
layers found in the Atoka and Wolfcamp formations. As seen in Figure 14, the largest fault found SE of the
Rattlesnake AGI #1 well, terminates within the Atoka formation. Though it crosses the Silurian section, this
fault thrusts the Mississippian Lime upward against the Atoka shales. The tight reservoir characteristics of
the Mississippian Lime and shaley section of the Atoka create a confining environment vertically and laterally
to contain potential upward migration of buoyant fluids. Shales within the Wolfcamp formation provide
additional confining beds between overlying USDWs and the fault plane.
Should an unmapped fault exist within the plume boundary, the offset would be below 3D seismic resolution.
The offset would be less than the thickness of the Woodford shale, juxtaposing the Woodford against itself,
preventing vertical migration.
Fractures and subsequent subaerial exposure are responsible for porosity development within the injection
intervals. Open hole logs show little to no porosity development indicating the Woodford or Mississippian
Lime were not exposed at this location. Upward migration of injected gas through confining bed fractures is
unlikely.
50
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Leakage Through Confining Layers
The Silurian-Devonian injection zones have competent sealing rocks above and below the porous sub-aerially
exposed carbonate. The properties of the overlying transgressive Woodford shale (widespread deposition,
high illite clay and organic matter composition, and low porosity and permeability) make an excellent sealing
rock to the underlying Silurian formation. Tight Mississippian Lime of roughly 660', lay between Atoka and
Woodford shale formations, forming an impermeable upper seal to the injection interval. Above this
confining unit, correlative shales of the Wolfcamp, Abo and Tubb formations will prevent any upper fluid
migration. These impermeable shales are capped by hundreds of feet of the regionally present Salado
formation evaporites. The USDW lies above the sealing properties of the formations outlined above, making
stratigraphic migration of fluids into the USDW highly unlikely. The underlying low porosity and permeability
Montoya carbonate minimizes the likelihood of downward migration of injected fluids. The relative
buoyancy of injected gas to the in-situ reservoir fluid makes migration below the lower confining layer
unlikely.
Leakage from Natural or Induced Seismicitv
The location of Rattlesnake AGI #1 is in an area of the Permian Basin that is inactive from a seismicity
perspective, whether induced or natural. A review of historical seismic events on the USGS's Advanced
National Seismic System site (from 1971 to present) and the Bureau of Economic Geology's TexNet catalog
(from 2017 to present), as shown in Figure 33, indicates the nearest seismic event occurred more than 60
miles away.
A regional analysis of the probabilistic fault slip potential across the Permian Basin (Snee & Zoback 2016), as
seen in Figure 34, further demonstrates that the Rattlesnake AGI #1 well is located in a seismically inactive
area and confirms that this area has little to no potential for an induced seismicity event.
Therefore, there is no indication that seismic activity poses a risk for loss of CO2 to the surface within the
MMA.
51
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Cctclir 3M '
LaveHand Lubbock
LI A NO ES 7 ACA 0 O
(STAKED Pi. A IN!
Figure 33 - Seismicity Review (TexNet - 06/01/2022)
52
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Dagger
Draw
field
\ Living
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5wfing
m ^ ^taSbersor?
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Figure 34 - Probabilistic Fault Slip Potential Analysis with Rattlesnake AGI #1 location (Snee & Zobak 2016)
53
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SECTION 5 - MONITORING FOR LEAKAGE
This section discusses the strategy that Stakeholder 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). 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. Table 8 summarizes the
monitoring of potential leakage pathways to the surface. Monitoring will occur during the planned 25-year
injection period, or cessation of injection operations, plus a proposed 5-year post-injection period.
• Leakage from surface equipment
• Leakage through existing and future wells within MMA
• Leakage through faults and fractures
• Leakage through the confining layer
• Leakage through natural or induced seismicity
Because the acid gas injection stream also contains H2S, any leakage would be detected by the H2S alarms
located around the facility and would be quickly addressed which would minimize the release of C02 into the
atmosphere.
Table 10 - Summary of Leakage Monitoring Methods
Leakage Pathway
Monitoring Method
Leakage from surface equipment
Fixed H2S monitors throughout the AGI facility
Daily visual inspections
Personal H2S monitors
Distributed Control System Monitoring (Volumes and Pressures)
Leakage through existing wells
Fixed H2S monitor at the AGI well
SCADA Continuous Monitoring at the AGI Well
Annual Mechanical Integrity Tests ("MIT") of the AGI Well
Visual Inspections
Quarterly C02 Measurements within AMA
Leakage through groundwater wells
Annual GroundwaterSamples on Property
Leakage from future wells
H2S Monitoring during offset drilling operations
Leakage through faults and fractures
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage through confining layer
SCADA Continuous Monitoring at the AGI Well (volumes and pressures)
Fixed In-field H2S monitors
Leakage from natural or induced
seismicity
Seismic monitoring station to be installed
54
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Leakage from Surface Equipment
As the 30-30 Facility and the Rattlesnake AGI #1 well are designed to handle H2S, leakage from surface
equipment is unlikely to occur and would be quickly detected and addressed. The facility design minimizes
leak points through the equipment used and the type of connections are designed to minimize corrosion
points. The H2S in the injectate serves as a proxy for the release of C02. The facility and well site contain a
number of H2S alarms, set with a high alarm setpoint of 10 ppm of H2S, which are shown in Figure 28above.
Additionally, all Stakeholder field personnel are required to wear H2S monitors, which trigger the alarm at 5
ppm H2S.
The AGI facility is continuously monitored through automated systems. In addition, field personnel conduct
daily visual field inspections of gauges, monitors and leak indicators such as vapor plumes. The effectiveness
of the internal and external corrosion control program is monitored through the periodic inspection of the
system, analysis of liquids collected from the line, and inspection of the cathodic protection system. These
inspections, in addition to the automated systems, allow Stakeholder to quickly respond to any leakage
situation. Monitoring will occur for the duration of injection and the post-injection period. 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).
Leakage from Existing and Future Wells within Monitoring Area
Stakeholder continuously monitors and collects injection volumes, pressures, temperatures and gas
composition data, through their SCADA systems, for the Rattlesnake AGI #1 well. This data is reviewed by
qualified personnel and will follow response and reporting procedures when data is outside acceptable
performance limits. Rattlesnake AGI #1 has a pressure and temperature gauge placed in the injection stream
at its wellhead, and a pressure gauge on the casing annulus. A change of pressure on the annulus would
indicate the presence of a possible leak. Mechanical integrity tests ("MITs") performed annually would also
indicate the presence of a leak. Upon a negative MIT, the well would immediately be isolated and the leak
mitigated.
The ten offset penetrating wells within the MMA are adequately cased and cemented to prevent potential
leakage of CO2 from the Rattlesnake AGI #1 well plume. Additionally, the plugged wells were done so in a
way to prevent migration of CO2 as provided in Appendix E. As discussed previously, Rule 13 would ensure
that new wells in the field would be constructed in a manner to prevent migration from the injection interval.
In addition to the fixed and personal monitors described previously, Stakeholder will also establish and
operate an in-field monitoring program to detect any C02 leakage within the AMA. The scope of work will
include H2S and C02 monitoring at the AGI well site as well as minimum, quarterly atmospheric monitoring
near identified penetrations within the AMA. Upon approval of the MRV and through the post-injection
monitoring period, Stakeholder will have these monitoring systems in place. Additional monitoring will be
added as the AMA is updated over time.
Groundwater Quality Monitoring
Stakeholder will monitor the groundwater quality in fluids above the confining interval by sampling the well
on the facility property and analyzing the sample with a third-party laboratory on an annual basis. Any
significant changes to the water analysis would be investigated to determine if such change was a result of
leakage from the Rattlesnake AGI #1 well.
55
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Leakage through Faults. Fractures or Confining Seals
Stakeholder continuously monitors the operations of the Rattlesnake AGI #1 well through automated
systems. Any deviation from normal operating conditions indicating movement into a potential pathway
such as a fault or breakthrough of the confining seal would trigger an alert. Any such alert would be reviewed
by field personnel and action taken to shut in the well, if necessary. Field H2S monitoring systems would alert
field personnel for any release of H2S/CO2 caused by such leakage.
Leakage through Natural or Induced Seismicitv
While the likelihood of a natural or induced seismicity event is extremely low, Stakeholder plans to install a
seismic monitoring station in the general area of the Rattlesnake AGI #1 well. This monitoring station will be
tied in to the Bureau of Economic Geology's TexNet Seismic Monitoring system. If a seismic event of 3.0
magnitude or greater is detected, Stakeholder will review the injection volumes and pressures at the
Rattlesnake AGI #1 well to determine if any significant changes occur that would indicate potential leakage.
56
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SECTION 6- BASELINE DETERMINATIONS
This section identifies the strategies Stakeholder will undertake to establish the expected baselines for
monitoring C02 surface leakage per 40 CFR §98.448(a)(4). Stakeholder will use the existing SCADA monitoring
systems to identify changes from expected performance that may indicate leakage of C02.
Visual Inspections
Daily inspections will be conducted by field personnel at the 30-30 Facility and the Rattlesnake AGI #1 well.
These inspections will aid with identifying and addressing issues timely to minimize the possibility of leakage.
If any issues are identified, such as vapor clouds or ice formations, corrective actions would be taken to
address such issues.
H2S Detection
H2S will be initially injected into the AGI well at a concentration of approximately ten (10) percent or 100,000
ppm. The concentration will drop to approximately six (6) percent as additional volumes are added. H2S gas
detectors are located throughout the AGI facility and well site and are set to trigger the alarm at 10 ppm.
Additionally, all field personnel are required to wear personal H2S monitors, which are set to trigger the alarm
at 5 ppm. Any alarm would trigger an immediate response to protect personnel and verify that the monitors
are working properly. If monitors are working correctly, immediate actions would be taken to secure the
facility and mitigate potential leaks.
CO2 Detection
Any C02 release would be accompanied by H2S and therefore the H2S monitors at the facility would also serve
as a C02 release warning system. In addition to the fixed and personal monitors described previously,
Stakeholder will also establish and operate an in-field monitoring program to detect any C02 leakage within
the AMA. The scope of work will include H2S and C02 monitoring at the AGI well site as well as atmospheric
monitoring near identified penetrations within the AMA.
Operational Data
Upon starting injection operations, baseline measurements of injection volumes and pressures will be taken.
Any significant deviations over time will be analyzed for indication of leakage of C02.
Continuous Monitoring
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as per Texas regulations and Stakeholder's TRRC-
approved H2S Contingency Plan. Gas detectors and continuous monitoring systems would trigger an alarm
upon a release. The mass of the C02 released would be calculated for the operating conditions at the time,
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.
57
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No C02 emissions will occur from venting because of the high H2S concentrations. Blowdown emissions are
sent to flares and would be reported as part of the required reporting for the gas plant.
Groundwater Monitoring
An initial sample will be taken from the groundwater well on Stakeholder's property, identified as Well #
482963 in Table 9 above, upon approval of Stakeholder's MRV and prior to increasing injection. The sample
will be analyzed by a third-party laboratory to establish the baseline properties of the groundwater.
58
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SECTION 7 - SITE SPECIFIC CONSIDERATIONS FOR MASS BALANCE
EQUATION
This section identifies how Stakeholder will calculate the mass of C02 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).
Mass of CO2 Received
Per 40 CFR §98.443, the mass of C02 received must be calculated using the specified C02 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 subpartto calculate C02 received."
The CO2 received for this injection well is wholly injected and not mixed with any other supply and the annual
mass of C02 injected will equal the amount received. Any future streams would be metered separately before
being combined into the calculated stream.
Mass of CO2 Injected
Per 40 CFR §98.444(b), since the flow rate of C02 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 C02
concentration in the flow according to Equation RR-4:
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u
QP,u = Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons per quarter)
Cco2,P,u = Quarterly C02 concentration measurement in flow for flow meter u in quarter p (wt. percent
CO2, expressed as a decimal fraction)
p = Quarter of the year
u = Flow meter
4
p = 1
where:
59
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Mass of CO2 Produced
The Rattlesnake AGI #1 well is not part of an enhanced oil recovery project; therefore, no C02 will be
produced.
