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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAboutAIO 046AIO 46
Southern Miluveach Unit
Kuparuk River Oil Pool
North Slope Borough, Alaska
1. June 3, 2024 Mustang Application for Area Injection Order for the Kuparuk Oil
Pool
2. July 12, 2024 AOGCC Notice of Public Hearing and Affidavit
3. September 25, 2025 Mustang Request for Verbal Approval
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 W. 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Mustang
Holding, LLC to gain authorization to
inject fluids for pressure maintenance
and enhanced recovery of
hydrocarbons in the Southern
Miluveach Unit, Kuparuk River Oil
Pool
)
)
)
)
)
)
)
Area Injection Order 46
Kuparuk River Oil Pool
Southern Miluveach Unit
North Slope Borough, Alaska
February 11, 2026
ERRATA NOTICE
The Alaska Oil and Gas Conservation Commission (AOGCC) notes that Area Injection Order 46
(AIO 46) had an error in one rule. Namely, the second paragraph of Rule 2, which states:
In lieu of the packer depth requirements under 20 AAC 25.412(b), the
packer/isolation equipment for injection wells may be located above 200 feet
measured depth (MD) from above the top of the perforations/open interval but
must be located below the base of the confining zone and shall have outer casing
cement volume sufficient to place a minimum of 300 feet MD above the planned
packer depth.
Mustang Holding LLC had requested that the packer could be located above 200 feet measured
depth from the top of the perforated/open interval where injection occurs but that it must be
located below the top of the confining zone, but AIO 46 inadvertently stated the packer had to be
located below the base of the confining zone. The rule that Mustang proposed is a common rule
in injection orders issued by the AOGCC with the setting depth requirement being below the top
of the confining zone. As such the order will be corrected and this correction will be reflected in
a revised AIO 46 to be issued by the AOGCC.
DONE at Anchorage, Alaska and dated February 11, 2026.
Jessie L. Chmielowski Gregory C. Wilson Thomas W. McKay
Commissioner Commissioner Commissioner
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2026.02.11
08:31:10 -09'00'
Gregory C
Wilson
Digitally signed by Gregory C
Wilson
Date: 2026.02.11 08:38:57
-09'00'
Thomas W.
McKay
Digitally signed by
Thomas W. McKay
Date: 2026.02.11
13:01:36 -09'00'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Mustang
Holding LLC to gain authorization to
inject fluids for pressure maintenance and
enhanced recovery of hydrocarbons in the
Southern Miluveach Unit, Kuparuk River
Oil Pool
)
)
)
)
)
)
)
)
)
Area Injection Order 46 Corrected
Docket Number: AIO-24-018
Southern Miluveach Unit
Kuparuk River Oil Pool
North Slope Borough, Alaska
February 11, 2026
Nunc pro tunc September 25, 2025
IT APPEARING THAT:
1. By application dated June 3, 2024 (Application), Mustang Holding LLC (MHLLC), in its
capacity of operator of the Southern Miluveach Unit (SMU), requested an Area Injection Order
(AIO) authorizing injection of fluids for pressure maintenance and enhanced recovery of
hydrocarbons from the Kuparuk River Oil Pool (KROP) within the SMU (the portion of the
KROP within the SMU and the Affected Area of this order are referred to as the SMU-KROP).
2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC)
tentatively scheduled a public hearing for August 27, 2024. On July 12, 2024, the AOGCC
published notice of that hearing on the State of Alaska’s Online Public Notice website and on
the AOGCC’s website and electronically transmitted the notice to all persons on the AOGCC’s
email distribution list. On July 17, 2024, the notice was published in the ANCHORAGE
DAILY NEWS.
3. The AOGCC received no comments or requests to hold the proposed hearing. The hearing was
vacated.
4. MHLLC submitted updated information mid-September 2025, concerning fracture gradients
and injection pressures, that was taken into consideration as an accessory to the Application.
5. MHLLC’s application, supplemental information, and AOGCC’s public records provide
sufficient information to make an informed decision.
FINDINGS:
1. Order History
Area Injection Order 42 (AIO 42), issued June 12, 2019, defined rules governing the injection
of fluids for pressure maintenance and enhanced recovery of hydrocarbons for the SMU-
KROP, with Brooks Range Petroleum Corporation (BRPC) as the designated operator. On
December 4, 2020, MHLLC succeeded BRPC as operator of the SMU. In accordance with 20
AAC 25.402(i) AIO 42 automatically expired on June 12, 2021, due to injection not starting
prior to that date.
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 2 of 11
2. Affected Area
The Affected Area lies onshore within the SMU, North Slope Borough, Alaska, about 45
miles west-southwest of Prudhoe Bay. The SMU-KROP is being developed from the SMU
Mustang drill site, a gravel pad located in Section 2, Township (T) 10N, Range (R) 7E, Umiat
Meridian (UM).
3. Owners and Landowners
Mustang Holding, LLC is the operator of the SMU. Working interest owners are Mustang
Holding, LLC, Mustang Operations Center 1, LLC, Mustang Investment Holdings, LLC, and
Alaska Venture Capital Group, LLC. The State of Alaska, Department of Natural Resources
is the surface and subsurface landowner of the Affected Area.
4. Exploration, Delineation, and Production History
During January 2012, BRPC drilled the discovery well—North Tarn 1A (Permit to Drill No.
211-174)—into the Kuparuk Formation (Kuparuk) in Section 2, T10N, R7E, UM, and
encountered oil indicators. This discovery was confirmed by the Mustang 1 exploratory well
(Permit to Drill No. 212-174) in February 2012. To date, five wells have been logged across
the Kuparuk reservoir within the SMU.
Three-dimensional seismic survey and well log data have been used to determine the geologic
structure and reservoir distribution for the SMU-KROP. Well log, well test, and Operator-
supplied information were used to establish reservoir and fluid properties for the pool.
5. Pool Identification
The KROP, defined in Conservation Order 432F (CO 432F), is the accumulation of oil that is
common to and correlates with the accumulation found in the Atlantic Richfield Company
West Sak River State No. 1 well between the depths of 6,474- and 6,880-feet MD (Permit to
Drill No. 171-003). Along with the SMU, portions of this expansive oil pool also lie within
the adjoining Kuparuk River Unit (KRU) and the nearby Milne Point Unit (MPU).
6. Geology
a. Structure: The Colville Anticline is the regional structural trap for the SMU-KROP. The
SMU lies on a portion of that anticline. Within the SMU, the SMU-KROP ranges in
depth from about -5,800 to -6,400 feet TVDSS.1
b. Stratigraphy:
Within the SMU, Cretaceous-aged reservoir sandstones within the Kuparuk Formation
are informally divided into two intervals, the Kuparuk C-Sands (C-Sand) and the
underlying Kuparuk A-Sands (A-Sand). The C-Sand consists of bioturbated and
burrowed glauconitic sandstones, shaley sandstones, siltstones, and shales. These
sediments were most likely deposited in an offshore marine-shelf setting. The thickness
of the C-Sand interval varies from 0 to 25 feet within the SMU, and this variation is
believed to have been influenced by syndepositional fault activity.
1 To avoid confusion, when depths presented represent true vertical depth below sea level (subsea), the footage will be preceded
by a minus sign and followed by the acronym TVDSS (e.g., 5,800 feet true vertical subsea is depicted as -5,800 feet TVDSS).
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 3 of 11
The regional Lower Cretaceous Unconformity (LCU) separates the C-Sand from the
underlying A-Sands, and it progressively truncates the A-Sand intervals from southeast
to northwest across the SMU.
Within the SMU, the A-Sands consist of two upward-coarsening intervals that were
deposited in an offshore marine setting. Here, the A-Sands are subdivided into intervals
informally named “A4” and “A3”, in descending order. The thickness of A4 varies from
0 to 36 feet from northwest to southeast across the SMU. Interval A3 varies from 2 to
40 feet in thickness from northwest to southeast within the SMU. The thickness trends
of the A-Sands do not appear to be influenced by faulting or the present-day structure.
c. Rock Properties: The C-Sand comprises fine- to coarse-grained quartzose sandstone that
contains up to 40 percent glauconite and is commonly cemented with secondary siderite.
Porosity averages 22 percent. Permeability ranges from 50 to several hundred
millidarcies (md), averaging 70 md. Water saturation with the C-Sand can be as low as
20 percent.
The underlying A-Sand consists of very fine- to fined-grained sandstone interbedded
with siltstone and mudstone. Porosity averages 22 percent. Permeability ranges from
less than 10 to 100 md, averaging 30 md. Water saturation in the A-Sand can be as high
as 40 percent.
d. Faults: Two sets of faults cut the Colville Anticline within the SMU; one set trends
north-northeast, and the other set trends west-northwest. The vertical displacement of
faults cutting the proposed SMU-KROP ranges up to 85 feet but is generally less than
30 feet. Because of the relatively thin-bedded nature of reservoir sands within the
proposed pool, some faults may act as localized flow barriers and may result in reservoir
compartments.
e. Trap Configuration and Seals: Well log and seismic information indicate that structural
dip controls the hydrocarbon accumulation within the SMU-KROP. The overlying
Kalubik and HRZ Shales form the top seal for the oil accumulation within the proposed
pool.
7. Reservoir Continuity
Many faults cut the KROP within the Affected Area. As mapped using 3D seismic, these
faults have vertical displacements that are generally less than 30 feet. However, some
compartmentalization of the pool is expected due to the thin nature of the reservoir strata,
especially in the western portion of the Affected Area.
8. Reservoir Fluid Contacts
To date, no hydrocarbon contacts have been encountered in the Kuparuk reservoirs within the
Affected Area.
9. Reservoir Fluid Properties
In the SMU-KROP area, the initial producing gas oil ratio (GOR) is estimated to be about 600
standard cubic feet per stock tank barrel (scf/stb). The API gravity of oil recovered from the
proposed pool measured about 24° in the North Tarn 1A well. Due to injection activities in
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 4 of 11
the KROP within the adjoining KRU, pressure in the SMU-KROP measured as high as 3,850
psi. Bubble-point pressure is estimated to be 1,930 psi. The oil formation volume factor is
estimated at 1.2 reservoir barrels per stock tank barrel of oil.
10. In-Place and Recoverable Volume Estimates (based on reservoir modeling predictions)
11. Future Development Plans
MHLLC has plans to develop the pool from the existing SMU “Mustang” drill site, through
multiple phases. Development includes reinstallation of production facilities, reconnecting
the Mustang Pipeline to the Alpine Pipeline for access to the Trans-Alaska Pipeline System
(TAPS), re-entering existing wells, and drilling additional wells. Well stock will involve up
to 11 horizontal or vertical development (production) wells and up to 10 horizontal or vertical
service (injection) wells, with most production wells trending north-south, parallel to the
direction of the major fault patterns that cut the pool. Some producers will produce from both
the C-Sand and the A-Sand. Injection wells may be placed to create alternating rows of
producer-injector pairs for line drive flood patterns. The length of the horizontal sections of
wells are planned to range up to 6000 feet. Depending upon reservoir quality, some producers
or injectors may be hydraulically fractured to enhance productivity and to enhance vertical
injection sweep.
