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HomeMy WebLinkAboutAIO 045AIO 45
Coyote Oil Pool
Kuparuk River Unit
North Slope Borough, Alaska
1. June 20, 2024 CPAI Applications for Coyote Oil Pool, and Area Injection, North
Slope, Alaska
2. July 12, 2024 Notice of public hearing
3. August 20, 2024 Hearing presentation and transcripts
4. August 20, 2024 OSA comments on AIO
5. September 6, 2024 CPAI response to OSA comments
6. September 11, 2024 OSA clarification letter to AOGCC
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage, Alaska 99501
Re: THE APPLICATION OF ConocoPhillips
Alaska, Inc. for an order authorizing
underground injection of fluids for
enhanced oil recovery in the Kuparuk
River Unit, Coyote Oil Pool
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Docket Number: AIO-24-019
Area Injection Order 45
Coyote Oil Pool
Kuparuk River Unit
North Slope Borough, Alaska
November 27, 2024
IT APPEARING THAT:
1. By application received June 20, 2024, ConocoPhillips Alaska, Inc. (CPAI), as operator of
the Kuparuk River Unit (KRU), requested an order authorizing underground injection of
fluids for enhanced oil recovery in the area and strata covered by the proposed Coyote Oil
Pool (COP), which was applied for on the same day.
2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC)
scheduled a public hearing for August 20, 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 to all persons on the
AOGCC’s mailing distribution list. On July 14, 2024, the notice was also published in the
Anchorage Daily News.
3. Oil Search (Alaska), LLC, a subsidiary of Santos Limited (Santos) submitted comments on
the application on August 20, 2024 (Santos August 20 letter).
4. The hearing commenced at 10:00 a.m. on August 20, 2024. Testimony was received from
representatives of CPAI. The record closed at the conclusion of the hearing.
5. CPAI submitted comments regarding Santos’ August 20 letter on September 6, 2024.
Santos submitted additional comments regarding CPAI’s September 6, 2024 comments on
September 13, 2024. Since both letters were submitted after the record closed, they were
not considered in the AOGCC’s decision on CPAI’s application.
FINDINGS:
1. Owners and Landowners: Surface owners in the proposed COP area are Gertrude
Ahsogeak (Deceased), Ahsoogeak Woodrow (Deceased), Horace K. Ahsogeak, Johnny K.
Ahtuangaruak, Beulah E. Williams, Benjamin Tukle (Deceased), and Martha Magdalene
Helmericks and the State of Alaska (SOA), Department of Natural Resources (DNR),
Division of Mining, Land and Water (MLW), which is a “Party-in-Interest” to two of the
properties listed above, and the SOA, DNR, Division of Oil and Gas (DOG). Subsurface
owner of the COP is the State of Alaska. ConocoPhillips Alaska, Inc., ConocoPhillips
Alaska II, Inc., Chevron U.S.A. Inc., and ExxonMobil Alaska Production, Inc. are the
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November 27, 2024
Page 2 of 11
working interest owners of the leased acreage within the proposed Affected Area, as
defined below.
2. Operator: CPAI is operator of all the leased acreage in the proposed Affected Area.
3. Operators of Within ¼-Mile of Proposed Affective Area: The operators within ¼-mile of
the proposed Affected are ConocoPhillips Alaska, Inc. II, Oil Search (Alaska), LLC,
Hilcorp Alaska, LLC1, and Finnex, LLC.
4. Affected Area: CPAI is proposing (see Figure 1 below) the same Affected Area as was
proposed for the COP. The proposed Affected Area encompasses a portion of the KRU and
extends beyond the area the CPAI proposed 2 for the Coyote Participating Area. The
proposed Affected Area is bordered to the north by the Oooguruk Unit, to the south by the
Quokka Unit and lands not currently committed to any unit, and to the east and west by
lands within the KRU.
5. Exploration, Delineation, and Development History: The proposed Affected Area was
penetrated numerous times over the years, dating back to the mid-1960s. The first test of
the proposed COP was conducted in well KRU 3S-24B (PTD 221-078, API No. 50-103-
20456-02-00) in 2021. In 2022-23 a small-scale pilot project—conducted under Enhanced
Recovery Injection Order No. 8—involved a horizontal producer KRU 3S-704 (PTD 222-
142, API No. 50-103-20848-00-00) and a horizontal injector KRU 3S-701A, (PTD 222-
134, API No. 50-103-20847-01-00), and it demonstrated the viability of developing the
COP.
1 At the time the application was submitted Eni US Operating Co. Inc. was the operator of the Oooguruk Unit (OU).
Effective November 1, 2024, Hilcorp Alaska, LLC became owner and operator of the OU.