Mass of CO2 Emitted by Surface Leakage
Mass of C02 emitted by surface leakage and equipment leaks will not be measured directly as the injection
stream for this well contains H2S which would be extremely dangerous for personnel to perform a direct leak
survey. Any leakage would be detected and managed as a major upset event. Gas detectors and continuous
monitoring systems would trigger an alarm upon a release. The mass of the C02 released would be calculated
for the operating conditions at the time, 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 as a result 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:
C02 = 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 from subpart W will be used to calculate C02 emissions from equipment located on
the surface between the flow meter used to measure injection quantity and the injection wellhead
Mass of CO2 Sequestered
The mass of C02 sequestered in subsurface geologic formations will be calculated based off Equation RR-12,
as this well will not actively produce oil or natural gas or any other fluids, as follows:
X
X=1
Where:
C02 — C02i C02e C02f
Where:
60
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C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year
CO21 = Total annual C02 mass injected (metric tons) in the well or group of wells 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 2F1 - 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 reporting of GHGs. Because no venting would occur
due to the high H2S concentrations of the injectate stream, the calculations would be based on the blowdown
emissions that would be sent to flares and would be reported as part of the required GHG reporting for the
gas plant.
• Calculation methods from subpart W will be used to calculate C02emissions from equipment located
on the surface between the flow meter used to measure injection quantity and the injection
wellhead.
61
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SECTION 8 - IMPLEMENTATION SCHEDULE FOR MRV PLAN
The Rattlesnake AGI #1 well currently reports GHGs under Subpart UU, but Stakeholder has elected to submit
an MRV plan under, and otherwise comply with, Subpart RR. The MRV plan will be implemented upon
receiving EPA approval. The Annual Subpart RR Report will be filed on March 31st of the year following the
reporting year.
62
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SECTION 9 - QUALITY ASSURANCE
This section identifies how Stakeholder plans to manage quality assurance and control, to meet the
requirements of 40 CFR §98.444.
Monitoring QA/QC
CO 2 Injected
• The flow rate of the C02 being injected will be measured with a volumetric flow meter, consistent
with industry best practices. These flow rates will be compiled quarterly.
• The composition of the C02 stream will be measured upstream of the volumetric flow meter with a
continuous gas composition analyzer or representative sampling consistent with industry best
practices.
• The gas composition measurements of the injected stream will be averaged quarterly.
• The CO2 measurement equipment will be calibrated according to manufacturer recommendations.
C02 Emissions from Leaks and Vented Emissions
• Gas detectors will be operated continuously, except for maintenance and calibration.
• Gas detectors will be calibrated according to manufacturer recommendations and API standards.
• Calculation methods from subpart W will be used to calculate C02emissions 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 the requirements in 40 CFR §98.3(i).
• Flow meters will be operated per an appropriate standard method as published by a consensus-
based standards organization.
• Flow meter calibrations will be traceable to the National Institute of Standards and Technology
(NIST).
All measured volumes of C02 will be converted to standard cubic meters at a temperature of 60 degrees
Fahrenheit and an absolute pressure of 1 atmosphere.
Missing Data
In accordance with 40 CFR §98.445, Stakeholder 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 C02 injected is missing, the amount will be estimated using a representative
quantity of C02 injected from the nearest previous period of time at a similar injection pressure.
• Fugitive C02 emissions from equipment leaks from facility surface equipment will be estimated and
reported per the procedures specified in subpart W of 40 CFR §98.
63
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MRV Plan Revisions
If any of the changes outlined in 40 CFR §98.448(d) occur, Stakeholder will revise and submit an amended
MRV plan within 180 days to the Administrator for approval.
64
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SECTION 10 - RECORDS RETENTION
Stakeholder will retain records as required by 40 CFR §98.3(g). These records will be retained for at least
three years and include:
• 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 C02 stream
• Annual records of the information used to calculate the C02 emitted by surface leakage from leakage
pathways.
• Annual records of information used to calculate C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
65
-------
References
Broadhead, Ronald E., 2005. Regional Aspects of the Wristen petroleum system, southeastern New Mexico:
New Mexico Bureau of Geology and Mineral Resources Open File Report, no. 485.
Comer, John B., 1991. Stratigraphic Analysis of the Upper Devonian Woodford Formation, Permian Basin,
West Texas and Southeastern New Mexico: Bureau of Economic Geology Report of Investigations, no. 201.
George, Peter G., Mace, Robert E., and Petrossian, Rima, 2011. Aquifers of Texas: Texas Water Development
Board Report, no 380.
Hoak, T., Sundberg, K., and Ortoleva, P. Overview of the Structural Geology and Tectonics of the Central Basin
Platform, Delaware Basin, and Midland Basin, West Texas and New Mexico: Department of Energy Open File
Report.
Molina, Oscar, Vilarras, Victor, and Zeidouni, Mehdi, 2016. Geologic carbon storage for shale gas recovery:
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18.
Ruppel, Stephen C. and Holtz, Mark H., 1994. Depositional and Diagenetic Facies Patterns and Reservoir
Development in Silurian and Devonian Rocks of the Permian Basin: Bureau of Economic Geology Report of
Investigations, no. 216.
Snee, Jens-Erik Lund and Zoback, Mark D., 2016. State of stress in the Permian Basin, Texas and New Mexico:
Implications for induced seismicity.
Teeple, Andrew P., Ging, Patricia B., Thomas, Jonathan V., Wallace, David S., and Payne, Jason D., 2021.
Hydrogeologic Framework, Geochemistry, Groundwater-Flow System, and Aquifer Hydraulic Properties Used
in the Development of a Conceptual Model of the Ogallala, Edwards-Trinity (High Plains), and Dockum
Aquifers In and Near Gaines, Terry, and Yoakum Counties, Texas: USGS Scientific Investigations Report 2021-
5009.
66
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APPENDICES
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APPENDIX A-GEOLOGY
APPENDIX A-l: SILURIAN STRUCTURE MAP
APPENDIX A-2: NE-SW CROSS SECTION
APPENDIX A-3: NW-SE CROSS SECTION
-------
-------
mi
LONQU 1ST
SEQUESTRATION L
Stakeholder Midstream
-------
42501105700000
1-667
TEXAS CRUDE OIL CO
42501358340000
ROBERTS UNIT
2
APACHE
<14,201 FT>
42501369980000
RATTLESNAKE AG I
1
STAKEHOLDER GAS SERVICES
-------
APPENDIX B - TRRC FORMS Rattlesnake AG I #1
APPENDIX B-l: UIC CLASS II ORDER
APPENDIX B-2: GAU GROUNDWATER PROTECTION DETERMINATION
APPENDIX A-3: DRILLING PERMIT
APPENDIX A-4: COMPLETION REPORT
-------
Christi Craddick, Chairman
Ryan Sitton, Commissioner
Wayne Christian, Commissioner
B-1
Danny Sorrells
Assistant Executive Director
Director, Oil and Gas Division
Leslie Savage
Assistant Director, Technical Permitting
Railroad Commission of Texas
OIL AND GAS DIVISION
PERMIT TO DISPOSE OF NON-HAZARDOUS OIL AND GAS WASTE BY INJECTION INTO A
POROUS FORMATION NOT PRODUCTIVE OF OIL AND GAS
PERMIT NO. 15848
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024
DOCKET NO. 8A-0312019
Authority is granted to inject Non-Hazardous Oil and Gas waste into the well identified herein in accordance
with Statewide Rule 9 of the Railroad Commission of Texas and based on information contained in the
application (Form W-14) dated March 12, 2018 for the permitted interval of the DEVONIAN formation and
subject to the following terms and special conditions:
RATTLESNAKE AGI (000000) LEASE
WASSON FIELD
YOAKUM COUNTY, DISTRICT 8A
WELL II
DENTIFIC ATION AND P]
ERMIT PA]
RAMET]
ERS:
Well No.
API No.
UIC Number
Permitted
Fluids
Top
Interval
(feet)
Bottom
Interval
(feet)
Maximum
Liquid
Daily
Injection
Volume
(BBL/day)
Maximum
Gas Daily
Injection
Volume
(MCF/day)
Maximum
Surface
Injection
Pressure
for Liquid
(PSIG)
Maximum
Surface
Injection
Pressure
for Gas
(PSIG)
1
50136998
000117143
C02, and
H2S
11,000
12,000
4,500
N/A
N/A
2,200
SPECIAL CONDITIONS:
Well No.
API No.
Special Conditions
1
50136998
1. Open hole completions shall have a plug back depth no deeper than the bottom of the
permitted injection interval.
2. The operator shall provide to the UIC section an annotated electric log, and a mud log if
available, of the subject well with the top(s) and bottom(s) of the permitted formation
indicated on the log. Top and bottom of the authorized injection interval may be modified
based on electric log or mud log indications of the top and bottom of the permitted
formations.
1701 NORTH CONGRESS AVENUE * POST OFFICE BOX 12967 * AUSTIN. TEXAS 78711-2967 * PHONE: 512/463-6792* FAX: 512/463-6780
TDD 800/735-2989 OR TDY 512/463-7284 * AN EQUAL OPPORTUNITY EMPLOYER* http://www.rrc.texas.gov
-------
STANDARD CONDITIONS:
1. Injection must be through tubing set on a packer. The packer must be set no higher than 100 feet above the
top of the permitted interval.
2. The District Office must be notified 48 hours prior to:
a. running tubing and setting packer;
b. beginning any work over or remedial operation;
c. conducting any required pressure tests or surveys.
3. The wellhead must be equipped with a pressure observation valve on the tubing and for each annulus.
4. Prior to beginning injection and subsequently after any work over, an annulus pressure test must be
performed. The test pressure must equal the maximum authorized injection pressure or 500 psig, whichever
is less, but must be at least 200 psig. The test must be performed, and the results submitted in accordance
with the instructions of Form H-5.
5. The injection pressure and injection volume must be monitored at least monthly and reported annually on
Form H-10 to the Commission's Austin office.
6. Within 30 days after completion, conversion to disposal, or any work over which results in a change in well
completion, a new Form W-2 or G-l must be filed to show the current completion status of the well. The
date of the disposal well permit, and the permit number must be included on the new Form W-2 or G-l.
7. Written notice of intent to transfer the permit to another operator by filing Form P-4 must be submitted to
the Commission at least 15 days prior to the date of the transfer.
8. This permit will expire when the Form W-3, Plugging Record, is filed with the Commission. Furthermore,
permits issued for wells to be drilled will expire three (3) years from the date of the permit unless drilling
operations have commenced.
Provided further that, should it be determined that such injection fluid is not confined to the approved interval, then
the permission given herein is suspended and the disposal operation must be stopped until the fluid migration from
such interval is eliminated. Failure to comply with all of the conditions of this permit may result in the operator
being referred to enforcement to consider assessment of administrative penalties and/or the cancellation of the
permit.
APPROVED AND ISSUED ON November 14. 2018.
Injection-Storage Permits Unit
IN-HOUSE AMENDMENT TO CORRECT THE RATE.
Note: This document will only be distributed electronically.
PERMIT NO. 15848
Page 2 of 2
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GROUNDWATER PROTECTION DETERMINATION
Groundwater Advisory Unit
Form GW-2
B-2
Date Issued:
31 August 2017
GAU Number:
179154
Attention:
SANTA FE MIDSTREAM
API Number:
5700 GRANITE PARKWAY
County:
YOAKUM
PLANO, TX 75024
Lease Name:
Roberts Unit
Operator No.:
748093
Lease Number:
Well Number:
Total Vertical Depth:
Latitude:
Longitude:
Datum:
019212
1
11000
33.049990
-102.903464
NAD27
Purpose:
New Drill
Location:
Survey-Gibson, J H/Poole, J T; Block-D; Section-733
To protect usable-quality groundwater at this location, the Groundwater Advisory Unit of the Railroad Commission of
Texas recommends:
The interval from the land surface to a depth of 375 feet must be protected.