12. Confining Layers for Injection
Approximately 260 feet of Kalubik and HRZ shales overlie the SMU-KROP. Several hundred
feet of shales assigned to the Miluveach and Kingak Formations underlie the SMU-KROP.
13. Fracture Propagation and Confinement
Kuparuk Formation fracture closure pressure was found via pressure decline analysis to be
0.67 psi/ft * 6,100’ TVD = 4,087 psi. Via history match of a frac in an offset well, it was
found that an increase of 1,000 psi above the Kuparuk closure pressure of 4,087 psi was
needed before excessive fracture height develops into confining shales: 4,087 psi + 1,000 psi
= 5,087 psi. The confining shale fracture gradient is therefore 5,087 psi / 6,100’ = 0.834 psi/ft.
A fracture propagation model showed that, at the planned estimated maximum injection
pressures for miscible water alternating gas (MWAG) or immiscible water alternating gas
(IWAG) service, fractures would form in the injection interval but would not initiate into or
2 The acronym MMSTB signifies millions of stock tank barrels.
Hydrocarbon Resource Estimated Volume2
Original Oil in Place (OOIP) 70 MMSTB
Primary Recovery (10-15% OOIP) 7-10.5 MMSTB
Primary + Water Injection (10-25% OOIP incremental) 7-17.5 MMSTB
Incremental
Primary + Water and Lean Gas Injection (1-5% OOIP
incremental)
0.7-3.5 MMSTB
Incremental
Primary + Water and Enriched Gas Injection (3-15% OOIP
incremental)
2.1-10.5 MMSTB
Incremental
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 5 of 11
propagate through confining strata. For fractures to propagate into the confining layers,
surface pressures during injection would have to exceed 2,391 psi with water and 4,477 psi
with gas.
14. Injection Pressures 3
Maximum injection pressures at the wellhead, for both water and gas, will be below the
confining zone fracture gradient of 0.834 psi/ft. For water, a maximum of 2,300 psi will be
well below the 2,391 psi that corresponds to the confining zone frac gradient. For gas, a
maximum of 4,400 psi will be well below the 4,477 psi that corresponds to the confining zone
frac gradient.
Average injection pressure on water is expected to be ~1,400 psi, very near the surface water
injection pressure of 1,391 psi that corresponds to the Kuparuk fracture gradient of 0.67 psi/ft.
15. Injection Rates
The anticipated peak daily injection rate for individual wells within the SMU-KROP is 6,000
barrels of water per day (BWPD) and 6 million standard cubic feet of gas per day (MMSCFD).
16. Freshwater Strata
No porosity logs have been recorded across the shallow geologic section within the SMU.
The former operator, BPRC, commissioned a formation water salinity determination using
logs from well West Sak 25590-15, which is located about 3 miles east of the SMU
development gravel pad. Well log calculations suggest that aquifers shallower than a depth of
about 2,300 feet MD (-2,140 feet TVDSS) within the SMU may contain native formation
waters that have total dissolved solids concentrations of less than 10,000 mg/l. However,
MHLLC will isolate these aquifers by setting the surface casing at -2,500 feet TVDSS and
cementing it to surface.
17. Aquifer Exemption Order
MHLLC’s Application contends that the US Environmental Protection Agency’s (EPA)
Aquifer Exemption for the Kuparuk River Unit (KRU), defined in 1984 by 40 CFR
147.102(b)(3), still applies to the current area of the SMU. The exact boundary of that Aquifer
Exemption is currently under review by the EPA.
CONCLUSIONS:
1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil
recovery purposes in the SMU-KROP within the SMU.
2. The Aquifer Exemption for the KRU—as described in Federal Regulation 40
CFR147.102(b)(3)—currently applies to the SMU-KROP. However, if subsequent EPA
review determines that the SMU-KROP falls outside of the affected area for the KRU Aquifer
Exemption, MHLLC must apply for a new Aquifer Exemption.
3. Reservoir simulation modeling shows water and water-alternating-gas injection (both
immiscible water alternating gas (IWAG) and miscible water alternating gas (MWAG)) into
3 For fracture gradient calculations, 0.442 psi/ft was used for water, 0.1 psi/ft for gas, and -6,100’ TVDSS for depth.
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 6 of 11
the SMU-KROP will provide a substantial EOR benefit over primary recovery alone,
maximize ultimate recovery from the SMU-KROP, and prevent waste.
4. The maximum wellhead injection pressures of 2,300 psig during water injection and 4,400 psi
during gas injection are well below the pressures needed to initiate fractures in the confining
intervals. As such, the confining intervals will ensure that injected fluids remain in the SMU-
KROP.
NOW THEREFORE IT IS ORDERED:
The underground injection of fluids for pressure maintenance and enhanced recovery is authorized
in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded
by these rules:
Affected Area (Revised this order):
Umiat Meridian
Township/Range Sections
10N-7E 1-4, 9-12
11N-7E 24-26, 34-36
Table 1. Legal Description of Affected Area
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 7 of 11
Figure 1. Extent of Affected Area
(Source: Mustang Holding LLC)
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 8 of 11
Rule 1: Authorized Injection Strata for Enhanced Recovery
Within the Affected Area, Class II fluids may be injected for the purposes of pressure maintenance
and enhanced recovery into strata defined as those which correlate with, and are common to, the
formation found in the North Tarn 1Awell (Permit to Drill No. 211-051) between measured depths
of 6,130 feet and 6,212 feet (see Figure 2, below).
Figure 2. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool
Kuparuk
River Oil
Pool
C-Sand
A4-Sand
A3-Sand
Lower Cretaceous Unconformity
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 9 of 11
Rule 2: Fluid Injection Wells and Well Construction
The injection of fluids must be conducted through a new well that has been permitted for drilling
as a service well for injection in conformance with 20 AAC 25.005, or through an existing well
that AOGCC has approved for conversion to a service well for injection in conformance with 20
AAC 25.280.
In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation
equipment for injection wells may be located above 200 feet measured depth (MD) from above
the top of the perforations/open interval but must be located below the top of the confining zone
and shall have outer casing cement volume sufficient to place a minimum of 300 feet MD above
the planned packer depth.
Rule 3: Authorized Fluids for Injection for Enhanced Recovery
Fluids authorized for injection are:
a. Source water from the KRU seawater treatment plant;
b. Produced water from the SMU-KROP, produced water from other as yet undefined oil
pools in the SMU if authorized administratively after showing they will be compatible
with the SMU-KROP formation and fluids;
c. Enriched hydrocarbon gas (MI): a blend of KRU lean gas with indigenous and/or
imported natural gas liquids;
d. Lean hydrocarbon gas;
e. Fluids used during hydraulic stimulation;
f. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive,
etc.);
g. Fluids used to improve near wellbore injectivity (e.g., acid washes, scale inhibition
treatments, etc.);
h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency
(e.g., cement, resin, etc.);
i. Fluids associated with freeze protection (diesel, glycol, methanol, etc.); and
j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.).
Rule 4: Authorized Injection Pressure for Enhanced Recovery
Maximum injection pressures shall be well below the confining zone fracture gradient of 0.834
psi/ft, to ensure containment of injected fluids within the defined injection interval of the defined
Affected Area. Maximum wellhead injection pressures shall be 2,300 psig during water injection
and 4,400 psig during gas injection.
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 10 of 11
Rule 5: Monitoring Tubing-Casing Annulus Pressure
Inner annulus, outer annulus, and tubing pressures shall be monitored and recorded at least daily,
except if prevented by extreme weather condition, emergency situation, or similar unavoidable
circumstances for all injection and production wells. The outer annulus pressures of all wells that
are not cemented across the SMU-KROP and are located within a one-quarter mile radius of a
SMU-KROP injector shall be monitored daily. All monitoring results shall be documented and
available for AOGCC inspection.
Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity
The mechanical integrity of each injection well must be demonstrated before injection begins and
before returning a well to service following any workover affecting mechanical integrity. An
AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is
commenced for the first time in a well, to be scheduled when injection conditions (temperature,
pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four
years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a
representative to witness an MIT.
Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated
by a tubing/casing annulus pressure test using a surface pressure equivalent to the maximum
injection pressure, or 1,500 psi, whichever is greater, that shows stabilizing pressure and does not
change more than 10 percent during a 30-minute period. Results of MITs must be readily available
for AOGCC inspection.
Rule 7: Well Integrity and Confinement
Whenever an indication of pressure communication, leakage, or lack of zone isolation occurs, the
operator must notify the AOGCC by the next business day. Such indication may arise from
information including but not limited to injection rate change, operating pressure change, test,
survey, log, or outer annulus pressure monitoring in wells within a one-quarter mile radius of
where the SMU-KROP is not cemented. The operator shall notify the AOGCC by the next business
day and submit a plan of corrective action on an Application for Sundry Approvals Form 10-403
for AOGCC approval. The operator must shut-in any well for which: (a) continued operation
would be unsafe, (b) continued operation would threaten communication of freshwater, or (c) the
AOGCC directs the operator to shut-in the well.
A monthly report of daily tubing and casing annuli pressures and injection rates must be provided
to the AOGCC for all injection wells that: (a) are subject to administrative approval (AA) to
operate, or (b) lack injection zone isolation.
Rule 8: Notification of Improper Class II Injection
Injection of fluids other than those listed in Rule 3 without prior authorization is considered
improper Class II injection. Upon discovery of such an event, the operator must immediately notify
the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This
requirement is in addition to, and does not relieve the operator of, any other obligations under the
notification requirements of any other State or Federal agency, regulation or law.
AIO 46 Corrected
February 11, 2026
Nunc pro tunc September 25, 2025
Page 11 of 11
Rule 9: Other Conditions
If fluids are found to be fracturing the confining zone or migrating out of the approved injection
stratum, the operator must immediately shut in the injection wells and immediately notify the
AOGCC. Injection must not be restarted unless approved by the AOGCC.
DONE at Anchorage, Alaska and dated February 11, 2026, nunc pro tunc September 25, 2025.
Jessie L. Chmielowski Gregory C. Wilson Thomas W. McKay
Commissioner Commissioner Commissioner
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as
the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of
the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration
must set out the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to
act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision
and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days
after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying
reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on
which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision
on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal
MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the
order or decision on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included
in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs
until 5:00 p.m. on the next day that does not fall on a weekend or state holiday.
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2026.02.11
08:33:22 -09'00'
Gregory C
Wilson
Digitally signed by
Gregory C Wilson
Date: 2026.02.11 08:39:53
-09'00'
Thomas W.