2 On October 22, 2024, the DOG approved a Coyote PA that was approximately 5.5% smaller than what CPAI
proposed in its application.
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November 27, 2024
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Figure 1. Proposed Coyote Oil Pool Affected Area (Source: ConocoPhillips Alaska, Inc.)
6.Pool Identification: As proposed, the COP is a part of the Brookian Nanushuk Formation
(Nanushuk). The Nanushuk was deposited in a shallow marine to upper slope setting in the
Colville Foreland. The “topset” Nanushuk strata form a series of eastward prograding
deltaic – shoreface – uppermost slope sediments. The equivalent middle – lower slope –
basin floor sediments are grouped into the Torok Formation (Torok). The COP is located
in the easternmost portion of this progradational system. The proposed injection interval is
the same as what CPAI proposed for the COP and is the accumulation of hydrocarbons
common to and correlating with that portion of the Nanushuk shown on the Palm 1
reference log (API Number 50-103-20361-00-00;see Figure 2 below) between 4,270 and
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November 27, 2024
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5,115 feet measured depth (MD), which is equivalent to 4,038 and 4,720 feet true vertical
depth below mean sea level (also termed true vertical feet sub-sea, or TVDSS).
Figure 2. Palm 1 type log (Source: ConocoPhillips Alaska, Inc.)
7. Relationship to other Nanushuk Developments: The Nanushuk Oil Pool in the Pikka Unit,
the Qannik Oil Pool in the Colville River Unit, and the proposed Willow development in
the Bear Tooth Unit are all part of the same Nanushuk progradational sequence that the
COP is in but are located in further west facies that are not in communication with the
COP.
8. Geology:
A. Stratigraphy:
CPAI’s proposed injection interval is part of a generally west to east progradational system
that is elongate in a northeast to southwest direction. The COP was deposited in a delta-
front to distal delta-front environment. Net to gross and grain size generally decrease with
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November 27, 2024
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depth and as such the highest quality reservoir is located in the upper portion of the
formation. The COP is thinly bedded throughout and comprised of very fine-grained
sandstones, siltstones, and mudstones. The COP thins to the west and thickens to the east.
There is a presumed oil water contact at 4,260 feet TVDSS which limits the proposed
development to approximately the upper 200 feet of the proposed pool. Whole cores
collected from the Mitquq 1 ST1 and 3S-701 wells indicate the average porosity is ~24%,
the average permeability to air is ~32 md, and the average water saturation is 52%.
B. Trap and Structure:
The COP is a combined structural-stratigraphic trap that pinches out to the west-northwest
and shales out to the east-southeast and has an average dip of ~1 degree or less. Faulting
within the proposed COP is very limited.
C. Permafrost Base:
The base of permafrost is interpreted to be between approximately 1,500 and 1,700 feet
TVDSS.
D. Upper Confining Interval:
This interval is represented by distal toe of slope (deep marine) claystone with thin
siltstones beds of the Cretaceous Seabee Formation. This interval is more than 350 feet
thick throughout the affected area. Test show that the fracture closing pressure gradient of
the upper confining interval is 0.67 psi/ft.
E. Lower Confining Interval:
This interval is comprised of basin floor mudstones of the Torok, this interval is more than
300 feet thick throughout the proposed affected area. This interval is also the upper
confining interval of the KRU Torok Oil Pool.
9. Reservoir Fluid Contacts: There is a small gas cap in the COP that will be produced out,
interpretation indicates an oil water contact at approximately 4,260 feet TVDSS.
10. Reservoir Fluid Properties: CPAI provided the following reservoir fluid properties at a
datum of 4,150 feet TVDSS from samples collected in the Mitquq 1 ST 1 and 3S-704 wells.
Property Value
Reservoir Pressure (psia) 1,857
Reservoir Temperature (°F) 105
Stock tank oil API Gravity (°) 32
Gas oil ration (SCF/STB) 580
Bubble point pressure, Pb (psi) 1,794
Oil formation factor at Pb (RB/STB) 1.28
Oil viscosity at Pb (cP) 1.0
Gas formation factor at Pb (RB/MSCF)
at saturation pressure
1.3
11. Formation Water Quality: A sample of the produced water from the 3S-24B well shows
the total dissolved solids in the water produced from the COP is over 21,000 mg/l.
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November 27, 2024
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12. Aquifer Exemption: Under 40 CFR 147.102(b)(3) the US Environmental Protection
Agency has adopted an aquifer exemption for the “portions of aquifers on the North Slope
described by a 1/4- mile area beyond and lying directly below the Kuparuk River Unit oil
and gas producing field.