Note: Unless stated otherwise, this recommendation is intended to apply only to the subject well and not for area-wide use.
This recommendation is for normal drilling, production, and plugging operations only. It does not apply to saltwater disposal
operation into a nonproductive zone (RRC Form W-14).
This determination is based on information provided when the application was submitted on 08/30/2017. 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.gov
Rev. 02/2014
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APINa 42-501-36998
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
APPLICATION FOR PERMIT TO DRILL, RECOMPLETE, OR RE-ENTER
This facsimile W-l was generated electronically from data submitted to the RRC.
A certification of the automated data is available in the RRC's Austin office.
FORM W-l 07/2004
Drilling Permit #
839303
SWR Exception Case/Docket No.
Permit Status: Approved
B-3
1. RRC Operator No.
748093
2. Operator's Name (as shown on form P-5, Organization Report)
SANTA FE MIDSTREAM PERMIAN LLC
3. Operator Address (include street, city, state, zip):
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
4. Lease Name
RATTLESNAKE AGI
5. Well No.
1
GENERAL INFORMATION
6. Purpose of filing (mark ALL appropriate boxes): Ix] New Drill EH Recompletion EH Reclass EH Field Transfer EH Re-Enter
EH Amended EH Amended as Drilled (BHL) (Also File Form W-1D)
7. Wellbore Profile (mark ALL appropriate boxes): 0 Vertical EH Horizontal (Also File Form W-1H) EH Directional (Also File Form W-1D) EH Sidetrack
8. Total Depth
12000
9. Do you have the right to develop the [x] - | |
minerals under any right-of-way ?
10. Is this well subject to Statewide Rule 36 (hydrogen sulfide area)? IS Yes EH \0
SURFACE LOCATION AND ACREAGE INFORMATION
11. RRC District No.
8A
12. County I—, ,—, ,—, ,—¦
YOAKUM 13. Surface Location LXI Land 1—1 Bay/Estuary 1—1 Inland Waterway 1—1 Offshore
14. This well is to be located miles in a NW direction from DENVER CITY which is the nearest town in the county of the well site.
15. Section 16. Block 17. Survey 18. Abstract No.
733 D GIBSON, J H A-89
19. Distance to nearest lease line:
200 ft-
20. Number of contiguous acres in
lease, pooled unit, or unitized tract: 640
21. Lease ]
22. Survey
'erpendiculars: 200 ft from the NORTH line and 200 ft froi
nt
nt
ie WEST line.
PprppiiHii^iilars" 200 ft from the NORTH line and 200 ft froi
le WEST line.
23. Is this a pooled unit? EH Yes B No 24. Unitization Docket No:
25. Are you applying for Substandard Acreage Field? EH Yes (attach Form W-1A) S No
FIELD INFORMATION List all fields of anticipated completion including Wildcat. List one zone per line.
26. RRC
District No.
27. Field No.
28. Field Name (exactly as shown in RRC records)
29. Well Type
30. Completion Depth
31. Distance to Nearest
Well in this Reservoir
32. Number of Wells on
this lease in this
Reservoir
8A
95397001
WASSON
Injection Well
12000
0.00
1
8A
95399400
WASSON, NORTH (SAN ANDRES)
Injection Well
12000
0.00
1
BOTTOMHOLE LOCATION INFORMATION is required for DIRECTIONAL, HORIZONTAL, AND AMENDED AS DRILLED PERMIT APPLICATIONS
Remarks
[FILER Apr 16, 2018 5:16 PM]: Filing for an acid gas injection well.
Certificate:
I certify that information stated in this application is true and complete, to the
best of my knowledge.
Jessica Risien, Regulatory Compliance
Specialist Apr 25, 2018
Name of filer Date submitted
(281)8729300 jrisien@ntglobal.com
Phone E-mail Address (OPTIONAL)
RRC Use Only Data Validation Time Stamp: Apr 27, 2018 10:36 AM( As Approved' Version )
Page 1 of 1
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NOTE: Acreages shown hereon ere based on Information provided by others.
This plat represents a staked well location and does not represent a boundary survey.
The Information shown does not meet the current TBPLS minimum standards for boundary
surveys. Limited field measurements were acquired. Lease and tract line Information is
compiled from record information and additional sources.
NOTES:
1)
2)
3-J
ALL BEARINGS. DISTANCES ANO COORDINATES SHOWN
HEREON WERE DERIVED FROM <3. P S. OBSERVATIONS
CONVERTED TO THE TEXAS COORDINATE SYSTEM,
NORTH CENTRAL ZONE (NAD 1993). US FOOT AND ARE
REFERENCED TO THE LOCAL GNSS RTK NETWORK.
THE PROPOSED WELL LOCATION IS SITUATED N 37~W -
7.3 MILES FROM DENVER CITY, TX.
THE PROPOSED WELL LOCATION IS SITUATED SOW FROM
THE NSL AND 200 FROM THE WSL.
6
5°X'
rC-< liw
SECTION 704. BLOCK D
J. H. GIBSON SURVEY-
ABSTRACT NO. 1144
YOAKUM COUNTY. TX
704
733
RA TTLESMAKE AGf No.
(PROPOSED)
.0^
SURFACE L OCA T/ON
NAD 83, TX-NC, U.S. FT.
NORTH/NG/Y; 7093713.4ST
EASTING/X 619409-13"
LATITUDE (DDJ- 33.05134722°
LONGITUDE (DO)- -102.90450555*
NAD 27, TX-NC, US- FT,
NORTHfNG/Y: 546285.34*
EAST/NG/X; 344968.61'
LA TTTUDE (DO)- 33.05124473"
LONGITUDE (DO)- -102.90401331°
SURFACEELEVA T/ON- 3627.05-
732
*
83^8
2
5>^0
S
Af /=>&?AfMA/LLG
rtATTL£SA/j4/C£-s4G/A/o. 7
*/.M. G/&SOA/ SURWEK
SEGT/OA/ 733, &LOC/C0
yOAKt/AS GCHSA/TX TjEXAS
m Y aHcmws80i*a,7x:7B>
IhtebkityRk
i ] Positions, llc
-------
Railroad Commission of Texas
PERMIT TO DRILL, RE-COMPLETE, OR RE-ENTER ON REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
CONDITIONS AND INSTRUCTIONS
Permit Invalidation. It is the operator's responsibility to make sure that the permitted location complies with Commission density and
spacing rules in effect on the spud date. The permit becomes invalid automatically if, because of a field rule change or the drilling of another
well, the stated location is not in compliance with Commission field rules on the spud date. If this occurs, application for an exception to
Statewide Rules 37 and 38 must be made and a special permit granted prior to spudding. Failure to do so may result in an allowable not being
assigned and/or enforcement procedures being initiated.
Notice Requirements. Per H.B 630, signed May 8,2007, the operator is required to provide notice to the surface owner no later than the
15th business day after the Commission issues a permit to drill. Please refer to subchapter Q Sec. 91.751-91.755 of the Texas Natural
Resources Code for applicability.
Permit expiration. This permit expires two (2) years from the date of issuance shown on the original permit. The permit period will not
be extended.
Drilling Permit Number. The drilling permit number shown on the permit MUST be given as a reference with any notification to the
district (see below), correspondence, or application concerning this permit.
Rule 37 Exception Permits. This Statewide Rule 37 exception permit is granted under either provision Rule 37 (h)(2)(A) or 37(h)(2)(B).
Be advised that a permit granted under Rule 37(h)(2)(A), notice of application, is subject to the General Rules of Practice and Procedures
and if a protest is received under Section 1.3, "Filing of Documents," and/or Section 1.4, "Computation of Time," the permit may be deemed
invalid.
Before Drilling
Fresh Water Sand Protection. The operator must set and cement sufficient surface casing to protect all usable-quality water, as defined by
the Railroad Commission of Texas (RRC) Groundwater Advisory Unit (GWAU). Before drilling a well, the operator must obtain a letter from
the Railroad Commission of Texas stating the depth to which water needs protection, Write: Railroad Commission of Texas, Groundwater
Advisory Unit (GWAU), P.O. Box 12967, Austin, TX 78711-3087. File a copy of the letter with the appropriate district office.
Accessing the Well Site. If an OPERATOR, well equipment TRANSPORTER or WELL service provider must access the well site from a
roadway on the state highway system (Interstate, U.S. Highway, State Highway, Farm-to-Market Road, Ranch-to-Market Road, etc.), an
access permit is required from TxDOT. Permit applications are submitted to the respective TxDOT Area Office serving the county where the
well is located.
Water Transport to Well Site. If an operator intends to transport water to the well site through a temporary pipeline laid above
ground on the state's right-of-way, an additional TxDOT permit is required. Permit applications are submitted to the respective
TxDOT Area Office serving the county where the well is located.
^NOTIFICATION
The operator is REQUIRED to notify the district office when setting surface casing, intermediate casing, and production casing, or when
plugging a dry hole. The district office MUST also be notified if the operator intends to re-enter a plugged well or re-complete a well into a
different regulatory field. Time requirements are given below. The drilling permit number MUST be given with such notifications.
During Drilling
Permit at Drilling Site : A copy of the Form W-l Drilling Permit Application, the location plat, a copy of Statewide Rule 13
alternate surface casing setting depth approval from the district office, if applicable, and this drilling permit must be kept at the
permitted well site throughout drilling operations.
*Notification of Setting Casing : The operator MUST call in notification to the appropriate district office (phone number shown the
on permit) a minimum of eight (8) hours prior to the setting of surface casing, intermediate casing, AND production casing. The
individual giving notification MUST be able to advise the district office of the drilling permit number.
*Notification of Re-completion/Re-entry : The operator MUST call in notification to the appropriate district office (phone number
shown on permit) a minimum of eight (8) hours prior to the initiation of drilling or re-completion operations. The individual giving
notification MUST be able to advise the district office of the drilling permit number.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 1 of 5
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Completion and Plugging Reports
Hydraulic Fracture Stimulation using Diesel Fuel: Most operators in Texas do not use diesel fuel in hydraulic fracturing fluids.
Section 322 of the Energy Policy Act of 2005 amended the Underground Injection Control (UIC) portion of the federal Safe Drinking Water
Act (42 USC 300h(d)) to define "underground Injection" to EXCLUDE " ...the underground injection of fluids or propping agents (other
than dieselfluels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities." (italic and underlining
added.) Therefore, hydraulic fracturing may be subject to regulation under the federal UIC regulations if diesel fuel is injected or used as a
propping agent. EPA defined "diesel fuel" using the following five (5) Chemical Abstract Service numbers: 68334-30-5 Primary Name: Fuels,
diesel; 68476-34-6 Primary Name: Fuels, diesel, No. 2; 68476-30-2 Primary Name: Fuel oil No. 2; 68476-31-3 Primary Nmae: Fuel oil, No.
4; and 8008-20-6 Primary Name: Kerosene. As a result, an injection well permit would be required before performing hydraulic fracture
stimulation using diesel fuel as defined by EPA on any well in Texas. Hydraulic fracture stimulation using diesel fuel as defined by EPA on a
well in Texas without an injection well permit could result in enforcement action.
Producing Well: Statewide Rule 16 states that the operator of a well shall file with the Commission the appropriate completion report
within thirty (30) days after completion of the well or within ninety (90) days after the date on which the drilling operation is completed,
whichever is earlier. Completion of the well in a field authorized by this permit voids the permit for all other fields included in the permit
unless the operator indicates on the initial completion report that the well is to be a dual or multiple completion and promptly submits an
application for multiple completion. All zones are required to be completed before the expiration date on the existing permit. Statewide Rule
40(d) requires that upon successful completion of a well in the same reservoir as any other well previously assigned the same acreage,
proration plats and P-15s (if required) must be submitted with no double assignment of acreage.
Dry or Noncommercial Hole : Statewide Rule 14(b)(2) prohibits suspension of operations on each dry or non-commercial well without
plugging unless the hole is cased and the casing is cemented in compliance with Commission rules. If properly cased, Statewide Rule 14(b)(2)
requires that plugging operations must begin within a period of one (1) year after drilling or operations have ceased. Plugging operations must
proceed with due diligence until completed. An extension to the one-year plugging requirement may be granted under the provisions stated in
Statewide Rule 14(b)(2).