McKay
Digitally signed by Thomas
W. McKay
Date: 2026.02.11 10:58:58
-09'00'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Mustang
Holding LLC to gain authorization to
inject fluids for pressure maintenance and
enhanced recovery of hydrocarbons in the
Southern Miluveach Unit, Kuparuk River
Oil Pool
)
)
)
)
)
)
)
)
Docket Number: AIO-24-018
Area Injection Order 46
Southern Miluveach Unit
Kuparuk River Oil Pool
North Slope Borough, Alaska
September 25, 2025
IT APPEARING THAT:
1. By application dated June 3, 2024 (Application), Mustang Holding LLC (MHLLC), in its
capacity of operator of the Southern Miluveach Unit (SMU), requested an Area Injection Order
(AIO) authorizing injection of fluids for pressure maintenance and enhanced recovery of
hydrocarbons from the Kuparuk River Oil Pool (KROP) within the SMU (the portion of the
KROP within the SMU and the Affected Area of this order are referred to as the SMU-KROP).
2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC)
tentatively scheduled a public hearing for August 27, 2024. On July 12, 2024, the AOGCC
published notice of that hearing on the State of Alaska’s Online Public Notice website and on
the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s
email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons
on the AOGCC’s mailing distribution list. On July 17, 2024, the notice was published in the
ANCHORAGE DAILY NEWS.
3. The AOGCC received no comments or requests to hold the proposed hearing. The hearing was
vacated.
4. MHLLC submitted updated information mid-September 2025, concerning fracture gradients
and injection pressures, that was taken into consideration as an accessory to the Application.
5. MHLLC’s application, supplemental information, and AOGCC’s public records provide
sufficient information to make an informed decision.
FINDINGS:
1. Order History
Area Injection Order 42 (AIO 42), issued June 12, 2019, defined rules governing the injection
of fluids for pressure maintenance and enhanced recovery of hydrocarbons for the SMU-
KROP, with Brooks Range Petroleum Corporation (BRPC) as the designated operator. On
December 4, 2020, MHLLC succeeded BRPC as operator of the SMU. In accordance with 20
AAC 25.402(i) AIO 42 automatically expired on June 12, 2021, due to injection not starting
prior to that date.
AIO 46
September 25, 2025
Page 2 of 11
2. Affected Area
The Affected Area lies onshore within the SMU, North Slope Borough, Alaska, about 45
miles west-southwest of Prudhoe Bay. The SMU-KROP is being developed from the SMU
Mustang drill site, a gravel pad located in Section 2, Township (T) 10N, Range (R) 7E, Umiat
Meridian (UM).
3. Owners and Landowners
Mustang Holding, LLC is the operator of the SMU. Working interest owners are Mustang
Holding, LLC, Mustang Operations Center 1, LLC, Mustang Investment Holdings, LLC, and
Alaska Venture Capital Group, LLC. The State of Alaska, Department of Natural Resources
is the surface and subsurface landowner of the Affected Area.
4. Exploration, Delineation, and Production History
During January 2012, BRPC drilled the discovery well—North Tarn 1A (Permit to Drill No.
211-174)—into the Kuparuk Formation (Kuparuk) in Section 2, T10N, R7E, UM, and
encountered oil indicators. This discovery was confirmed by the Mustang 1 exploratory well
(Permit to Drill No. 212-174) in February 2012. To date, five wells have been logged across
the Kuparuk reservoir within the SMU.
Three-dimensional seismic survey and well log data have been used to determine the geologic
structure and reservoir distribution for the SMU-KROP. Well log, well test, and Operator-
supplied information were used to establish reservoir and fluid properties for the pool.
5. Pool Identification
The KROP, defined in Conservation Order 432F (CO 432F), is the accumulation of oil that is
common to and correlates with the accumulation found in the Atlantic Richfield Company
West Sak River State No. 1 well between the depths of 6,474- and 6,880-feet MD (Permit to
Drill No. 171-003). Along with the SMU, portions of this expansive oil pool also lie within
the adjoining Kuparuk River Unit (KRU) and the nearby Milne Point Unit (MPU).
6. Geology
a. Structure: The Colville Anticline is the regional structural trap for the SMU-KROP. The
SMU lies on a portion of that anticline. Within the SMU, the SMU-KROP ranges in
depth from about -5,800 to -6,400 feet TVDSS.1
b. Stratigraphy:
Within the SMU, Cretaceous-aged reservoir sandstones within the Kuparuk Formation
are informally divided into two intervals, the Kuparuk C-Sands (C-Sand) and the
underlying Kuparuk A-Sands (A-Sand). The C-Sand consists of bioturbated and
burrowed glauconitic sandstones, shaley sandstones, siltstones, and shales. These
sediments were most likely deposited in an offshore marine-shelf setting. The thickness
of the C-Sand interval varies from 0 to 25 feet within the SMU, and this variation is
believed to have been influenced by syndepositional fault activity.
1 To avoid confusion, when depths presented represent true vertical depth below sea level (subsea), the footage will be preceded
by a minus sign and followed by the acronym TVDSS (e.g., 5,800 feet true vertical subsea is depicted as -5,800 feet TVDSS).
AIO 46
September 25, 2025
Page 3 of 11
The regional Lower Cretaceous Unconformity (LCU) separates the C-Sand from the
underlying A-Sands, and it progressively truncates the A-Sand intervals from southeast
to northwest across the SMU.
Within the SMU, the A-Sands consist of two upward-coarsening intervals that were
deposited in an offshore marine setting. Here, the A-Sands are subdivided into intervals
informally named “A4” and “A3”, in descending order. The thickness of A4 varies from
0 to 36 feet from northwest to southeast across the SMU. Interval A3 varies from 2 to
40 feet in thickness from northwest to southeast within the SMU. The thickness trends
of the A-Sands do not appear to be influenced by faulting or the present-day structure.
c. Rock Properties: The C-Sand comprises fine- to coarse-grained quartzose sandstone that
contains up to 40 percent glauconite and is commonly cemented with secondary siderite.
Porosity averages 22 percent. Permeability ranges from 50 to several hundred
millidarcies (md), averaging 70 md. Water saturation with the C-Sand can be as low as
20 percent.
The underlying A-Sand consists of very fine- to fined-grained sandstone interbedded
with siltstone and mudstone. Porosity averages 22 percent. Permeability ranges from
less than 10 to 100 md, averaging 30 md. Water saturation in the A-Sand can be as high
as 40 percent.
d. Faults: Two sets of faults cut the Colville Anticline within the SMU; one set trends
north-northeast, and the other set trends west-northwest. The vertical displacement of
faults cutting the proposed SMU-KROP ranges up to 85 feet but is generally less than
30 feet. Because of the relatively thin-bedded nature of reservoir sands within the
proposed pool, some faults may act as localized flow barriers and may result in reservoir
compartments.
e. Trap Configuration and Seals: Well log and seismic information indicate that structural
dip controls the hydrocarbon accumulation within the SMU-KROP. The overlying
Kalubik and HRZ Shales form the top seal for the oil accumulation within the proposed
pool.
7. Reservoir Continuity
Many faults cut the KROP within the Affected Area. As mapped using 3D seismic, these
faults have vertical displacements that are generally less than 30 feet. However, some
compartmentalization of the pool is expected due to the thin nature of the reservoir strata,
especially in the western portion of the Affected Area.
8. Reservoir Fluid Contacts
To date, no hydrocarbon contacts have been encountered in the Kuparuk reservoirs within the
Affected Area.
9. Reservoir Fluid Properties
In the SMU-KROP area, the initial producing gas oil ratio (GOR) is estimated to be about 600
standard cubic feet per stock tank barrel (scf/stb). The API gravity of oil recovered from the
proposed pool measured about 24° in the North Tarn 1A well. Due to injection activities in
the KROP within the adjoining KRU, pressure in the SMU-KROP measured as high as 3,850
AIO 46
September 25, 2025
Page 4 of 11
psi. Bubble-point pressure is estimated to be 1,930 psi. The oil formation volume factor is
estimated at 1.2 reservoir barrels per stock tank barrel of oil.
10. In-Place and Recoverable Volume Estimates (based on reservoir modeling predictions)
11. Future Development Plans
MHLLC has plans to develop the pool from the existing SMU “Mustang” drill site, through
multiple phases. Development includes reinstallation of production facilities, reconnecting
the Mustang Pipeline to the Alpine Pipeline for access to the Trans-Alaska Pipeline System
(TAPS), re-entering existing wells, and drilling additional wells. Well stock will involve up
to 11 horizontal or vertical development (production) wells and up to 10 horizontal or vertical
service (injection) wells, with most production wells trending north-south, parallel to the
direction of the major fault patterns that cut the pool. Some producers will produce from both
the C-Sand and the A-Sand. Injection wells may be placed to create alternating rows of
producer-injector pairs for line drive flood patterns. The length of the horizontal sections of
wells are planned to range up to 6000 feet. Depending upon reservoir quality, some producers
or injectors may be hydraulically fractured to enhance productivity and to enhance vertical
injection sweep.
12. Confining Layers for Injection
Approximately 260 feet of Kalubik and HRZ shales overlie the SMU-KROP. Several hundred
feet of shales assigned to the Miluveach and Kingak Formations underlie the SMU-KROP.
13. Fracture Propagation and Confinement
Kuparuk Formation fracture closure pressure was found via pressure decline analysis to be
0.67 psi/ft * 6,100’ TVD = 4,087 psi. Via history match of a frac in an offset well, it was
found that an increase of 1,000 psi above the Kuparuk closure pressure of 4,087 psi was
needed before excessive fracture height develops into confining shales: 4,087 psi + 1,000 psi
= 5,087 psi. The confining shale fracture gradient is therefore 5,087 psi / 6,100’ = 0.834
psi/ft.
A fracture propagation model showed that, at the planned estimated maximum injection
pressures for miscible water alternating gas (MWAG) or immiscible water alternating gas
(IWAG) service, fractures would form in the injection interval but would not initiate into or
propagate through confining strata. For fractures to propagate into the confining layers,
2 The acronym MMSTB signifies millions of stock tank barrels.
Hydrocarbon Resource Estimated Volume2
Original Oil in Place (OOIP) 70 MMSTB
Primary Recovery (10-15% OOIP) 7-10.5 MMSTB
Primary + Water Injection (10-25% OOIP incremental) 7-17.5 MMSTB
Incremental
Primary + Water and Lean Gas Injection (1-5% OOIP
incremental)
0.7-3.5 MMSTB
Incremental
Primary + Water and Enriched Gas Injection (3-15% OOIP
incremental)
2.1-10.5 MMSTB
Incremental
AIO 46
September 25, 2025
Page 5 of 11
surface pressures during injection would have to exceed 2,391 psi with water and 4,477 psi
with gas.
14. Injection Pressures 3
Maximum injection pressures at the wellhead, for both water and gas, will be below the
confining zone fracture gradient of 0.834 psi/ft. For water, a maximum of 2,300 psi will be
well below the 2,391 psi that corresponds to the confining zone frac gradient. For gas, a
maximum of 4,400 psi will be well below the 4,477 psi that corresponds to the confining zone
frac gradient.
Average injection pressure on water is expected to be ~1,400 psi, very near the surface water
injection pressure of 1,391 psi that corresponds to the Kuparuk fracture gradient of 0.67 psi/ft.
15. Injection Rates
The anticipated peak daily injection rate for individual wells within the SMU-KROP is 6,000
barrels of water per day (BWPD) and 6 million standard cubic feet of gas per day (MMSCFD).
16. Freshwater Strata
No porosity logs have been recorded across the shallow geologic section within the SMU.
The former operator, BPRC, commissioned a formation water salinity determination using
logs from well West Sak 25590-15, which is located about 3 miles east of the SMU
development gravel pad. Well log calculations suggest that aquifers shallower than a depth of
about 2,300 feet MD (-2,140 feet TVDSS) within the SMU may contain native formation
waters that have total dissolved solids concentrations of less than 10,000 mg/l. However,
MHLLC will isolate these aquifers by setting the surface casing at -2,500 feet TVDSS and
cementing it to surface.
17. Aquifer Exemption Order
MHLLC’s Application contends that the US Environmental Protection Agency’s (EPA)
Aquifer Exemption for the Kuparuk River Unit (KRU), defined in 1984 by 40 CFR
147.102(b)(3), still applies to the current area of the SMU. The exact boundary of that Aquifer
Exemption is currently under review by the EPA.
CONCLUSIONS:
1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil
recovery purposes in the SMU-KROP within the SMU.
2. The Aquifer Exemption for the KRU—as described in Federal Regulation 40
CFR147.102(b)(3)—currently applies to the SMU-KROP. However, if subsequent EPA
review determines that the SMU-KROP falls outside of the affected area for the KRU Aquifer
Exemption, MHLLC must apply for a new Aquifer Exemption.
3. Reservoir simulation modeling shows water and water-alternating-gas injection (both
immiscible water alternating gas (IWAG) and miscible water alternating gas (MWAG)) into
3 For fracture gradient calculations, 0.442 psi/ft was used for water, 0.1 psi/ft for gas, and -6,100’ TVDSS for depth.
AIO 46
September 25, 2025
Page 6 of 11
the SMU-KROP will provide a substantial EOR benefit over primary recovery alone,
maximize ultimate recovery from the SMU-KROP, and prevent waste.
4. The maximum wellhead injection pressures of 2,300 psig during water injection and 4,400
psi during gas injection are well below the pressures needed to initiate fractures in the
confining intervals. As such, the confining intervals will ensure that injected fluids remain in
the SMU-KROP.
NOW THEREFORE IT IS ORDERED:
The underground injection of fluids for pressure maintenance and enhanced recovery is authorized
in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded
by these rules:
Affected Area (Revised this order):
Umiat Meridian
Township/Range Sections
10N-7E 1-4, 9-12
11N-7E 24-26, 34-36
Table 1. Legal Description of Affected Area
AIO 46
September 25, 2025
Page 7 of 11
Figure 1. Extent of Affected Area
(Source: Mustang Holding LLC)
AIO 46
September 25, 2025
Page 8 of 11
Rule 1: Authorized Injection Strata for Enhanced Recovery
Within the Affected Area, Class II fluids may be injected for the purposes of pressure maintenance
and enhanced recovery into strata defined as those which correlate with, and are common to, the
formation found in the North Tarn 1Awell (Permit to Drill No. 211-051) between measured depths
of 6,130 feet and 6,212 feet (see Figure 2, below).
Figure 2. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool
Kuparuk
River Oil
Pool
C-Sand
A4-Sand
A3-Sand
Lower Cretaceous Unconformity
AIO 46
September 25, 2025
Page 9 of 11
Rule 2: Fluid Injection Wells and Well Construction
The injection of fluids must be conducted through a new well that has been permitted for drilling
as a service well for injection in conformance with 20 AAC 25.005, or through an existing well
that AOGCC has approved for conversion to a service well for injection in conformance with 20
AAC 25.280.
In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation
equipment for injection wells may be located above 200 feet measured depth (MD) from above
the top of the perforations/open interval but must be located below the base of the confining zone
and shall have outer casing cement volume sufficient to place a minimum of 300 feet MD above
the planned packer depth.
Rule 3: Authorized Fluids for Injection for Enhanced Recovery
Fluids authorized for injection are:
a. Source water from the KRU seawater treatment plant;
b. Produced water from the SMU-KROP, produced water from other as yet undefined oil
pools in the SMU if authorized administratively after showing they will be compatible
with the SMU-KROP formation and fluids;
c. Enriched hydrocarbon gas (MI): a blend of KRU lean gas with indigenous and/or
imported natural gas liquids;
d. Lean hydrocarbon gas;
e. Fluids used during hydraulic stimulation;
f. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive,
etc.);
g. Fluids used to improve near wellbore injectivity (e.g., acid washes, scale inhibition
treatments, etc.);
h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency
(e.g., cement, resin, etc.);
i. Fluids associated with freeze protection (diesel, glycol, methanol, etc.); and
j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.).
Rule 4: Authorized Injection Pressure for Enhanced Recovery
Maximum injection pressures shall be well below the confining zone fracture gradient of 0.834
psi/ft, to ensure containment of injected fluids within the defined injection interval of the defined
Affected Area. Maximum wellhead injection pressures shall be 2,300 psig during water injection
and 4,400 psig during gas injection.
Rule 5: Monitoring Tubing-Casing Annulus Pressure
Inner annulus, outer annulus, and tubing pressures shall be monitored and recorded at least daily,
except if prevented by extreme weather condition, emergency situation, or similar unavoidable
circumstances for all injection and production wells. The outer annulus pressures of all wells that
AIO 46
September 25, 2025
Page 10 of 11
are not cemented across the SMU-KROP and are located within a one-quarter mile radius of a
SMU-KROP injector shall be monitored daily. All monitoring results shall be documented and
available for AOGCC inspection.
Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity
The mechanical integrity of each injection well must be demonstrated before injection begins and
before returning a well to service following any workover affecting mechanical integrity. An
AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is
commenced for the first time in a well, to be scheduled when injection conditions (temperature,
pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four
years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a
representative to witness an MIT.
Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated
by a tubing/casing annulus pressure test using a surface pressure equivalent to the maximum
injection pressure, or 1,500 psi, whichever is greater, that shows stabilizing pressure and does not
change more than 10 percent during a 30-minute period. Results of MITs must be readily available
for AOGCC inspection.
Rule 7: Well Integrity and Confinement
Whenever an indication of pressure communication, leakage, or lack of zone isolation occurs, the
operator must notify the AOGCC by the next business day. Such indication may arise from
information including but not limited to injection rate change, operating pressure change, test,
survey, log, or outer annulus pressure monitoring in wells within a one-quarter mile radius of
where the SMU-KROP is not cemented. The operator shall notify the AOGCC by the next business
day and submit a plan of corrective action on an Application for Sundry Approvals Form 10-403
for AOGCC approval. The operator must shut-in any well for which: (a) continued operation
would be unsafe, (b) continued operation would threaten communication of freshwater, or (c) the
AOGCC directs the operator to shut-in the well.
A monthly report of daily tubing and casing annuli pressures and injection rates must be provided
to the AOGCC for all injection wells that: (a) are subject to administrative approval (AA) to
operate, or (b) lack injection zone isolation.
Rule 8: Notification of Improper Class II Injection
Injection of fluids other than those listed in Rule 3 without prior authorization is considered
improper Class II injection. Upon discovery of such an event, the operator must immediately notify
the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This
requirement is in addition to, and does not relieve the operator of, any other obligations under the
notification requirements of any other State or Federal agency, regulation or law.
Rule 9: Other Conditions
If fluids are found to be fracturing the confining zone or migrating out of the approved injection
stratum, the operator must immediately shut in the injection wells and immediately notify the
AOGCC. Injection must not be restarted unless approved by the AOGCC.
AIO 46
September 25, 2025
Page 11 of 11
DONE at Anchorage, Alaska and dated September 25, 2025.
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as
the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of
the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration
must set out the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to
act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision
and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days
after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying
reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on
which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision
on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal
MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the
order or decision on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included
in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs
until 5:00 p.m. on the next day that does not fall on a weekend or state holiday.
Gregory C Wilson Digitally signed by Gregory C Wilson
Date: 2025.09.25 16:39:54 -08'00'
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2025.09.25
16:51:26 -08'00'
From:Coldiron, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] Area Injection Order 46 (Mustang)
Date:Thursday, September 25, 2025 4:55:24 PM
Attachments:AIO46.pdf
Authorization to inject fluids for pressure maintenance and enhanced recovery of
hydrocarbons in the Southern Miluveach Unit, Kuparuk River Oil Pool
Samantha Coldiron
AOGCC Special Assistant
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
(907) 793-1223
__________________________________
List Name: AOGCC_Public_Notices@list.state.ak.us
You subscribed as: samantha.coldiron@alaska.gov
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v
3
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Josh Tempel
To:AOGCC Permitting (CED sponsored)
Cc:David Wages; Gabriela Keeton
Subject:Mustang AIO: Request for Verbal Approval
Date:Thursday, September 25, 2025 10:17:45 AM
Attachments:image001.png
Hello Chris,
We will be commissioning our gas compressors this morning, and it is strongly preferable from
both an engineering and wells operations standpoint to start by injecting gas into WAG injector
M-02 prior to initiating gas lift. AIO 42 was submitted June 3, 2024, and I understand it is in final
review, but may still be a few days away. To initiate gas injection on M-02, Mustang requests
verbal approval to inject under the Brooks Range AIO issued 6/12/2019.
Within a verbal approval, we propose Mustang adhere to the pressure limitations found in the
old Brooks Range AIO until final approval is given for the new AIO:
RULE 4: Injection pressures shall not exceed the maximum injection gradient of 0.67
psi/ft to ensure containment of injected fluids within the defined Affected Area and
injection interval.
This project has come a long way in the last year, and today’s commissioning will be a big
milestone for Mustang and the State leases. We appreciate all the effort AOGCC has put into
working with us to get to this point.
Best regards,
Josh
Josh Tempel
Head of Operations, Mustang Holding LLC
Phone: (907)-891-5930
310 K Street, Ste 309
Anchorage, AK 99501
2
Notice of Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RE: Docket Number: AIO-24-018
By application dated June 3, 2024, Mustang Holding LLC (Mustang), as the operator of the
Southern Miluveach Unit (SMU), requests that the Alaska Oil and Gas Conservation Commission
(AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection
activities in the portion of the Kuparuk River Oil Pool (KROP) located in the SMU.
The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal
either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for
conducting operations that are intended to increase the amount of oil or gas that could be recovered
from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil
through the reservoir to a production well, or modifying the properties of the oil to make it more
mobile. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater
ultimate recovery.