Intention to Plug : The operator must file a Form W-3 A (Notice of Intention to Plug and Abandon) with the district office at least five (5)
days prior to beginning plugging operations. If, however, a drilling rig is already at work on location and ready to begin plugging operations,
the district director or the director's delegate may waive this requirement upon request, and verbally approve the proposed plugging
procedures.
*Notification of Plugging a Dry Hole : The operator MUST call in notification to the appropriate district office (phone number shown on
permit) a minimum of four (4) hours prior to beginning plugging operations. The individual giving the notification MUST be able to advise
the district office of the drilling permit number and all water protection depths for that location as stated in the Texas Commission on
Environmental Quality letter.
DIRECT INQUIRIES TO: DRILLING PERMIT SECTION, OIL AND GAS DIVISION
PHONE
(512) 463-6751
MAIL:
PO Box 12967
Austin, Texas, 78711-2967
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 2 of 5
-------
RAILROAD COMMISSION OF TEXAS
OIL & GAS DIVISION
PERMIT TO DRILL, DEEPEN, PLUG BACK, OR RE-ENTER ON A REGULAR OR ADMINISTRATIVE EXCEPTION LOCATION
PERMIT NUMBER
839303
DATE PERMIT ISSUED OR AMENDED
04/27/2018
DISTRICT
8A
API NUMBER
42-501-36998
FORM W-l RECEIVED
04/25/2018
COUNTY
YOAKUM
TYPE OF OPERATION
New Drill
WELLBORE PROFILE(S)
Vertical
ACRES
640.0
OPERATOR 748093
SANTA FE MIDSTREAM PERMIAN LLC
5830 GRANITE PKWY STE 1025
PLANO, TX 75024-0000
NOTICE
This permit and any allowable assigned may
be revoked if payment for fee(s) submitted to
the Commission is not honored.
District Office Telephone No:
(806) 698-6509
LEASE NAME
RATTLESNAKE AGI
WELL NUMBER
1
LOCATION
7.3 miles NW direction from DENVER CITY
TOTAL DEPTH
12000
Section, Block and/or
SECTION 733 BLOCK D ABSTRACT 89
SURVEY GIBSON, J H
DISTANCE TO SURVEY LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST LEASE LINE
200.0
DISTANCE TO LEASE LINES
200.0 ft NORTH 200.0 ft WEST
DISTANCE TO NEAREST WELL ON LEASE
See FIELD(s) Below
FIELD(s) and LIMITATIONS:
* SEE FIELD DISTRICT FOR REPORTING PURPOSES *
FIELDNAME ACRES DEPTH WELL# DIST
LEASE NAME NEAREST LEASE NEAREST WELL
WASSON "640!0 12000 1 8A
RATTLESNAKE AGI 200 0 0.0
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
WASSON, NORTH (SAN ANDRES) "64o!o 12000 1 8A
RATTLESNAKE AGI 200.0 0.0
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 3 of 5
-------
This is a hydrogen sulfide field. This well shall be drilled in accordance with SWR 36.
Do not use this well for injection/disposal/hydrocarbon storage purposes without approval by the Environmental Services section of the Railroad Commission,
Austin, Texas office.
THE FOLLOWING RESTRICTIONS APPLY TO ALL FIELDS
This well shall be completed and produced in compliance with applicable special field or statewide spacing and density rules. If this well is
to be used for brine mining, underground storage of liquid hydrocarbons in salt formations, or underground storage of gas in salt formations,
a permit for that specific purpose must be obtained from Environmental Services prior to construction, including drilling, of the well in
accordance with Statewide Rules 81, 95, and 97.
This well must comply to the new SWR 3.13 requirements concerning the isolation of any potential flow zones and zones with corrosive
formation fluids. See approved permit for those formations that have been identified for the county in which you are drilling the well in.
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 4 of 5
-------
Railroad Commission of Texas
Oil and Gas Division
SWR #13 Formation Data
YOAKUM (501) COUNTY
l-'oniiiilioii
Koniiirks
Order
I.ITcc(i\c
Diilo
RED BED-SANTA ROSA
1
01/01/2014
YATES
2
01/01/2014
SAN ANDRES
high flows, H2S, corrosive
3
01/01/2014
GLORIETA
4
01/01/2014
CLEARFORK
Active C02 Flood
5
01/01/2014
WICHITA
6
01/01/2014
LEONARD
7
01/01/2014
WOLFCAMP
8
01/01/2014
PENNSYLVANIAN
9
01/01/2014
STRAWN
10
01/01/2014
MISSISSIPPIAN
11
01/01/2014
DEVONIAN
12
01/01/2014
DEVONIAN-SILURIAN
13
01/01/2014
The above list may not be all inclusive, and may also include formations that do not intersect all wellbores. The listing order of the Formation
information reflects the general stratigraphic order and relative geologic age. This is a dynamic list subject to updates and revisions. It is the
operator's responsibility to make sure that at the time of spudding the well the most current list is being referenced. Refer to the RRC website
at the following address for the most recent information, http://www.rrc.texas.gov/oil-gas/compliance-enforcement/rule-13-geologic-
formation-info
Date Validation
Fri, 20 Nov 2020 09:32:59
Page 5 of 5
-------
B-4
RAILROAD COMMISSION OF TEXAS Form G-1
1701 N. Congress Status: Approved
P.O. Box 12967 Date: 07/25/2019
Austin, Texas 78701-2967 Tracking No.: 205926
GAS WELL BACK PRESSURE TEST, COMPLETION OR RECOMPLETION REPORT, AND LOG
OPERATOR INFORMATION
Operator Name: santa fe midstream permian llc Operator No.: 748093
Operator Address: 5830 granite pkwy ste 1025 plano, tx 75024-0000
WELL INFORMATION
API No.: 42-501-36998
County: YOAKUM
Well No.: 1
RRC District No.: 8A
Lease Name: RATTLESNAKE AG I
Field Name: WASSON
RRC Gas ID No.: 286838
Field No.: 95397001
Location: Section: 733, Block: D, Survey: GIBSON, J H, Abstract: 89
Latitude:
Longitude:
This well is located 7.3 miles in a nw
direction from Denver city,
which is the nearest town in the county.
FILING INFORMATION
Purpose of filing: Well Record Only
Type of completion: New Well
Well Type: Active UIC
Completion or Recompletion Date: 08/31/2018
Type of Permit
Date Permit No.
Permit to Drill, Plug Back, or Deepen
04/27/2018 839303
Rule 37 Exception
Fluid Injection Permit
O&G Waste Disposal Permit
11/14/2018 15848
Other:
COMPLETION INFORMATION
ISpud date: 07/16/2018
Date of first production after rig released: 08/31/2018 I
Date plug back, deepening, recompletion, or Date plug back, deepening, recompletion, or
drilling operation commenced: 07/16/2018
drilling operation ended: 08/31/2018
Number of producing wells on this lease in
Distance to nearest well in lease &
this field (reservoir) including this well:
1 reservoir (ft.): 0.0
Total number of acres in lease: 640.00
Elevation (ft.): 3627 GR
Total depth TVD (ft.): 11980
Total depth MD (ft.):
Plug back depth TVD (ft.): 11980
Plug back depth MD (ft.):
Was directional survey made other than
Rotation time within surface casing (hours): 72.0
inclination (Form W-12)? Yes
Is Cementing Affidavit (Form W-15) attached? Yes
Recompletion or reclass? No
Multiple completion? No
Type(s) of electric or other log(s) run: Combo of Induction/Neutron/Density/Sonic
Electric Log Other Description:
Location of well, relative to nearest lease boundaries Off Lease: No
of lease on which this well is located:
200.0 Feet from the North Line and
200 0 Feet from the West Line of the
rattlesnake agi Lease.
FORMER FIELD (WITH RESERVOIR) & GAS ID OR OIL LEASE NO.
Field & Reservoir
Gas ID or Oil Lease No. Well No. Prior Service Type
Page 1 of4
-------
G1: N/A
PACKET: N/A
FOR NEW DRILL OR RE-ENTRY, SURFACE CASING DEPTH DETERMINED BY:
GAU Groundwater Protection Determination Depth (ft.): 2025.0 Date: 01/12/2018
SWR 13 Exception Depth (ft.):
GAS MEASUREMENT DATA
I Date of test: Gas measurement method(s):
Gas production during test (MCF):
Was the well preflowed for 48 hours? No
Orif. or 24 hr. Coeff.
Run Line Choke Orif. Or Choke Static Pm or Diff
No. size Size (in.) (in.) Choke (in.) (hw)
Flow
Temp Temp. Gravity
(°F) (l-tt) (hg)
Compress
(Fpv)
Volume
(MCF/day)
N/A
FIELD DATA AND PRESSURE CALCULATIONS
Gravity (dry gas):
Gas-Liquid Hydro Ratio (CF/Bbl):
Avg. shut in temp. (°F):
Gravity (liquid hydrocarbons) (Deg. API):
Gravity (mixture): Gmix=
Bottom hole temp, and depth: °F@ ft
Run No. Time of Run (Min.)
Choke Size (in.) Wellhead Pressure (PSIA) Wellhead Flow Temp (°F )
N/A
CASING RECORD
Casing Hole Setting Multi - Multi - Cement Slurry Top of TOC
Type of
Size
Size
Depth Stage Tool Stage Shoe Cement Amount Volume Cement Determined
Row Casing
(in.)
(in.)
(ft.)
Depth (ft.) Depth (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
1 Surface
13 3/8
17 1/2
504
c
510
687.5
0
Circulated to Surface
3 Intermediate
9 5/8
12 1/4
5498
5498
c
485
797.0
4275
Circulated to Surface
2 Intermediate
13 3/8
17 1/2
5498
4275
c
1650
3045.0
0
Circulated to Surface
6 Conventional Production
7
8 3/4
11023
WELL
60
337.0
9575
Calculation
LOCK
5 Conventional Production
7
8 3/4
11023
5591
PREM
380
906.5
0
Circulated to Surface
PLUS
4 Conventional Production
7
8 3/4
11023
9575
PREM
380
906.5
5591
Calculation
PLUS
LINER RECORD
Cement
Slurry
Top of
TOC
Liner Hole
Liner
Liner
Cement
Amount
Volume
Cement
Determined
Row Size (in.) Size (in.)
Top (ft.)
Bottom (ft.)
Class
(sacks)
(cu. ft.)
(ft.)
By
N/A
TUBING RECORD
Row
Size (in.)
Depth Size (ft.)
Packer Depth (ft.)/Type
1
3 1/2
10966
10966 / HALLIBURTON
BWD
PRODUCING/INJECTION/DISPOSAL INTERVAL
Row
Open hole?
From (ft.)
To (ft.)
1
Yes
L 11025
11980
Page 2 of4
-------
ACID, FRACTURE, CEMENT SQUEEZE,
CAST IRON BRIDGE PLUG, RETAINER, ETC.
Was hydraulic fracturing treatment performed? No
Is well equipped with a downhole actuation
sleeve? No
If yes, actuation pressure (PSIG):
Production casing test pressure (PSIG) prior to
Actual maximum pressure (PSIG) during hydraulic
hydraulic fracturing treatment:
fracturing:
Has the hydraulic fracturing fluid disclosure been
reported to FracFocus disclosure registry (SWR29)?
No
Row Type of Operation Amount and Kind of Material Used Depth Interval (ft.)
N/A
FORMATION RECORD
Is formation
Formations Encountered Depth TVD (ft.) Depth MP (ft.) isolated? Remarks
YATES
Yes
3019.0
Yes
SAN ANDRES - HIGH FLOWS, H2S,
Yes
4465.0
Yes
CORROSIVE
GLORIETA
Yes
6316.0
Yes
CLEARFORK - ACTIVE C02 FLOOD
Yes
6492.0
Yes
WICHITA
Yes
8628.0
Yes
UPPER WOLFCAMP
Yes
9239.0
Yes
STRAWN
Yes
10030.0
Yes
ATOKA
Yes
10230.0
Yes
WOODFORD
Yes
10973.0
Yes
DEVONIAN
Yes
11036.0
No
DISPOSAL
WRISTEN
Yes
11268.0
No
DISPOSAL
FUSSELMAN
Yes
11538.0
No
DISPOSAL
MONTOYA
Yes
11974.0
No
DISPOSAL
RED BED-SANTA ROSA
No
No
NOT IN AREA
LEONARD
No
No
NOT IN AREA
WOLFCAMP
No
No
NOT IN AREA
PENNSYLVANIAN
No
No
NOT IN AREA
STRAWN
No
No
NOT IN AREA
MISSISSIPPIAN
No
No
NOT IN AREA
Do the producing interval of this well produce H2S with a concentration in excess of 100 ppm (SWR 36)? No
s the completion being downhole commingled (SWR 10)? No
REMARKS
NEW WELL PUTTING ON SCHEDULE.
Page 3 of4
-------
OPERATOR'S CERTIFICATION
Printed Name: Karen Zornes
Title:
Telephone No.: (281) 872-9300
Date Certified: 06/25/2019
Page 4 of4
-------
APPENDIX C - GAS COMPOSITION
-------
C-1
1 rv » n,,
natural Gas Analysis
www.permianls.com
575.397.3713 2609 W Marland HobbS NM 88240
11093G
30/30 Acid Gas
Sample Point Code
Sample Point Name
C6+ Gas Analysis Report
30/30 Acid Gas
Sample Point Location
Laboratory Services
Date Sampled
2021048523
1781
E Benavides - Spot
Source Laboratory
Lab File No
Container Identity
Sampler
USA
USA
USA
Texas
District
Area Name
Field Name
Facility Name
Nov 16, 2021
Nov 16, 2021
Nov 19, 2021 09:59
Nov 19, 2021
Date Effective
System Administrator
Ambient Temp (°F)
Flow Rate (Mcf)
Analyst
Date Received
21 @ 129
Press PSI @ Temp °F
Source Conditions
Date Reported
Stakeholder Midstream
30/30
Operator
Lab Source Description
Component
Normalized
Mol %
Un-Normalized
Mol %
GPM
H2S (H2S)
9.2000
9.2
Nitrogen (N2)
0.0000
0
C02 (C02)
89.6780
98.775
Methane (CI)
0.3030
0.331
Ethane (C2)
0.0580
0.063
0.0150
Propane (C3)
0.1080
0.118
0.0300
I-Butane (IC4)
0.0000
0
0.0000
N-Butane (NC4)
0.0250
0.027
0.0080
I-Pentane (IC5)
0.0000
0
0.0000
N-Pentane (NC5)
0.0000
0
0.0000
Hexanes Plus (C6+)
0.6280
0.686
0.2710
TOTAL
100.0000
109.2000
0.3240
Method(s): Gas C6+ - GPA 2261, Extended Gas - GPA 2286, Calculations - GPA 2172
Analyzer Information
Device Type: Gas Chromatograph Device Make: Shimadzu
Device Model: GC-2014 Last Cal Date: Nov 14, 2021
Gross Heating Values (Real, BTU/ft3)
14.696 PSI @ 60.00 A°F 14.65 PSI @ 60.00 A°F
Dry Saturated Dry Saturated
98.7 98.00 98.4 97.7
Calculated Total Sample Properties
GPA2145-16 Calculated at Contract Conditions
Relative Density Real Relative Density Ideal
1.5042 1.4956
Molecular Weight
43.3157
C6 - 60.000%
C6+ Group Properties
Assumed Composition
C7 - 30.000%
C8 - 10.000%
Field H2S
92000 PPM
PROTREND STATUS: DATA SOURCE:
Passed By Validator on Nov 21, 2021 Imported
PASSED BY VALIDATOR REASON:
Close enough to be considered reasonable.
VALIDATOR:
Dustin Armstrong
VALIDATOR COMMENTS:
OK
Nov 22, 2021 7:57 a
Powered By ProTrend -www.criticalcontrol.com
Page 1 of 1
-------
APPENDIX D - FACILITY SAFETY PLOT PLANS
-------
PLANT NORTH
LEGEND
•
FIRE EXTINGUISHER
~
SCBA/ESCAPE PACK
~
WIND SOCK
®
LEL/H2S MONITOR
ESD BUTTON
H
STROBE LIGHTS
HORN
D-1
r
i| 1 | |—1 l\ 71 1 k 1 A 1 \ W—1 / \ 1 1
—\
JKI 1 IMINAKY 1 ()l>
pn/ic\A/
0
NO.
05/11 / 22
DATE
INITIAL RELEASE K C V 1 C V V
REVISION DESCRIPTION
KLD
BY
BEC
FCE
JB
CLIENT
CHAR1S ENGINEERING. LLC
"IX ENG. FIRM NO. F-1B8B4
MIDLAND. IX
STAKEHOLDER
MIDSTREAM
CLIENT ;
PROJECT ;
TITLE :
STAKEHOLDER MIDSTREAM
30-30 GAS PLANT
SAFETY EQUIPMENT PLOT PLAN
1" = 50'—0"
DATE
5/11/22
ME—PLNP—AOOO—0004
A
-------
APPENDIX E - MMA/AMA REVIEW MAPS
APPENDIX E-l: PLUME BOUNDARY AT END OF INJECTION, STABILIZED PLUME BOUNDARY AND MAXIMUM
MONITORING AREA MAP
APPENDIX E-2: ACTIVE MONITORING AREA MAP
APPENDIX E-3: OIL AND GAS WELLS WITHIN THE MMA MAP
APPENDIX E-4: OIL AND GAS WELLS WITHIN THE MMA LIST
APPENDIX E-5: INJECTION INTERVAL PENETRATING WELLS WITHIN THE MMA MAP
APPENDIX E-6: GROUNDWATER WELLS WITHIN THE MMA
APPENDIX E-7: WELLBORE SCHEMATICS FOR INJECTION INTERVAL PENETRATING WELLS
-------
A-1143
A-545
A-1866
A-572
A-£ 58
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& Stabilized Plume
with
1/2-Mile Maximum Monitoring Area (MMA)
Stakeholder Midstream
Yoakum Co., TX
A-1314
A-549
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
Rattlesnake AGI No. 1 SHL
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
J Plume Boundary at End of Injection
1560
-------
A-1143
Rattlesnake AGI No. 1
Plume Boundary at End of Injection
& 19-Year Plume
with
1/2-Mile Active Monitoring Area (AMA)
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
1
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
E-2
Rattlesnake AGI No. 1 SHL
1 Active Monitoring Area Boundary
1 9-Year Plume
J Plume Boundary at End of Injection
Abstract
Note: All coordinates shown are in NAD83 (DD).
MAP EXTENT
~
-------
A-1866
A-1314
iiiiiiiiij
36998 l\
RATTLESNAKE AGI NO
33.0513499,1
-102.90450576
00000
32541
00261
32531
00000
iiiiiiiiii
00000"
00000
00262
000
\ 00645 •
00050
00643s
00644
00000
33349.
33530
00057
33173
32702
34984\
32065
00059
33172
33531
A-1484
33531'
32703
33351
32064
,00061
00000
00060
00058
32704
33 no 3
00065
00068
00064
^067 ^
32945
32975
32077
32075
: 30600
32076
36156
00267
00266
00066 3271 i
00063
02992
02991
02990
02989 35820
A-1816
34878
32070
36155
36151 30604 35791 30602
30606
JO fyy
36152
35821
30630
32072
36153
30601
30605
35794
35793 30598
36150
30603
36048
36154
35180
35703
35701
35705
30000
=3058.4;
32270
33065
1:34099;
00755
30583
30629
35961'
34797
56428 00000
• °l
36098
-34023 •
00768J
34124
30580
36327
33843
LONQUIST & CO LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON jfc CALGARY • WICHITA
DENVER • COLLEGE STATION T BATON ROUGE • EDMONTON
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
+ Rattlesnake AC I No. 1 SHL
| ~ ~ ™ 1/2-Mile Buffer from Max. Plume Extent (MMA)
I ~ Z Z Z Combined Maximum Plume Extent
1 Stabilized Plume
I ~ ~ ~ Z Plume Boundary at End of Injection
Abstract
Lateral (21)
API (42-501-...) SHL Status - Type (Count)
O Horizontal Surface Location (21)
• Active - Oil (93)
Active - Injection/Disposal (21)
•» Active - Injection/Disposal from Oil (22)
X Plugged - Oil (69)
^ Plugged - Gas (1)
Plugged- Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal (3)
TA - Injection/Disposal from Oil (7)
"0" Dry Hole (6)
o Permitted Location (2)
0 Canceled/Abandoned Location (6)
X Expired Permit (7)
API (42-501-...) BHL Status - Type (Count)
• Active - Oil (11)
•A Active - Injection/Disposal from Oil (1)
Shut-In - Oil (1)
TA - Injection/Disposal from Oil (1)
o Permitted Location (4)
X Expired Permit (3)
Sou rce:
1.) Oil/Cas Well SHL Data: DI-2022
2.) Oil/Cas Well BHL Data: DI-2022
3.) Oil/Cas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD). *
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
1
A-1531
A-1064
A-87
A-1483
A-1641
A-499
VI55 !
i .-1777
A
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
E-4
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101829
DENVER UNIT
2215W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5300
5300
2215W
4250101835
DENVER UNIT
2207
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5185
5185
2207
4250130914
DENVER UNIT
2222
OCCIDENTAL PERMIAN LTD.
Active - Oil
2222
4250101832
DENVER UNIT
2201W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5190
5190
2201W
4250101826
DENVER UNIT
2203
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2203
4250101319
ROBERTS UNIT
4532W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5200
5200
4532W
4250130629
ROBERTS UNIT
4535
APACHE CORPORATION
Active - Oil
5280
5280
4535
4250130583
ROBERTS UNIT
4525
APACHE CORPORATION
Active - Oil
5286
5286
4525
4250101318
ROBERTS UNIT
4541
APACHE CORPORATION
TA - Injection/Disposal from Oil
5240
5240
4541
4250101889
ROBERTS UNIT
3614
APACHE CORPORATION
Plugged - Oil
5180
5180
3614
4250130598
Roberts Unit
3647
APACHE CORPORATION
Plugged - Oil
5281
5281
3647
4250130603
ROBERTS UNIT
3626
APACHE CORPORATION
Plugged - Oil
5289
5289
3626
4250102992
ROBERTS UNIT
3612W
APACHE CORPORATION
Plugged - Oil
5226
5226
3612W
4250100066
ROBERTS UNIT
3532
APACHE CORPORATION
Plugged - Oil
5231
5231
3532
4250101886
ROBERTS UNIT
3631
APACHE CORPORATION
Plugged - Oil
3631
4250101885
ROBERTS UNIT
3641
APACHE CORPORATION
Plugged - Oil
5212
5212
3641
4250100068
ROBERTS UNIT
3521
APACHE CORPORATION
Plugged - Oil
5225
5225
3521
4250100064
ROBERTS UNIT
3541
APACHE CORPORATION
Plugged - Oil
5264
5264
3541
4250102014
ROBERTS UNIT
2443
APACHE CORPORATION
Plugged - Oil
5226
5226
2443
4250100050
ROBERTS UNIT
1654
APACHE CORPORATION
Plugged - Oil
5198
5198
1654
4250133531
ROBERTS UNIT
2443A
Active - Injection/Disposal
5325
5325
2443A
4250133502
ROBERTS UNIT
2527A
Plugged - Oil
5308
5308
2527A
4250100000
C. A. ELLIOTT
6
AMERICAN LIBERTY OIL CO
Plugged - Oil
5229
5229
6
4250100000
C. A. ELLIOTT
7
AMERICAN LIBERTY AND ATLANTIC
Active - Oil
5182
5182
7
4250100000
GEO CLEVELAND
1
DELFERN OIL CO
Dry Hole
5071
5071
1
4250100000
JAMES H. LYNN
1614
AMERICAN LIBERTY
Active - Oil
5169
5169
1614
4250100000
J. H. LYNN
1634
AMERICAN LIBERTY
Active - Oil
5160
5160
1634
4250100000
A. T. MORRIS
1
ATLANTIC
Active - Oil
5235
5235
1
4250100000
A. T. MORRIS
2
AMERICAN LIBERTY OIL CO
Plugged - Oil
5179
5179
2
4250100000
W.J. CARPENTER
1642
AMERICAN LIBERTY OIL COMPANY
Plugged - Oil
5183
5183
1642
4250100000
E.S.SMITH
1
CREAT WESTERN FROD
Dry Hole
5216
5216
1
4250130607
ROBERTS UNIT
3546
Active - Oil
3546
4250135958
DENVER UNIT
2247
OCCIDENTAL PERMIAN LTD.