This notice does not contain all the information filed by Mustang. To obtain more information,
contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or
Samantha.Coldiron@alaska.gov.
A public hearing on the matter has been tentatively scheduled for August 27, 2024, at 10:00 a.m.
The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing
room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is
(907) 202-7104 Conference ID: 912 691 777#. Anyone who wishes to participate remotely using
MS Teams video conference should contact Ms. Coldiron at least two business days before the
scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively
scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m.
on July 31, 2024.
If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To
learn if the AOGCC will hold the hearing, call (907) 793-1223 after August 2, 2024.
In addition, written comments regarding this application may be submitted to the AOGCC, at 333
west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be
received no later than 4:30 p.m. on August 22, 2024, except that, if a hearing is held, comments
must be received no later than the conclusion of the August 27, 2024, hearing.
If, because of a disability, special accommodations may be needed to comment or attend the
hearing, contact Samantha Coldiron, at (907) 793-1223, no later than August 20, 2024.
Jessie L. Chmielowski
Commissioner
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2024.07.12 13:40:33
-08'00'
From:Coldiron, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] Public Hearing Notices
Date:Friday, July 12, 2024 2:42:06 PM
Attachments:CO-24-010 public hearing notice expansion of S-BGP in BRU.pdf
CO-24-009 and AIO-24-019 public hearing notice establishing pool rules and an AIO for the COP in KRU.pdf
AIO-24-018 public hearing notice establishing an AIO for the KROP in SMU.pdf
Docket Number: AIO-24-018
By application dated June 3, 2024, Mustang Holding LLC (Mustang), as the operator of the
Southern Miluveach Unit (SMU), requests that the Alaska Oil and Gas Conservation
Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil
recovery (EOR) injection activities in the portion of the Kuparuk River Oil Pool (KROP)
located in the SMU.
Docket Numbers: CO-24-009 and AIO-24-019
By application dated June 20, 2024, ConocoPhillips Alaska, Inc. (CPAI), as the operator of
the Kuparuk River Unit (KRU), requests that the Alaska Oil and Gas Conservation
Commission (AOGCC) approve Pool Rules establish rules for the development of the
Coyote Oil Pool (COP) in the KRU and an Area Injection Order (AIO) to allow enhanced oil
recovery (EOR) injection activities in the COP.
Docket Number: CO-24-010
By applications dated June 27, 2024, Hilcorp Alaska, LLC (Hilcorp), as the operator of the
Beluga River Unit (BRU), requests that the Alaska Oil and Gas Conservation Commission
(AOGCC) expand the vertical extent of the Sterling-Beluga Gas Pool (S-BGP), as currently
defined by Rule 2 of Conservation Order No. 802 (CO 802) in the BRU.
Samantha Coldiron
AOGCC Special Assistant
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
(907) 793-1223
__________________________________
List Name: AOGCC_Public_Notices@list.state.ak.us
You subscribed as: samantha.coldiron@alaska.gov
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v
Lisi Misa being first duly sworn on oath deposes
and says that she is a representative of the An-
chorage Daily News, a daily newspaper. That
said newspaper has been approved by the Third
Judicial Court, Anchorage, Alaska, and it now
and has been published in the English language
continually as a daily newspaper in Anchorage,
Alaska, and it is now and during all said time
was printed in an office maintained at the afore-
said place of publication of said newspaper.
That the annexed is a copy of an advertisement
as it was published in regular issues (and not in
supplemental form) of said newspaper on
AFFIDAVIT OF PUBLICATION
______________________________________
Notary Public in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
______________________________________
07/17/2024
and that such newspaper was regularly distrib-
uted to its subscribers during all of said period.
That the full amount of the fee charged for the
foregoing publication is not in excess of the rate
charged private individuals.
Signed________________________________
Subscribed and sworn to before me
Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501
Order #: W0047006 Cost: $335.69
Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION
RE: Docket Numbers: AIO-24-018
By application dated June 3, 2024, Mustang Holding LLC (Mustang), as the operator of the Southern Miluveach Unit (SMU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR)
injection activities in the portion of the Kuparuk River Oil Pool (KROP)
located in the SMU.
The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the
reservoir to a production well, or modifying the properties of the oil
to make it more mobile. This is consistent with the portion of the
AOGCC’s mission that seeks to promote greater ultimate recovery.
This notice does not contain all the information filed by Mustang. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska. gov.
A public hearing on the matter has been tentatively scheduled for
August 27, 2024, at 10:00 a.m. The hearing, which may be changed
to full virtual, if necessary, will be held in the AOGCC hearing room
located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 912 691 777#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held,
a written request must be filed with the AOGCC no later than 4:30
p.m. on July 31, 2024.
If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after August 2, 2024.
In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be
received no later than 4:30 p.m. on August 22, 2024, except that,
if a hearing is held, comments must be received no later than the
conclusion of the August 27, 2024, hearing.
If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than August 20, 2024.
Jessie L. Chmielowski
Commissioner
Pub: July 17, 2024
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
______________________________________2024-07-19
2028-07-14
Document Ref: DT9YN-EWAGQ-ZQCBO-S2GHR Page 8 of 23
1
pg. 1
June 3, 2024
Jessie Chmielowski, Chair
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave #100
Anchorage, Alaska, 99501-3539
RE: Application for Area Injection Order for the Kuparuk Oil Pool
Southern Miluveach Unit, North Slope, Alaska
Dear Commissioner Chmielowski:
In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders),
Mustang Holding LLC (“MHLLC”)as operator of the Southern Miluveach Unit ("SMU") and on behalf of the
Working Interest Owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission")
approve MHLLC's application for an Area Injection Order ("AIO") for the Kuparuk Oil Pool, as defined by the
Commission and within the SMU as defined in the SMU Agreement by and between the Alaska Department of
Natural Resources. First injection into the Kuparuk Oil Pool in the Southern Miluveach Unit is expected to occur
as early as the 4th quarter of 2024.
MHLLC requests that the hearing date for this application be scheduled as soon as possible after the 30-day
notice period has concluded. A limited number of maps have been marked confidential to retain proprietary
reservoir and subsurface interpreted information.
Please contact Harry Bockmeulen (907-865-5808) if you have questions or require additional information.
Best Regards,
Gordon Pospisil PE
President & CEO
Mustang Holding LLC
By Samantha Coldiron at 4:54 pm, Jun 03, 2024
pg. 2
Mustang Holding LLC
Application for Area Injection Order in the Kuparuk Oil Pool
Southern Miluveach Unit
May 31, 2024
Section A- Introduction
Section B- Plot of Project Area 20 AAC 25.402(c)(1)
Section C- Operator & Surface Owners 20 AAC 25.402(c)(2)
Section D- Affidavit 20 AAC 25.402(c)(3)
Section E- Description of Proposed Operation 20 AAC 25.402(c)(4)
Section F- Pool Description 20 AAC 25.402(c)(5)
Section G- Formation Geology 20 AAC 25.402(c)(6)
Section H- Logs of Injection Wells 20 AAC 25.402(c)(7)
Section I- Mechanical Integrity of Injection Wells 20 AAC 25.402(c)(8)
Section J- Injection Fluids 20 AAC 25.402(c)(9)
Section K- Injection Pressures 20 AAC 25.402(c)(10)
Section L- Fracture Information 20 AAC 25.402(c)(11)
Section M- Formation Water Quality 20 AAC 25.402(c)(12)
Section N- Aquifer Exemption 20 AAC 25.402(c)(13)
Section O- Hydrocarbon Recovery 20 AAC 25.402(c)(14)
Section P- Confinement in Offset Wells 20 AAC 25.402(c)(15)
Section Q- Proposed Area Injection Order Rules 20 AAC 25.402(c)(16)
pg. 3
List of Figures/Exhibits
B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells
D-1: Affidavit
F-1: Outline of AIO and Pool Area highlighting leases outside of the SMU
F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower
confining intervals
G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest
G-2: Kuparuk “C” Reservoir Isochore
G-3: Kuparuk “A4” Reservoir Isochore
G-4: Kuparuk “A3” Reservoir Isochore
G-5: West to East Well Cross Section across the AIO Area
G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk “C” Structure Grid
I-1: Generic Kuparuk Injector Well Design
J-1: Kuparuk Seawater Treatment Plant Water Composition
J-2: Kuparuk Gas Injectant Composition
J-3: Kuparuk Pool Produced Water Composition
K-1: Southern Miluveach Unit, Kuparuk Oil Pool Injection Pressure Summary
L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis
L-2: Model of single point Injection into the Kuparuk “C”
L-3: Injection pressure modeled at 3000 BOPD
L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD
L-5: Injection pressure modeled at 6000 BOPD
L-6: Water Injection Without Propped Fracture At 6,000 BPD
M-1: SMU Kuparuk Pool Water Sample Analysis from North Tarn 1A Well Test
M-2: SMU Kuparuk Pool Gas Sample Analysis from North Tarn 1A Well Test
M-3: SMU Kuparuk Pool Crude Oil Sample Analysis from North Tarn 1A Well Test
O-1: Map of Proposed SMU Kuparuk Development Wells
pg. 4
Section A – Introduction
Document Scope
This document is an application for an Area Injection Order ("AIO") submitted to the Alaska Oil and Gas Conservation
Commission ("Commission") in accordance with 20 AAC 25.460 (Area Injection Orders). The purpose of this
document is to gain authorization from the Commission to inject fluids for pressure maintenance and enhanced
recovery of hydrocarbons in the Southern Miluveach Unit, Kuparuk Oil Pool pursuant to 20 ACC 25.402.
Mustang Holding LLC ("MHLLC"), in its capacity as Operator of the Southern Miluveach Unit (SMU), submits this
document to the Commission. This application has been prepared in accordance with 20 ACC 25.402 (Enhanced
Recovery Operations) and 20 ACC 25.460 (Area Injection Orders).
MHLLC is operating the SMU Kuparuk Reservoir under the Current Kuparuk Pool Rules that govern the
development of the Kuparuk Pool.
Introduction
The Kuparuk Oil Pool within the SMU is a continuation of the deposit of Kuparuk “C” and Kuparuk “A” Sands adjacent
to the southwest portion of the Kuparuk River Unit. It is comprised of sandstones, siltstones, and shales at depths
between -5800 ft. true vertical depth sub-sea ("TVDSS") and -6400 ft. TVDSS within the SMU.