Active - Oil
2333
2333
2247
4250131542
DENVER UNIT
2229
SHELL OIL COMPANY
Dry Hole
2409
2409
2229
4250101320
ROBERTS UNIT
4543
APACHE CORPORATION
Active - Injection/Disposal from Oil
5120
5120
4543
4250137301
MILLER
8H
AMTEX ENERGY, INC.
Active - Oil
5157
5157
8H
4250137304
MILLER 732 C
10H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
10H
4250137305
MILLER 732 D
11H
AMTEX ENERGY, INC.
Permitted Location
5157
5157
11H
4250101888
ROBERTS UNIT
3634W
APACHE CORPORATION
Plugged - Oil
5160
5160
3634W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101031
ROBERTS UNIT
3534W
APACHE CORPORATION
Plugged - Oil
5164
5164
3534W
4250101828
DENVER UNIT
2208
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5170
5170
2208
4250101032
ROBERTS UNIT
3544
APACHE CORPORATION
Plugged - Oil
5170
5170
3544
4250101841
DENVER UNIT
2206
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5177
5177
2206
4250101842
ROBERTS UNIT
3643W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3643W
4250101035
ROBERTS UNIT
3533W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5180
5180
3533W
4250132704
ROBERTS UNIT
2615
APACHE CORPORATION
Active - Oil
5180
5180
2615
4250100261
ROBERTS UNIT
1643W
APACHE CORPORATION
Plugged - Oil
5180
5180
1643W
4250101323
ROBERTS UNIT
4542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
4542W
4250102989
ROBERTS UNIT
3642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5182
5182
3642W
4250102991
ROBERTS UNIT
3622W
APACHE CORPORATION
Plugged - Oil
5185
5185
3622W
4250132417
MILLER
3
AMTEX ENERGY, INC.
Active - Oil
5186
5186
3
4250101025
ROBERTS UNIT
2613W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5188
5188
2613W
4250101887
ROBERTS UNIT
3644
APACHE CORPORATION
Active - Injection/Disposal from Oil
5189
5189
3644
4250101830
DENVER UNIT
2214WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5190
5190
2214WC
4250101103
ROBERTS UNIT
3621
APACHE CORPORATION
Plugged - Oil
5190
5190
3621
4250101024
ROBERTS UNIT
2623
APACHE CORPORATION
Plugged - Oil
5190
5190
2623
4250101023
ROBERTS UNIT
2622W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5190
5190
2622W
4250101022
ROBERTS UNIT
2632
APACHE CORPORATION
Active - Oil
5190
5190
2632
4250101019
ROBERTS UNIT
2621
APACHE CORPORATION
Active - Oil
5190
5190
2621
4250101030
ROBERTS UNIT
3524W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5193
5193
3524W
4250101829
DENVER UNIT
2205
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5195
5195
2205
4250101836
DENVER UNIT
2213WC
OCCIDENTAL PERMIAN LTD.
TA - Injection/Disposal from Oil
5200
5200
2213WC
4250101833
DENVER UNIT
2202WC
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5200
5200
2202WC
4250134099
DENVER UNIT
2239WC
OCCIDENTAL PERMIAN LTD.
Dry Hole
5200
5200
2239WC
4250132717
ROBERTS UNIT
3531A
APACHE CORPORATION
TA - Injection/Disposal
5200
5200
3531A
4250101014
ROBERTS UNIT
2624W
APACHE CORPORATION
Plugged - Oil
5200
5200
2624W
4250101028
ROBERTS UNIT
3523
APACHE CORPORATION
Plugged - Oil
5205
5205
3523
4250101102
ROBERTS UNIT
3611
APACHE CORPORATION
Plugged - Oil
5206
5206
3611
4250101827
DENVER UNIT
2209W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5210
5210
2209W
4250101015
2643
TEXACO INCORPORATED
Active - Injection/Disposal from Oil
5210
5210
2643
4250100266
ROBERTS UNIT
3522W
APACHE CORPORATION
Plugged - Oil
5211
5211
3522W
4250132632
MILLER
5
AMTEX ENERGY, INC.
Active - Oil
5213
5213
5
4250100057
ROBERTS UNIT
2512W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5213
5213
2512W
4250101890
ROBERTS UNIT
3624W
APACHE CORPORATION
Plugged - Oil
5214
5214
3624W
4250101033
ROBERTS UNIT
3543W
APACHE CORPORATION
Plugged - Oil
5215
5215
3543W
4250101012
ROBERTS UNIT
2634W
APACHE CORPORATION
Plugged- Injection/Disposal from Oil
5215
5215
2634W
4250101734
ROBERTS UNIT
2442
APACHE CORPORATION
Plugged - Oil
5215
5215
2442
4250101020
ROBERTS UNIT
2611W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5215
5215
2611W
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100067
ROBERTS UNIT
3531
APACHE CORPORATION
Plugged - Oil
5216
5216
3531
4250101013
ROBERTS UNIT
2614W
APACHE CORPORATION
Plugged - Oil
5216
5216
2614W
4250101844
ROBERTS UNIT
3623W
APACHE CORPORATION
Plugged - Oil
5217
5217
3623W
4250131869
ROBERTS UNIT
A3534W
APACHE CORPORATION
Plugged - Oil
5220
5220
A3534W
4250102990
ROBERTS UNIT
3632W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5220
5220
3632W
4250100262
ROBERTS UNIT
1644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5220
5220
1644W
4250132858
DENVER UNIT
2235
OCCIDENTAL PERMIAN LTD.
Shut-In - Oil
5225
5225
2235
4250100058
ROBERTS UNIT
2544W
APACHE CORPORATION
Plugged - Oil
5225
5225
2544W
4250130584
ROBERTS UNIT
4520
APACHE CORPORATION
Active - Oil
5230
5230
4520
4250130630
ROBERTS UNIT
3535
APACHE CORPORATION
Active - Oil
5230
5230
3535
4250100063
ROBERTS UNIT
3542W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5230
5230
3542W
4250132076
ROBERTS UNIT
3627
APACHE CORPORATION
Active - Oil
5230
5230
3627
4250100267
ROBERTS UNIT
3512W
APACHE CORPORATION
Plugged - Oil
5233
5233
3512W
4250101016
ROBERTS UNIT
2642W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5234
5234
2642W
4250134716
DENVER UNIT
2242
OCCIDENTAL PERMIAN LTD.
Active - Oil
5236
5236
2242
4250100061
ROBERTS UNIT
2524W
APACHE CORPORATION
Plugged - Oil
5238
5238
2524W
4250101021
ROBERTS UNIT
2633
APACHE CORPORATION
Plugged - Oil
5240
5240
2633
4250101011
ROBERTS UNIT
2644W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5241
5241
2644W
4250132541
FUTCH
1
AMTEX ENERGY, INC.
Active - Oil
5244
5244
1
4250101026
ROBERTS UNIT
2612W
APACHE CORPORATION
Plugged - Oil
5245
5245
2612W
4250100059
ROBERTS UNIT
2513W
APACHE CORPORATION
Active - Injection/Disposal from Oil
5246
5246
2513W
4250132531
MILLER
4
AMTEX ENERGY, INC.
Plugged - Oil
5248
5248
4
4250132687
ROBERTS UNIT
2635
APACHE CORPORATION
Plugged - Oil
5248
5248
2635
4250131656
DENVER UNIT
2232WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5250
5250
2232WC
4250131791
DENVER UNIT
2231
SHELL OIL COMPANY
Canceled/Abandoned Location
5250
5250
2231
4250134118
DENVER UNIT
2238
OCCIDENTAL PERMIAN LTD.
Active - Oil
5250
5250
2238
4250101342
ROBERTS UNIT
APACHE CORPORATION
Plugged - Gas
5250
5250
4250132269
ROBERTS UNIT
3601
APACHE CORPORATION
Plugged - Oil
5250
5250
3601
4250101843
ROBERTS UNIT
3633W
APACHE CORPORATION
Plugged - Oil
5250
5250
3633W
4250130608
ROBERTS UNIT
3545
APACHE CORPORATION
Active - Oil
5250
5250
3545
4250132077
ROBERTS UNIT
3617
APACHE CORPORATION
Active - Oil
5250
5250
3617
4250134963
DENVER UNIT
2244WC
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal
5251
5251
2244WC
4250100060
ROBERTS UNIT
2514
APACHE CORPORATION
Plugged - Oil
5251
5251
2514
4250101459
DENVER UNIT
2211
OCCIDENTAL PERMIAN LTD.
Active - Oil
5252
5252
2211
4250132521
DENVER UNIT
2233W
OCCIDENTAL PERMIAN LTD.
TA- Injection/Disposal from Oil
5253
5253
2233W
4250135211
DENVER UNIT
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5253
5253
2241
4250101837
DENVER UNIT
2212W
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5255
5255
2212W
4250132793
MILLER
6
AMTEX ENERGY, INC.
Active - Oil
5258
5258
6
4250132356
MILLER
1
AMTEX ENERGY, INC.
Active - Oil
5260
5260
1
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250101017
ROBERTS UNIT
2641
APACHE CORPORATION
Active - Oil
5260
5260
2641
4250101825
DENVER UNIT
2204W
OCCIDENTAL PERMIAN LTD.
Active - Injection/Disposal from Oil
5264
5264
2204W
4250132416
MILLER
2
AMTEX ENERGY, INC.
Active - Oil
5269
5269
2
4250100065
ROBERTS UNIT
3511W
APACHE CORPORATION
Plugged - Oil
5270
5270
3511W
4250101018
ROBERTS UNIT
2631
APACHE CORPORATION
Active - Oil
5270
5270
2631
4250130600
ROBERTS UNIT
3645
APACHE CORPORATION
Active - Oil
5273
5273
3645
4250130580
ROBERTS UNIT
4536
APACHE CORPORATION
Active - Oil
5279
5279
4536
4250130599
ROBERTS UNIT
3646
APACHE CORPORATION
Active - Oil
5279
5279
3646
4250130602
ROBERTS UNIT
3635
APACHE CORPORATION
Active - Oil
5283
5283
3635
4250132997
DENVER UNIT
2208WC
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5284
5284
2208WC
4250130601
ROBERTS UNIT
3636
APACHE CORPORATION
Active - Oil
5286
5286
3636
4250132174
SHEPHERD
1
YOUNG, MARSHALL R., OIL CO.
Dry Hole
5286
5286
1
4250130604
ROBERTS UNIT
3625
APACHE CORPORATION
Active - Oil
5287
5287
3625
4250130912
DENVER UNIT
2224
OCCIDENTAL PERMIAN LTD.
Active - Oil
5288
5288
2224
4250130911
DENVER UNIT
2225
OCCIDENTAL PERMIAN LTD.
Active - Oil
5290
5290
2225
4250130609
ROBERTS UNIT
4530
APACHE CORPORATION
Active - Oil
5291
5291
4530
4250130605
ROBERTS UNIT
3616
APACHE CORPORATION
Plugged - Oil
5291
5291
3616
4250130606
ROBERTS UNIT
3615
APACHE CORPORATION
Active - Oil
5293
5293
3615
4250133172
ROBERTS UNIT
2523
CONOCOPHILLIPS COMPANY
Plugged - Oil
5295
5295
2523
4250132739
CLEVELAND
1
HIGHLAND PRODUCTION COMPANY
Plugged - Oil
5300
5300
1
4250133064
DENVER UNIT
2238
SHELL WESTERN E&P INC.