Development of the Kuparuk Oil Pool in the SMU will be completed in multiple phases to mitigate risk and improve
recovery. The reservoir targets will be accessed from the SMU “Mustang” drill site. Current plans are to develop
the field with up to 11 horizontal or vertical producers and up to 10 horizontal or vertical injectors. Some of the
producers and injectors may be hydraulically fractured to enhance production and ultimate recovery. For Phase I,
MHLLC will reinstall production facilities, re-enter existing wells, reconnect the Mustang Pipeline, and return the field
to production from up to four production and injection wells by year end 2024. Mustang full field development is
underway with production ramping up in 4Q 2024 through a series of project phases. In Phase I, a 6,000 bopd Early
Production Facility (EPF) will be installed to process oil produced from the initial wells completed in the central and
SE corner of the Unit. The EPF will have the capability to produce sales quality crude oil along with gas and produced
water handling. Gas will be separated from the oil and utilized for power generation and process heat with any
excess injected into the reservoir. Produced water will initially be trucked to an off-site disposal facility. In Phase II,
additional wells will be drilled to keep field production in the targeted range of 4 mbopd and expand waterflood
operations. During Phase II, the EPF will be expanded to include a Produced Water Injection pump system to inject
water into designated wells and the existing seawater line will be connected to the Colville Seawater pipeline to
provide supplemental waterflood volumes. Additional wells will be drilled in subsequent phases (to be permitted at
a later date) with the ultimate well count as high as 21 wells, dependent on earlier phase results. The Early
Production Facility will be debottlenecked or replaced by additional facilities modules as warranted by longer term
production results, reservoir performance, and potential third party or multi-horizon Mustang field development.
Produced oil will be delivered to the market through a tie-in at the common carrier Alpine Pipeline which crosses
through the SMU and connects to the Trans-Alaska Pipeline System.
pg. 5
Section B – Plot of Project Area
20 AAC 25.402(c)(1)
20 AAC 25.402(c)(1) -An application for injection must include a plat showing the location of each proposed injection
well, abandoned or other unused well, production well, dry hole, and other well within one-quarter mile of each
proposed injection well.
Figure B-1 shows all existing injection wells, production wells, abandoned wells, dry holes and any other wells
within the requested Southern Miluveach Unit, Kuparuk Oil Pool as of March, 2024. Specific approvals for any
new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC
25.005, 25.280, and 25.507, or any applicable successor regulation.
pg. 6
Section C – Operator & Surface Owners
20 AAC 25.402(c)(2)
20 AAC 25.402(c)(2)- An application for injection must include a list of all operators and surface owners within a
one-quarter mile radius of each proposed injection well.
MHLLC is the designated operator of the SMU, which includes the Mustang drill site from which the Kuparuk
development wells will be drilled. The surface owners and operators within one-quarter mile radius of the
proposed injection area are listed below.
Surface Owners Operators
State of Alaska ConocoPhillips
Department of Natural Resources 700 G Street
Division of Oil and Gas Anchorage, Alaska 99501
Attention: James Beckham, Director
550 West Seventh Avenue, Suite 1100 Oil Search (Alaska), LLC a
subsidiary of Santos Limited
Anchorage, AK 99501-355 900 E. Benson Blvd. Anchorage,
Alaska 99508
Repsol
3800 Centerpoint Dr.
Anchorage, Alaska, 99503
pg. 7
Section D – AFFIDAVIT
20 AAC 25.402(c)(3)
20 AAC 25.402(c)(3) -An application for injection must include an affidavit showing that the operators and surface
owners within a one-quarter mile radius have been provided a copy of the application for injection.
Exhibit D-1 is an affidavit showing that the operators and surface owners within a one-quarter mile radius of the
proposed injection area have been provided a copy of this application.
pg. 8
Section E- Description of Proposed Operation
20 AAC 25.402(c)(4)
20 AAC 25.402(c)(4) -An application for injection must include a full description of the particular operation for which
approval is requested.
The Kuparuk Oil Pool within the Southern Miluveach Unit will be developed from the existing SMU Mustang drill site
and produced through the SMU processing facilities. Current plans call for 11 horizontal or vertical producers and
up to 10 horizontal or vertical injection wells. Depending on expected reservoir quality, some of the producers or
injectors may be hydraulically fractured to stimulate production and enhance ultimate recovery. As needed,
additional wells may be drilled to optimize reservoir performance.
Most of the development wells will trend North to South parallel to the direction of the major fault patterns that cut
through the reservoir. The length of the horizontal sections of the wells are planned to range in length up to 6000’
within the reservoir. Some of the wells will produce from both the Kuparuk “C” and the Kuparuk “A” reservoirs. In
these wells it is expected that hydraulic fracture stimulation may be needed to enhance productivity and improve
vertical injection sweep. The wells may be arranged end-to-end to form alternate rows of producers and injectors
in a line-drive flood pattern. Initial studies, which include a computer-generated reservoir simulation study, suggest
a nominal 1500’-2000’ inter-well spacing will fit within and between the major faults which cut through the Kuparuk
reservoir and will most likely cause some interference to a conformable waterflood. Based on well performance,
some infill drilling may be needed to optimize reservoir performance and maximize recovery.
To evaluate the performance of the Kuparuk Reservoir, a 3-D model, based on the available 3D seismic surveys
and well data, was constructed covering the entire development area to assess reservoir performance using a
waterflood for enhanced recovery. Additionally, waterflooding may be followed with either lean gas or miscible gas
injection to further improve recovery. Production and injection will be managed to maintain reservoir pressure near
the original measured pressure. Injection will most likely consist of either produced water or seawater. The seawater
injection source water will come from the nearby CPAI operated Alpine seawater pipeline.
Gas will be sourced from the SMU processing facilities. Although the future availability of gas for injection purposes
cannot be fully ascertained, some form of Immiscible Water Alternating Gas (“IWAG”) flood, Miscible Water
Alternating Gas (“MWAG”) or rich gas injection may be implemented on one or more injection patterns to enhance
recovery from the reservoir. An economic evaluation of IWAG and MWAG processes will determine the feasibility
of utilizing these enhanced oil recovery methods within the SMU.
pg. 9
Section F- Pool Description
20 AAC 25.402(c)(5)
20 AAC 25.402(c)(5) -An application for injection must include the names, descriptions, and depths of the pools to
be affected.
Location
As shown on Figure F-1, the affected area proposed for the Southern Miluveach Unit, Kuparuk Oil Pool Area
Injection Order is the entire Kuparuk Oil Pool, as proposed, which is within the following land:
Location
As shown on Figure F-1, the affected area proposed for the SMU Kuparuk Oil Pool Injection Order is the entire
SMU Kuparuk Oil Pool including the following land:
Umiat Meridian
T10N, R7E Sections 1, 2, 3, 4, 9, 10, 11, 12 all
T11N, R7E Sections 24, 25, 26, 34, 35, 36 all
Pool Definition
Injection of fluids for enhanced recovery is proposed for the correlative interval shown in Figure F-2, the North
Tarn 1A well, known as the Southern Miluveach Unit (SMU), Kuparuk Oil Pool. Within the requested areal extent,
the SMU Kuparuk Pool is defined as the accumulation of hydrocarbons common to and correlating with the
interval between the depth of -6006 ft. TVDss and -6090 ft. TVDss as defined in the North Tarn 1A Well. Within
the proposed Area Injection Order, the primary Kuparuk reservoirs are the Kuparuk “C” and the Kuparuk “A”
intervals.
Lower Confining Interval
Below the Kuparuk Oil Pool is the Miluveach Shale. The Miluveach is a thick regional shale interval throughout the
proposed area of development.
The Kuparuk Pool in the area of the SMU
The primary reservoirs in the proposed Area Injection Order consist of the shallow marine sandstones of the
Kuparuk “A” reservoir and the unconformably overlying transgressive sandstones of the Kuparuk “C” reservoir.
The underlying “A” sand is generally a lower permeability reservoir than found in the Kuparuk “C” sand.
Upper Confining Interval
The Kuparuk “C” reservoir is overlain by the Kalubik Shale interval. The Kalubik Shale is a regionally extensive
and thick shale unit which provides a top seal for the reservoir and provides the upper confining layer to waterflood.
pg. 10
Section G- Formation Geology
20 AAC 25.402(c)(6)
20 AAC 26.402(c)(6) -An application for injection must include the name, description, depth, and thickness of the
formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining
zone, including lithologic descriptions and geologic names.
Stratigraphy
Figure G1 shows the depositional model for the Kuparuk Formation, which consists of the underlying Kuparuk “A”
shallow marine sands which are estimated to be thinning westward and truncated in the Western portion of the SMU.
The Kuparuk “A” sand is overlain by the Kuparuk “C” which is a transgressive sand deposited on the regional Lower
Cretaceous Unconformity.
The Kuparuk “C” and underlying Kuparuk “A” members of the Cretaceous age Kuparuk formation consist of very fine
to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the
two members ranges from 0 to over 80 feet. Figure G-2 shows the expected isochore of the Kuparuk “C”, which is
the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data
and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk “A” reservoir, ranging from 0 to as
much as 80 feet thick. The Kuparuk A” reservoir thins to the west as it is truncated by the Lower Cretaceous
Unconformity.
Sedimentology
The Kuparuk “C” sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite,
and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones).
Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk “C” averaging 70 mD in
the Mustang area.
The Kuparuk “A” sandstones are very fine to fined grained sandstone interbedded with siltstone and mudstones.
Porosity averages 22%, but the permeability is lower than the Kuparuk “C” member ranging from less than 10 mD to
100mD, averaging 30 mD.
Structure and Trap
The Kuparuk Pool within the SMU ranges in depth from -5800 to -6400’ TVDSS. Oil is trapped within the regional
structural trap formed by the Colville Anticline. There is no oil-water contact in the area of the proposed Area Injection
Order. The Kuparuk reservoirs in the SMU are well above the known oil-water contact of the Kuparuk Oil Pool, which
Range in depth from 6530’ TVDss to 6650’ TVDss in the KRU and are deeper than this to the Northeast in the Milne
Point Unit.
Defining Net Pay
Net pay is generally defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk “C” can
be as low as 20%, while water saturations in the Kuparuk “A” are as high as 40%. Net Pay cutoffs of about 15%
porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with
petrophysical evaluations in offset producing wells which suggest these cutoffs are good indicators of net pay in the
Kuparuk “C” sand.
pg. 11
Section H- Logs of Injection Wells
20 AAC 25.402(c)(7)
20 AAC 25.402(c)(7) -An application for injection must Include the logs of the injection wells if not already on
file with the commission.
To date, two wells within the SMU have been drilled and completed which may ultimately be utilized for injection.
The well logs and well histories for these wells, North Tarn #1A and SMU M-02, have been submitted and are on
file with the AOGCC.
pg. 12
Section I - Logs of Injection Wells
20 AAC 25.402(c)(8)
20 AAC 25.402(c)(B) -An application for injection must include a description of the proposed method for
demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no
fluids will move behind casing beyond the approved injection zone, and a description of (A) the casing of the injection
wells if the wells are existing; or (B) the proposed casing program, if the injection wells are new.