Canceled/Abandoned Location
5300
5300
2238
4250132927
DENVER UNIT
2236
OCCIDENTAL PERMIAN LTD.
Active - Oil
5300
5300
2236
4250133065
DENVER UNIT
2237
SHELL WESTERN E&P INC.
Expired Permit
5300
5300
2237
4250132270
ROBERTS UNIT
4540
APACHE CORPORATION
Active - Oil
5300
5300
4540
4250132414
ROBERTS UNIT
3523A
APACHE CORPORATION
Active - Injection/Disposal
5300
5300
3523A
4250132712
ROBERTS UNIT
3537
APACHE CORPORATION
Plugged - Oil
5300
5300
3537
4250132722
ROBERTS UNIT
3547
APACHE CORPORATION
Active - Oil
5300
5300
3547
4250132945
ROBERTS UNIT
3541A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3541A
4250132975
ROBERTS UNIT
3641A
TEXACO PRODUCING INC.
Expired Permit
5300
5300
3641A
4250132711
ROBERTS UNIT
3620
APACHE CORPORATION
Active - Oil
5300
5300
3620
4250133527
ROBERTS UNIT
2518
APACHE CORPORATION
Active - Oil
5300
5300
2518
4250132714
ROBERTS UNIT
2637
APACHE CORPORATION
Plugged - Oil
5300
5300
2637
4250133351
ROBERTS UNIT
2526
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2526
4250132703
ROBERTS UNIT
2516
APACHE CORPORATION
Plugged - Oil
5300
5300
2516
4250133348
ROBERTS UNIT
2533
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2533
4250132702
ROBERTS UNIT
2515
APACHE CORPORATION
Active - Oil
5300
5300
2515
4250133350
ROBERTS UNIT
2525
APACHE CORPORATION
Active - Oil
5300
5300
2525
4250133498
ROBERTS UNIT
2532
TEXACO PRODUCING INC.
Expired Permit
5300
5300
2532
4250133173
ROBERTS UNIT
2522
APACHE CORPORATION
Active - Oil
5300
5300
2522
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250133499
ROBERTS UNIT
2527
TEXACO PRODUCING INC.
Dry Hole
5300
5300
2527
4250133530
ROBERTS UNIT
2507
APACHE CORPORATION
Active - Oil
5300
5300
2507
4250132685
ROBERTS UNIT
2638
APACHE CORPORATION
Plugged - Oil
5302
5302
2638
4250133349
ROBERTS UNIT
2517
APACHE CORPORATION
Active - Oil
5302
5302
2517
4250132718
ROBERTS UNIT
3532A
APACHE CORPORATION
Active - Injection/Disposal
5304
5304
3532A
4250132713
ROBERTS UNIT
2625
APACHE CORPORATION
Active - Oil
5308
5308
2625
4250133502
ROBERTS UNIT
2527A
APACHE CORPORATION
Plugged - Oil
5308
5308
2527A
4250132716
ROBERTS UNIT
3526
APACHE CORPORATION
Active - Oil
5309
5309
3526
4250100645
ROBERTS UNIT
1624W
APACHE CORPORATION
TA - Injection/Disposal from Oil
5309
5309
1624W
4250130913
DENVER UNIT
2223
OCCIDENTAL PERMIAN LTD.
Active - Oil
5310
5310
2223
4250132686
ROBERTS UNIT
2636
APACHE CORPORATION
Active - Oil
5310
5310
2636
4250101457
DENVER UNIT
2210
OCCIDENTAL PERMIAN LTD.
Plugged - Oil
5325
5325
2210
4250133529
ROBERTS UNIT
2508
APACHE CORPORATION
Plugged - Oil
5325
5325
2508
4250133531
ROBERTS UNIT
2443A
APACHE CORPORATION
Active - Injection/Disposal
5325
5325
2443A
4250133528
ROBERTS UNIT
2511
APACHE CORPORATION
Active - Oil
5325
5325
2511
4250135912
ROBERTS UNIT
3771W
APACHE CORPORATION
Active - Injection/Disposal
5330
5330
3771W
4250132075
ROBERTS UNIT
3637
APACHE CORPORATION
Active - Oil
5330
5330
3637
4250132063
ROBERTS UNIT
2705
APACHE CORPORATION
Active - Oil
5330
5330
2705
4250135793
ROBERTS UNIT
3672
APACHE CORPORATION
Active - Oil
5334
5334
3672
4250135819
ROBERTS UNIT
3674W
APACHE CORPORATION
Active - Injection/Disposal
5336
5336
3674W
4250135792
ROBERTS UNIT
3671
APACHE CORPORATION
Active - Oil
5339
5339
3671
4250135820
ROBERTS UNIT
3675W
APACHE CORPORATION
Active - Injection/Disposal
5341
5341
3675W
4250135818
ROBERTS UNIT
3633RW
APACHE CORPORATION
Active - Injection/Disposal
5344
5344
3633RW
4250135790
ROBERTS UNIT
3647R
APACHE CORPORATION
Active - Oil
5345
5345
3647R
4250100768
CORNELL UNIT
3107W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5350
5350
3107W
4250130915
DENVER UNIT
2221
OCCIDENTAL PERMIAN LTD.
Active - Oil
5350
5350
2221
4250136048
ROBERTS UNIT
3634RW
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3634RW
4250135908
ROBERTS UNIT
3678W
APACHE CORPORATION
Active - Injection/Disposal
5350
5350
3678W
4250132072
ROBERTS UNIT
3525
APACHE CORPORATION
Active - Oil
5350
5350
3525
4250135915
ROBERTS UNIT
3626R
APACHE CORPORATION
Active - Oil
5350
5350
3626R
4250132281
ROBERTS UNIT
2446
APACHE CORPORATION
Active - Oil
5350
5350
2446
4250132064
ROBERTS UNIT
2704
APACHE CORPORATION
Active - Oil
5350
5350
2704
4250132280
ROBERTS UNIT
2445
APACHE CORPORATION
Plugged - Oil
5350
5350
2445
4250135791
ROBERTS UNIT
3670
APACHE CORPORATION
Active - Oil
5351
5351
3670
4250135794
ROBERTS UNIT
3673
APACHE CORPORATION
Active - Oil
5352
5352
3673
4250135821
ROBERTS UNIT
3676W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3676W
4250135914
ROBERTS UNIT
3681W
APACHE CORPORATION
Active - Injection/Disposal
5352
5352
3681W
4250100643
ROBERTS UNIT
1634W
APACHE CORPORATION
Plugged - Oil
5353
5353
1634W
4250135796
ROBERTS UNIT
3669
APACHE CORPORATION
Active - Oil
5356
5356
3669
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250100644
ROBERTS UNIT
1614
APACHE CORPORATION
Plugged - Oil
5356
5356
1614
4250135913
ROBERTS UNIT
3680W
APACHE CORPORATION
Active - Injection/Disposal
5357
5357
3680W
4250135705
ROBERTS UNIT
3752
APACHE CORPORATION
Active - Oil
5360
5360
3752
4250135822
ROBERTS UNIT
3677W
APACHE CORPORATION
Active - Injection/Disposal
5362
5362
3677W
4250134984
ROBERTS UNIT
2626W
APACHE CORPORATION
Active - Injection/Disposal
5364
5364
2626W
4250135701
ROBERTS UNIT
3667
APACHE CORPORATION
Active - Oil
5365
5365
3667
4250132070
ROBERTS UNIT
3536
APACHE CORPORATION
Active - Oil
5370
5370
3536
4250132065
ROBERTS UNIT
2703
APACHE CORPORATION
Active - Oil
5370
5370
2703
4250100755
CORNELL UNIT
3101W
XTO ENERGY INC.
Active - Injection/Disposal from Oil
5373
5373
3101W
4250135703
ROBERTS UNIT
3668
APACHE CORPORATION
Active - Oil
5380
5380
3668
4250135229
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5388
5388
2240
4250136152
ROBERTS UNIT
3682W
APACHE CORPORATION
Active - Injection/Disposal
5397
5397
3682W
4250131539
DENVER UNIT
2230
SHELL OIL COMPANY
Canceled/Abandoned Location
5400
5400
2230
4250136327
ROBERTS UNIT
4547
APACHE CORPORATION
Active - Oil
5400
5400
4547
4250136154
ROBERTS UNIT
3624RW
APACHE CORPORATION
Active - Injection/Disposal
5400
5400
3624RW
4250136155
ROBERTS UNIT
3683W
APACHE CORPORATION
Active - Injection/Disposal
5402
5402
3683W
4250136156
ROBERTS UNIT
3686
APACHE CORPORATION
Active - Oil
5404
5404
3686
4250134797
CORNELL UNIT
3194
XTO ENERGY INC.
Active - Oil
5405
5405
3194
4250135696
CORNELL UNIT
113
XTO ENERGY INC.
Active - Oil
5406
5406
113
4250136150
ROBERTS UNIT
3684
APACHE CORPORATION
Active - Oil
5421
5421
3684
4250133629
CORNELL UNIT
3156
XTO ENERGY INC.
Active - Oil
5425
5425
3156
4250135961
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Active - Oil
5425
5425
2246
4250135960
DENVER UNIT
2249
OCCIDENTAL PERMIAN LTD.
Active - Oil
5431
5431
2249
4250136153
ROBERTS UNIT
3623RW
APACHE CORPORATION
Active - Injection/Disposal
5439
5439
3623RW
4250135353
CORNELL UNIT
107
XTO ENERGY INC.
Active - Oil
5450
5450
107
4250135528
ROBERTS UNIT
3549
APACHE CORPORATION
Active - Oil
5452
5452
3549
4250136151
ROBERTS UNIT
3685
APACHE CORPORATION
Active - Oil
5463
5463
3685
4250135963
DENVER UNIT
2252
OCCIDENTAL PERMIAN LTD.
Active - Oil
5476
5476
2252
4250136434
ROBERTS UNIT
263H
APACHE CORPORATION
Expired Permit
5500
5500
263H
4250136433
ROBERTS UNIT
262H
APACHE CORPORATION
Expired Permit
5500
5500
262H
4250136098
CORNELL UNIT
110
XTO ENERGY INC.
Active - Injection/Disposal
5510
5510
110
4250133615
ROBERTS UNIT
2442A
APACHE CORPORATION
TA - Injection/Disposal
5516
5516
2442A
4250135180
ROBERTS UNIT
3534B
APACHE CORPORATION
Active - Injection/Disposal
5517
5517
3534B
4250136428
CORNELL UNIT
124
XTO ENERGY INC.
Active - Oil
5532
5532
124
4250134878
ROBERTS UNIT
3548
APACHE CORPORATION
Active - Oil
5550
5550
3548
4250135966
DENVER UNIT
2251
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2251
4250135962
DENVER UNIT
2250
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2250
4250135356
DENVER UNIT
2246
OCCIDENTAL PERMIAN LTD.
Expired Permit
5600
5600
2246
4250135959
DENVER UNIT
2248
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2248
-------
Rattlesnake AGI No. 1
Oil and Gas Wells within MMA
API
WELL NAME
WELL NO
OPERATOR
RRCStatus
TVD
TD
welINo
4250135210
DENVER UNIT
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250135211
2241
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2241
4250134710
2240
OCCIDENTAL PERMIAN LTD.
Active - Oil
5600
5600
2240
4250101845
ROBERTS UNIT
3613
APACHE CORPORATION
Active - Oil
7000
7000
3613
4250110083
RANDALL, E.
36
EXXON CORP.
Plugged - Oil
8595
8595
36
4250110046
ELLIOTT, C.A.
2
MCCLURE OIL COMPANY, INC.
Plugged - Oil
9000
9000
2
4250136692
MISS KITTY 704-669
3XH
RILEY EXPLORATION OPG CO, LLC
Expired Permit
9000
9000
3XH
4250133793
RANDALL, E.
39
XTO ENERGY INC.
Active - Oil
9000
9000
39
4250137375
RIP WHEELER 705-668
5XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
5XH
4250137358
RIP WHEELER 705-668
1XH
RILEY PERMIAN OPERATING CO, LLC
Permitted Location
9000
9000
1XH
4250133843
ELLIOTT
1
DELTA C02, LLC
Plugged - Oil
9050
9050
1
4250134124
RANDALL, E
46
EXXON CORP.
Canceled/Abandoned Location
9100
9100
46
4250133792
RANDALL, E.
40
XTO ENERGY INC.
Plugged - Oil
9591
9591
40
4250110079
RANDALL, E.
32
EXXON CORP.
Plugged - Oil
9615
9615
32
4250135418
RANDALL, E.
46
XTO ENERGY INC.
Active - Oil
9650
9650
46
4250134023
RANDALL, E.
42
XTO ENERGY INC.
Active - Oil
9660
9660
42
4250134016
RANDALL, E.
43
XTO ENERGY INC.
Active - Oil
9740
9740
43
4250132388
RANDALL, E.
38
EXXON CORP.
Canceled/Abandoned Location
10300
10300
38
4250137302
MILLER 732 B
9H
AMTEX ENERGY, INC.
Active - Oil
5183
10662
9H
4250136432
ROBERTS UNIT
261 H
APACHE CORPORATION
Active - Oil
5151
11117
261 H
4250136998
RATTLESNAKE AGI
1
SANTA FE MIDSTREAM PERMIAN LLC
Active - Injection/Disposal
11980
11980
1
4250137252
MILLER SWD
7
AMTEX ENERGY, INC.
Permitted Location
13000
13000
7
4250136984
MADCAP 731-706
1XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5261
13274
1XH
4250137127
MISS KITTY A 669-704
25XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5321
13428
25XH
4250137287
MISS KITTY A 669-704
4XH
RILEY PERMIAN OPERATING CO, LLC
Shut-In - Oil
5340
13452
4XH
4250137236
MISS KITTY 669-704
2XH
RILEY PERMIAN OPERATING CO, LLC
Active - Oil
5317
13622
2XH
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Oil/Gas Well Penetrators
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 6/1/2022
Approved by: RH
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
1
AUSTIN • HOUSTON jj
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
E-5
+ Rattlesnake AGI No. 1 SHL
I '
I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
API (42-501-...) SHL Status - Type (Count)
• Active - Oil (4)
Active - Injection/Disposal (1)
Plugged - Oil (4)
® Permitted Location (1)
Sou rce:
1.) Oil/Gas Well SHL Data: DI-2022
2.) Oil/Gas Well BHL Data: DI-2022
3.) Oil/Gas Well Directional Data: DI-2022
* Note: All coordinates shown are in NAD83 (DD).
1560
-------
A-1143
Rattlesnake AGI No. 1
Maximum Monitoring Area
with
1/2-Mile MMA Groundwater Well
Area of Review
Stakeholder Midstream
Yoakum Co., TX
PCS: NAD83 TX-NC FIPS 4202 (US Ft.)
Drawn by: ER
Date: 5/31/2022
Approved by: RH
LONQUIST & CO LLC
PETROLEUM
ENERGY
E-6
ENGINEERS
ADVISORS
| AUSTIN • HOUSTON J
I CALGARY-WICHITA
DENVER
• COLLEGE STATION 1
[ BATON ROUGE • EDMONTON
+ Rattlesnake AGI No. 1 SHL
| I 1/2-Mile Buffer from Max. Plume Extent (MMA)
Combined Maximum Plume Extent
Stabilized Plume
J Plume Boundary at End of Injection
Abstract
SDRDB Groundwater Wells [TWDB-2022]
Proposed Use (Labeled with Well Report No.)
A Industrial (1)
Irrigation (5)
TWDB Groundwater Wells [TWDB-2022]
Well Type (Labeled with State Well No.)
¦ Withdrawal of Water (1)
Sou rce:
1.) SDRDB Groundwater Well SHL Data: TWDB-2022
2.) TWDB Groundwater Well SHL Data: TWDB-2022
3.) Brackish Groundwater Well SHL Data: TWDB-2022
* Note: All coordinates shown are in NAD83 (DD). *
1560
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Cement Plug #9
@7'-1,013'
Cement Plug #8
@ 1,730'- 1,800'
Cement Plug #7
@ 2,031' - 2,100
Cement Plug #6
@2,430'-2,500'
Cement Plug #5
@2,660'-2,719'
Cement Plug #4
@2,790'-2,860'
Cement Plug #3
@3,172'-3,239'
Cement Plug #2
@3,765'-3,831'
Cement Plug #1
@ 3,900'-3,960'
Perfs @ 8,231
8,396', 8,420'
8,447', 8,462'
Casing Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
4-1/2"
Depth Set
2,134'
9,601'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-10079
RRC District No: 8-A
Drawn: KAS
E. Randall No. 32 e-7A
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18231
Date: 05/31/2022
Approved: SLP
-------
Cement Plug #5
@ 0' - 458'
Cement Plug #4
@2,070'-2,295'
Cement Plug #3
@2,780'- 3,009'
Cement Plug #2
@4,450'-4,870'
Cement Plug #1
@5,184'-5,266'
Perfs@ 9,496'-9,516'
TD@ 9,591'
PBTD @ 9,560'
DV Tool ® 4,522'
DV Tool @ 5,676'
Casing Information
Label
1
3
Type
Surface
Production
OD
9-5/8"
5-1/2"
Weight
36 lb/ft
UNK
Depth Set
2,162'
9,569'
Hole Size
12-1/4"
7-7/8"
TOC
Surface
2,350'
Volume
880 sks
5,450 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-337932
RRC District No: 8-A
Drawn: KAS
E. Randall No. 40
State/Province: Texas
Spud Date: 12/04/1992
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
E-7B
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
A
Perfs (5) 9,536' - 9,540'
SI
[S
: . I
DV Tool @ 5,968'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54 lb/ft
36 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,129'
5,606'
9,699'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
Surface
Volume
1,790 sks
2,910 sks
1,590 sks
2-3/8" Tubing & Packer Set @ 9,331'
TD @ 9,700'
PBTD @ 9,654'
MD
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN • HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-33885
RRC District No: 8-A
Drawn: KAS
E. Randall No. 41L E-7C
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,533' - 9,553'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,167'
5,830'
9,658'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
440'
1,800'
Volume
1,530 sks
3,500 sks
1,050 sks
DV Tool ® 7,414'
2-3/8" Tubing & Packer Set @ 8,970'
TD @ 9,660' \-(3)
PBTD @ 9,623' W
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34023
RRC District No: 8-A
Drawn: KAS
E. Randall No. 42L
E-7D
State/Province: Texas
Spud Date: 07/01/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Li;.
Perfs @ 9,550' - 9,538'
9,603'-9,610'
sf.
.... «¦
*'¦ •-
4/?
¦A ¦
" B ¦'
" ¦ /
?
, 4' i
,
"4
t" '
'*¦ ?r
. v.
> .¦
"A
' 'i
;
¦ 'v
„ .: '
4* •"
/
CIBP ® 8,917'
CIBP @ 9,590'
TD @ 9,740'
PBTD @ 8,917'
rv@
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,166'
5,902'
9,735'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
2,000'
Volume
1,530 sks
3,505 sks
967 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-34016
RRC District No: 8-A
Drawn: KAS
E. Randall No. 43L E-7E
State/Province: Texas
Spud Date: 04/08/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs @ 8,762' - 8,782'
(Sqz w/100 sx)
Perfs @8,822'-8,831'
(Sqz w/ 75 sx)
Perfs @ 9,562' - 9,570'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
29 lb/ft
Depth Set
2,158'
5,904'
9,620'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,600'
Volume
1,450 sks
5,190 sks
1,100 sks
DV Tool ® 7,482'
2-3/8" Tubing & Packer Set @ 9,552'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34024
RRC District No: 8-A
Drawn: KAS
E. Randall No. 44 E_7F
State/Province: Texas
Spud Date: 08/09/1995
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
Perfs (5) 9,565' - 9,575'
Casing/Tubing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
7"
Weight
54.5 lb/ft
40 lb/ft
23 lb/ft
26 lb/ft
Depth Set
2,175'
5,898'
9,615'
Hole Size
17-1/2"
12-1/4"
8-3/4"
TOC
Surface
Surface
1,500'
Volume
1,530 sks
3,525 sks
1,170 sks
DV Tool ® 7,508'
2-3/8" Tubing Set @ 9,580'
Packer Set (5) 9,394'
TD @ 9,684'
PBTD @ 9,593'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Exxon Corp.
Country: USA
Location: Section 833, Block D
API No: 42-501-34017
RRC District No: 8-A
Drawn: KAS
E. Randall No. 45L E-7G
State/Province: Texas
Spud Date: 02/05/1994
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
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Perfs (5) 9,504' - 9,512'
TD @ 9,650'
PBTD @ 9,594'
Casing/Tubing
Information
Label
1
2
Type
Surface
Production
OD
8-5/8"
5-1/2"
Weight
24 lb/ft
17 lb/ft
Depth Set
2,120'
9,650'
Hole Size
11"
7-7/8"
TOC
Surface
Surface
Volume
900 sks
3,400 sks
DV Tool ® 8,656' & 8,674'
2-7/8" Tubing & Packer Set @ 9,184'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
XTO Energy, Inc.
Country: USA
Location: Section 833, Block D
API No: 42-501-35418
RRC District No: 8-A
Drawn: KAS
E. Randall No. 46 e-7H
State/Province: Texas
Spud Date: 05/23/2007
Field: Bruce (Silurian)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 66970
Date: 05/31/2022
Approved: SLP
-------
u
Cement Plug #4
@48'-60'
Cement Plug #3
@ 270' - 450'
Cement Plug #1
@7,549'-8,000'
Perfs @ 8,292' - 8,428'
Cement Plug #2
@3,273'-3,439'
Top of Cut @ 750'
Top of Cut @ 1,439'
TD ® 9,645'
v@
Casing Information
Label
1
2
3
Type
Surface
Intermediate
Production
OD
13-3/8"
9-5/8"
5-1/2"
Depth Set
300'
3,200'
9,610'
TOC
Surface
Surface
Surface
Volume
400 sks
300 sks
425 sks
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Bonanza Oil Corp.
Country: USA
Location: Section 832, Block D
API No: 42-501-10046
RRC District No: 8-A
Drawn: KAS
C.A. Elliott No. 2 E-7I
State/Province: Texas
Spud Date: 05/10/1965
Field: Wasson (Wichita Albany)
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
RRC Lease Number: 18875
Date: 05/31/2022
Approved: SLP
-------
2,000'D—
2,500'D—
3,000'D—
3,500'D—
5,500'D—
6,000'D—
6,500'D—
7,000'D—
7,500'D—
8,000'D—
8,500'D—
9,000'D—
11,000'D—
11,500'D—
12,000'D—
12,500'D—
w
if.
II
: . I
Casing/Tubing Information
I ahol I 1 I 0 I ^
Surface
3-1/2" Tubing & Packer Set @ 10,650'
MD
TD @ 13,000'
LONQUIST & CO. LLC
PETROLEUM
ENERGY
ENGINEERS
ADVISORS
AUSTIN - HOUSTON 1 CALGARY - WICHITA
DENVER • COLLEGE STATION | BATON ROUGE • EDMONTON
Texas License F-9147
12912 Hill Country Blvd. Ste F-200
Austin, Texas 78738
Tel: 512.732.9812
Fax: 512.732.9816
Amtex Energy, Inc.
Country: USA
Location: Section 732, Block D
API No: 42-501-37252
RRC District No: 7-C
Drawn: KAS
Miller SWD No. 7 (Permitted) E-7J
State/Province: Texas
Spud Date: 08/09/1995
Field: Wasson
Project No: LS 128
Reviewed: RKH
Notes:
County/Parish: Yoakum
Survey: John H. Gipson
Permit Number: 16637
Date: 05/31/2022
Approved: SLP
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