The well design for the SMU Kuparuk Oil Pool well (Figure1-1) are similar to other Kuparuk Oil Pool wells drilled
within the adjacent Kuparuk River Unit with surface casing to be set below the West Sak Interval and cemented to
surface. Within the planned development area, the base of permafrost is interpreted to be approximately 1250’
TVDss. Intermediate casing strings will be set and cemented to isolate problematic shales zones and to optimize
drilling through these zones. Any significant hydrocarbon bearing zones found in the borehole above the Kuparuk
Reservoir will be isolated in accordance with Commission regulations. Top of cement will extend a minimum of 500
feet measured depth above the known hydrocarbon bearing formations in accordance with 20 AAC 25.030(d)(5).
The SMU Kuparuk Oil Pool will likely be developed using the following completion methods. The reservoir interval
will be completed with cemented and perforated liners or a solid liner including pre-perforated pup joints and/or sliding
sleeves. This completion will be utilized where hydraulic fracturing is implemented to enhance well production or
injection. Alternatively, completions may utilize uncemented slotted liners where fracture stimulation is not
implemented. Tubing sizes will be determined to optimize expected production and injection rates.
In lieu of the packer depth requirement under 20 AAC 25.412(b) specifying packer depth within 200 ft. measured
depth from above the top of the perforations, MHLLC request the packer/isolation equipment depth may be located
above 200 ft. measured depth from above the top of the perforations/open interval, but shall not be located above
the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300’
measured depth above the planned packer depth. Given some of the Kuparuk Oil Pool injectors may be planned as
horizontal wells, stimulation optimization efforts and well work feasibility may be impeded if the packer/isolation
equipment depth is required to be within 200 ft. measured depth from above the top of the perforations/open interval.
The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.412(c).
Drilling and completion operation will be performed in accordance with 20 ACC 25. In accordance with 20 AAC
25.412(d), cement quality logs, or other data approved by the Commission, will be provided for all injection wells to
demonstrate isolation of the injected fluids to the approved interval.
All SMU Kuparuk Oil Pool injection wells will:
x Be cased and cemented above the reservoir interval to prevent leakage and contamination into oil, gas, or
freshwater sources.
x Be equipped with tubing and a packer or with other equipment that isolates pressure to the injection interval,
unless the Commission approves the use of alternate means to ensure that injection of fluid is limited to the
injection zone.
x Be pressure-tested to demonstrate the mechanical integrity of the tubing and packer (or with other equipment
that isolates pressure to the injection interval) and of the casing immediately surrounding the injection tubing
string.
x Have a cement quality log or other well data approved by the Commission to demonstrate isolation of the
injected fluids to the approved interval.
pg. 13
Section J - Logs of Injection Wells
20 AAC 25.402(c)(9)
20 AAC 25.402(c)(9) ·An application for injection must include a statement of the type of fluid to be injected, the
fluid's composition, the fluid's source, the estimated maximum amounts to be Injected daily, and the fluid's
compatibility with the injection zone.
Waterflooding will be implemented as the initial enhanced recovery mechanism for the proposed SMU Kuparuk Oil
Pool with the use of both produced water and treated seawater. Seawater will be delivered through a pipeline spur
off the nearby Alpine water pipeline. Additionally, waterflooding may be followed later with either lean gas or
miscible gas injection to further improve recovery.
Other fluids may also be injected for reservoir stimulation, reservoir performance, evaluation, freeze protection, or
chemical inhibition; however, these fluids are not planned for continuous injection as a means for enhanced recovery.
The volumes of these other fluids are expected to be less than 0.1% of the total volume injected and are not expected
to hinder the recovery efficiency of the proposed SMU Kuparuk Oil Pool.
Types and sources of fluids requested for injection are (compositions included for fluids that may be dedicated
injection fluids):
x Source water from the Kuparuk seawater treatment plant (composition listed in Figure J-1)
x Produced water from all present and yet-to-be defined oil pools within the SMU Kuparuk River Field,
including without limitation the Kuparuk Oil Pool.
x Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas
liquids (composition listed in Figure J-3)
x Lean gas (composition listed in Figure J-3)
x Fluids used during hydraulic stimulation
x Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.)
x Fluids used to improve near wellbore injectivity (via use of acid or similar treatment)
x Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.)
x Fluids associated with freeze protection (diesel, glycol, methanol, etc.)
x Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Fluid Compatibility
Dispersed clay in the sandstone layers is not prone to swelling when in contact with typical injection water
salinities expected to be used in the SMU Kuparuk Oil Pool.
Analyses of formation water samples collected from the Kuparuk producers within the KRU indicate the
potential for moderate scaling during production and when the formation water mixes with seawater. The
specific scale risks are listed below.
x Produced Water Injection
o BaSO4 and CaCO3
o Scale risks are minimized with the injection water going deeper into formation
x Seawater Injection
o BaSO4 risk is high from wellbore throughout the mixing zone
o CaCO3 risk is minor in reservoir beyond the near wellbore area
Scaling mitigation measures include placement of aqueous and solid phase scale inhibitors in fracture treatments,
conventional squeeze treatments, and chemical injection in the wells and at the surface. The analyses of the
formation water samples listed above indicate that the scale risk is expected to be controlled utilizing these
measures. Field injectivity data from analogous reservoirs (The Kuparuk River Field, Kuparuk Pool and
Nanuq/Kuparuk in the Colville River Field) suggest limited permeability degradation will occur with properly treated
injection fluids.
pg. 14
No compatibility issues between injection gas and Kuparuk Reservoir fluids have been identified. Fluids used for
hydraulic stimulation are planned to include a mixture of water (freshwater, seawater, or produced water), gelling
agents added to make the fluid thicker and slicker, and larger grain ceramic sand to improve and sustain conductivity
within the fracture through the life of the well. Hydraulic stimulation operations will be performed in accordance with
20 AAC 25.283. Hydraulic stimulation formulations may be adjusted as new technologies emerge and as the
reservoir characterization is further defined.
Injection Volumes
Estimated maximum injection rate for each injector is estimated at 6,000 barrels of water per day and 6 million
standard cubic feet of gas per day; however, injection rates will be confined by injection pressures as to not exceed
the overburden pressure gradient and cause fractures to penetrate through the confinement layer.
pg. 15
Section K – Injection Pressures
20 AAC 25.402(c)(10)
20 AAC 25.402(c)(10)- An application for injection must include the estimated average and maximum injection
pressure.
MHLLC proposes to develop the SMU Kuparuk Oil Pool using a waterflood and IWAG flood, with the option to
convert to an MWAG or rich gas flood to enhance recovery from the reservoir. Injection rates will be managed to
replace production voidage and will be controlled by surface chokes. The upper and lower confining intervals, the
Kalubik and Miluveach shales, respectively, have fracture gradients based on the offset well data of 0.80 psi/ft or
higher. To ensure containment of injected fluids within the SMU Kuparuk Oil Pool, water injection pressures are
designed for a maximum of 4700 psi bottom-hole pressure or (and will not exceed the confining layer fracture
gradient. Average water injection pressure gradient is expected to be 0.67. Figure K-1 lists the estimated wellhead
pressures and bottom-hole pressures.
pg. 16
Section L – Fracture Information
20 AAC 25.402(c)(11)
20 AAC 25.402(c)(11) -An application for injection must include evidence to support a commission finding of
that each proposed injection well will not initiate or propagate fractures through the confining zones that might
enable the injection fluid or formation fluid to enter freshwater strata.
An internal containment assurance analysis, obtained by MHLLC, indicates that the estimated maximum injection
pressures for the Kuparuk wells (listed in Section K) in IWAG or MWAG service will not initiate or propagate
fractures through the confining strata and therefore, will not allow injection or formation fluid to enter any freshwater
strata.
The internal containment assurance analysis involved the use of a fracture model built based on the nearby KRU
2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history
matched data from the North Tarn #1 fracture stimulation results. The simulations of the hydraulic fracturing stages
and long-term water injection cases were run and indicate that fracture growth is contained within the Kuparuk Oil
Pool without risk of breaking through overburden or under-burden containment zones.
The frac modelling software used was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due
to its reliability and common use by North Slope operators as well as in the fracturing industry. GOHFER is a
planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is
commercially available throughout the industry for performing hydraulic fracture simulation work.
Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted
using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and
extended within the Kuparuk A and C formations if water injection is conducted at surface pressures above 1700-
2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval
unless the surface injection pressure rises to more than 2700-3000 psi.
Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate
and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all
created fractures contained within the sands by the in-situ stress contrast between the sands and bounding
silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture
extension pressure indicated by the model is required before excessive fracture height growth develops. The
calibrated stress and fracture model predict height containment within each reservoir interval. It is not able to
accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends
primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected
by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation
sand-face caused by injected suspended solids and contaminants.
To study how fractures are initiated during injection in the Kuparuk Reservoir and whether they can be effectively
contained within the target interval, the following cases were simulated for a horizontal well penetrating and
injecting into a single point within the Kuparuk “C”. Single point injection models the worst-case scenario for the
induced pressure on the confining layers. In practice, injecting along the length of the lateral will result in less
fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone.
Increasing the number of injection points in the well will decrease the possibility of fracturing out of zone.
1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,)
2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6)
The above simulations indicate that injection induced fractures will be contained within the Kuparuk Reservoir; no
breakthrough of the overburden or under-burden containment zones will occur.
pg. 17
Section M – Formation Water Quality
20 AAC 25.402(c)(12)
20 AAC 25.402(c)(12)- An application for injection must include a standard laboratory water analysis, or the results
of another method acceptable to the commission, to determine the quality of the water within the formation into
which fluid injection is proposed.
Laboratory analysis of the Kuparuk Reservoir water sample collected from the North Tarn #1A well test is above
the 10,000 mg/l cut off for freshwater. Based on the calculation of the weight percent of the chloride ions (chlorine
molecules in the analysis) and sodium ions in the analysis from Kuparuk Lab, the total weight percent would be
1.66 weight percent which translates to 16,600 parts per million. This is consistent with the 15,000 to 20,000 ppm
readings that are measured from the Kuparuk Reservoir.
In fresh water - official salt concentration limits in drinking water US: 1000 ppm.
Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately
16,000 to 20,000 mg/l NaCI. Based on this information, the Kuparuk Reservoir is not a source of drinking water.
Composition of the North Tarn #1A water, gas and crude oil composition is listed in Figures M-1, 2 and 3.
pg. 18
Section N – Aquifer Exemption
20 AAC 25.402(c)(13)
20 AAC 25.402(c)(13)- An application for injection must Include a reference to any applicable freshwater exemption
issued under 20 AAC 25.440.
Minimum values of formation water salinity in the Southern Miluveach Unit Area, west of the Kuparuk
River Unit and continuing into the NPRA through the Colville River Unit determined using standard open
hole wellbore geophysical methods which have been calibrated from drill stem and production testing,
range from over 3,000 to 18,000 milligrams per liter ("mg/l") total dissolved solids ("TDS"). This evaluation
was conducted by qualified petrophysicists contracted from Schlumberger Oil Field Services by Brooks
Range Petroleum.
Permafrost extends from the surface to approximately 1300’ TVDss in the SMU, although partially frozen
zones locally exist to a depth of 1800’ TVDss. As such, no fresh water aquifers exist within the planned
development from the surface to this depth. Any potential aquifer sands that could be located below this
interval would be considered uneconomic sources of drinking water in this area. No significant permeable
zones have been identified in any nearby wells that penetrate the stratigraphy below permafrost and
above the first potential hydrocarbon bearing reservoir intervals.
The first potential hydrocarbon zone in the SMU could be found at a depth of about 4000’ TVDss, which
is stratigraphically equivalent to the shallowest producing horizon in the nearby Tarn oil pool. This zone,
stratigraphically equivalent to the Tarn Pool has not yet been proven to be a productive oil pool within the
SMU. A petrophysical evaluation of the zone from the base of permafrost to 4000’ TVDss was conducted
on the nearby West Sak 25590 15 well which has a complete logging suite suitable for estimating the
Total Dissolved Solids content (TDS) and salinity. From this analysis, the TDS/Salinity content of the
fluids in these sands is calculated to be more than 3000 ppm. Hence, by definition, there are no drinking
water aquifers identified in the vicinity by this analysis.
The EPA has adopted an aquifer exemption for the "portions of aquifers on the North Slope described by
a mile area beyond and lying directly below the Kuparuk River Unit oil and gas field." 40
CFR147.102(b)(3). The Commission has adopted that exemption by reference 20 AAC 25.440(c). All of
the proposed SMU Kuparuk Oil Pool and the area to which the proposed AIO applies is within the
ORIGINAL Kuparuk River Unit as approved in 1984 when the Environmental Protection Agency adopted
the original aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer
exemption. As such, the original aquifer exemption still applies to the proposed SMU AIO.
An aquifer exception should be granted for the SMU based on these factors and analysis. No fresh water
aquifers are found within the development area of the SMU.
pg. 19
Section O – Hydrocarbon Recovery
20 AAC 25.402(c)(14)
20 AAC 25.402(c)(14) -An application for injection must include the expected incremental increase in ultimate
hydrocarbon recovery.
The quality of the crude requires adoption of a secondary recovery mechanism to obtain an economic
production profile. Water injection has been implemented as the main improved recovery process for the
Kuparuk River Field and will also be planned for the SMU Kuparuk Oil Pool. This waterflood technique has
been widely used on North Slope with consistent success.
The SMU Kuparuk Oil Pool will employ a horizontal well line drive pattern IWAG flood, with the option to convert
to an MWAG or rich gas flood, to enhance recovery from the reservoir. Some wells will likely be hydraulically
fracture stimulated to enhance productivity and improve vertical injection sweep.
Most wells will trend north to south, sub parallel the maximum principal stress direction to improve waterflood
performance, and range in length up to 6,000 feet within the reservoir (Figure O-1). Wells will generally be
arranged end-to-end to form alternating rows of producers and injectors in a line-drive flood pattern. After taking
into account structural constraints, a nominal 1,500 ft. inter-well spacing is expected to deliver adequate
secondary response. Initial wells will provide critical performance and injection data for the SMU Kuparuk Pool
which may, in combination with additional geologic and engineering studies, change the number of wells, well
spacing, well design, and well placement for the remaining SMU Kuparuk Pool development.
The primary uncertainties in the development of the SMU Kuparuk Oil Pool are the lateral continuity of the
relatively thin sandstones and the effective displaceable pore volumes. The seismic signature of the SMU
Kuparuk Pool reservoir is consistent with and supports laterally continuous productive sandstones over the
development area with some compartmentalization possible. Hydraulic fracture stimulation will aid in connecting
the more poorly developed sandstone intervals.
Reservoir modeling predictions indicate that primary recovery will be approximately 10 to15% of the original oil-in-
place ("OOIP") and that waterflood recovery will range from 10% to 25% incremental recovery OOIP, yielding a
total recovery with waterflood of up to 35%. Gas injection, whether miscible or immiscible, could yield incremental
recovery in the SMU Kuparuk Oil Pool. Historical IWAG incremental recovery has been in the range of 1-5% of
OOIP, while MWAG incremental recovery has been demonstrated to range from 3-15% of OOIP.
Due to uncertainty in natural gas liquid ("NGL") supply, there is uncertainty in the composition of gas that will be
available for injection in the Kuparuk Interval. Therefore, it is not possible at this time to predict with certainty
whether or not miscibility between the injected gas and the formation oil will is possible.
Resource recovery for water and gas floods is primarily dependent on injection throughput, water and gas
injection conformance, and displacement efficiency.
pg. 20
Section P – Confinement in Offset Wells
20 AAC 25.402(c)(15)
20 AAC 25.402(c)(15)- An application for Injection must include a report on the mechanical condition of each well
that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well.
At the time of this report, no wells have been drilled within a one-quarter mile radius of each other within the SMU.
However, the development may contain additional wells within this offset distance.
Specific approvals for any new injection wells or existing wells to be converted to injection service will be
obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation.
pg. 21
Section Q – Proposed Area Injection Order Rules
20 AAC 25.402(c)(16)
The rules set forth apply to the following area referred to in this order:
Umiat Meridian
T10N, R7E Sections 1,2,3,4,9,10,11,12 all
T11N, R7E Sections 24,25,34,35,36 all
Rule 1. Authorized Injection Strata for Enhanced Recovery
Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced
hydrocarbon recovery within the proposed SMU Kuparuk Oil Pool, which is defined as the accumulation of oil and
gas common to and correlating with the interval within the North Tarn #1 well between the depths of -6006 ft.
TVDSS and -6096 TVDSS respectively).
Rule 2. Well Construction
In lieu of the packer depth requirement under 20 AAC 25.412(b), the packer/isolation equipment depth may be
located above 200 ft. measured depth from above the top of the perforations/open interval; but shall not be
located above the confining zone and shall have outer casing cement volume sufficient to place cement a
minimum of 300' measured depth above the planned packer depth.
Rule 3. Authorized Fluids for Injection for Enhanced Recovery
Fluids authorized for injection are:
a. Source water from the Kuparuk seawater treatment plant
b. Produced water from all present and yet-to-be defined oil pools within the SMU Kuparuk River Pool,
including without limitation the Kuparuk Oil Pool.
c. Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas
liquids
d. Lean gas
e. Fluids used during hydraulic stimulation
f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.)
g. Fluids used to improve near wellbore injectivity (by use of acid or similar treatment)
h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.)
i. Fluids associated with freeze protection (diesel, glycol, methanol, etc.)
j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Rule 4. Authorized Injection Pressure for Enhanced Recovery
Injection pressures will be managed as to not exceed a maximum injection gradient of 0.77 psi/ft.to ensure
containment of injected fluids within the SMU Kuparuk Oil Pool.
Rule 5. Administrative Action
Upon proper application, the Commission may administratively waive the requirements of any rule stated above
or administratively amend the order as long as the change does not promote waste or jeopardize correlative
rights, is based on sound engineering or geoscience principles, and will not result in an increased risk of fluid
movement into freshwater.
pg. 22
List of Figures/Exhibits
B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells
D-1: Affidavit
F-1: Outline of AIO and Pool Area highlighting leases outside of the SMU
F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower
confining intervals
G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest
G-2: Kuparuk “C” Reservoir Isochore
G-3: Kuparuk “A4” Reservoir Isochore
G-4: Kuparuk “A3” Reservoir Isochore
G-5: West to East Well Cross Section across the AIO Area
G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk “C” Structure Grid
I-1: Generic Kuparuk Injector Well Design
J-1: Kuparuk Seawater Treatment Plant Water Composition
J-2: Kuparuk Gas Injectant Composition
J-3: Kuparuk Pool Produced Water Composition
K-1: Southern Miluveach Unit, Kuparuk Oil Pool Injection Pressure Summary
L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis
L-2: Model of single point Injection into the Kuparuk “C”
L-3: Injection pressure modeled at 3000 BOPD
L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD
L-5: Injection pressure modeled at 6000 BOPD
L-6: Water Injection Without Propped Fracture At 6,000 BPD
M-1: SMU Kuparuk Pool Water Sample Analysis from North Tarn 1A Well Test
M-2: SMU Kuparuk Pool Gas Sample Analysis from North Tarn 1A Well Test
M-3: SMU Kuparuk Pool Crude Oil Sample Analysis from North Tarn 1A Well Test
O-1: Map of Proposed SMU Kuparuk Development Wells
pg. 23
B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells
pg. 24
pg. 25
F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper
and lower confining intervals
Kalubik Shale Upper Confining
Miluveach Shale Lower Confining Layer
pg. 26
G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest
pg. 32
I-1: Generic SMU Kuparuk Pool Injector 4 String Casing Well Design
pg. 33
J-1: Kuparuk Seawater Treatment Plant Water Composition
pg. 34
J-1: Kuparuk Seawater Treatment Plant Water Composition (Continued)
pg. 35
J-2: Kuparuk Gas Injectant Composition
pg. 36
J-3: Kuparuk Pool Produced Water Composition
pg. 37
J-3: Kuparuk Pool Produced Water Composition (Continued)
pg. 38
Figure K-1: SMU Kuparuk Oil Pool Injection Pressure Summary
Injection Type Estimated Wellhead
Pressure (PSIA)
Estimated Bottom-hole
Pressure
Average* Maximum** Average* Maximum**
Water Injection 1400 2100 4000 4700
Gas Injection 3800 4000 4410 4610
*Based on planned operations at a true vertical depth of 6100 feet
** Maximums vary according to actual interval depth
Assumptions:
Datum (TVDss) 6100
Average Injection Gradient 0.67
Maximum Injection Gradient 0.77
Confining Zone Fracture Gradient 0.80
CPF-3 Fluid Gradient (Water) 0.442
Gas Gradient (Produced Gas) 0.10
Calculations:
Bottom Hole Pressure (BHP)=Datum (TVDss)*Injection Gradient (Water or Gas)
Hydrostatic Pressure = Datum (TVDss) * Fluid Gradient
Well Head Pressure (WHP)=BHP-Hydrostatic Pressure
pg. 39
Figure L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis
pg. 40
Figure L-2: Model of single point Injection into the Kuparuk “C”
pg. 41
Figure L-3: Injection pressure modeled at 3000 BOPD
pg. 42
Figure L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD
pg. 43
Figure L-5: Injection pressure modeled at 6000 BOPD
pg. 44
Figure L-6: Water Injection Without Propped Fracture At 6,000 BPD
pg. 45
M-1: Oil/Water Sample Analysis, North Tarn 1A
pg. 46
M-2: Gas Sample Analysis, North Tarn 1A (Continued)
pg. 47
M-3: SMU Kuparuk Pool Crude Oil Sample Analysis, North Tarn 1A