13. In-Place and Recoverable Reserves Volumes:
Coyote Oil Pool Reservoir Volume Range
(MMSTBO)
Original Oil in Place (OOIP) in proposed 3S and 3T
development area
508-646
Original Oil in Place (OOIP) in entire proposed
affected area
636-810
Primary Recovery (~5% OOIP) 25.4-32.3
Primary + Waterflood (20-30% OOIP) 102-194
Primary + Water Alternating Gas Under
evaluation
14. Reservoir Development Drilling Plan: CPAI plans to develop the COP from the KRU 3S
and 3T drill sites with a total of 40 wells, split evenly between producers and injectors. A
horizontal line drive waterflood is planned with a water-alternating-gas development
possibility under evaluation. All wells, producers and injectors, will be fracture stimulated
to enhance productivity and improve vertical injection sweep.
Wells will trend northwest to southeast to generally align with the maximum principal
stress direction to improve waterflood performance. Wells will have horizontal sections of
6,000 to 12,000 feet length and arranged end to end, with between one and three wells in
each line, to form alternating rows of producers and injectors. Current studies suggest 1,300
feet between producers and injectors will be optimal assuming modest secondary response,
this is slightly closer than the 1,500-oot spacing between 3S-701A and 3S-704 which were
used for the pilot project. The 3S-701A has consistently taken 4,000 barrels of water per
day (BWPD) injection and pressure response has been seen in the 3S-704 producer, which
proved that a waterflood could be a viable method of development for the COP.
Pre-production of injection wells may occur.
15. Design of Injection Wells: The packer/isolation equipment may be placed more than 200
feet MD above the top of the perforated interval in injection wells, but may not be placed
above the upper confining interval. There will be a minimum of 100 feet MD of cement
above the packer. Injection well mechanical integrity will be tested in accordance with
applicable regulations and cement quality logs or other data that the AOGCC may approve
will be used to demonstrate isolation of the injected fluids to the approved interval.
16. Reservoir Management: CPAI plans to develop the COP as a waterflood utilizing produced
water from the KRU and/or Beaufort seawater from the Oliktok Point seawater treatment
plant. An immiscible water alternating gas (IWAG) development is currently under
evaluation and if implemented would utilize enriched hydrocarbon gas created by blending
KRU produced gas with indigenous and/or imported natural gas liquids. The target voidage
replacement is 1.0.
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November 27, 2024
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Due to the COP gas cap being produced and the possibility the pool will be developed with
an IWAG injection project CPAI expects the producing gas oil ratio (GOR) to exceed the
limits set by 20 AAC 25.240. CPAI is requesting a waiver of these limitations based on the
COP being developed with an enhanced oil recovery injection project.
17. Proposed Injection Fluids: CPAI seeks authorization to inject produced water and gas from
within the KRU and from the OU, seawater from the Oliktok Point Seawater Treatment
Plant, and gas and NGLs imported from the Greater Prudhoe Area for the purpose of
enhancing oil recovery. The water injection system at KRU 3S and 3T drill sites is currently
configured to inject produced water and intended to remain that way for the long term.
Enhanced Recovery Injection Order No. 8—that authorized the pilot injection project in
the COP—confirmed compatibility with seawater injection.
In addition to the fluids meant to enhance oil recovery, other fluids incidental to operations
may be injected. Thes include fluids used during hydraulic stimulation, tracer survey fluids
to monitor reservoir performance, fluids used to improve near wellbore injectivity (acids,
solvents, etc.), fluids used to seal wellbore intervals which negatively impact recovery
(cement, resin, etc.), fluids associated with freeze protection (diesel, crude, glycol,
methanol, etc.), and standard oil field chemicals (corrosion inhibitor, scale inhibitor, etc.).
18. Scale Deposition: Barium sulfate scale deposition in producing wells due to the mixing of
seawater (source of sulfate) and formation water (source of barium) and as such Coyote
wells will be included in the Greater Kuparuk Area scale inhibition treatment program.
19. Injection Volumes: Water injection rates of up to 15,000 BWPD per injection well could
occur. Gas injection rates are not yet determined as additional work is being done to
evaluate the potential of using gas injection to enhance oil recovery. The target voidage
replacement ratio for the COP is approximately 1:1.
20. Injection Pressures: Injection pressures shall be managed to so as not to exceed the fracture
closing pressure of the upper confining zone of 0.67 psi/ft. Typical injection pressures
would be approximately 0.61 psi/ft.
21. Fracture Modeling: Fracture modeling indicates that fractures will not propagate in the
proposed injection interval if injection pressures are 0.62 psi/ft or less. If fractures do
propagate in the injection interval they will not propagate into the upper confining interval
if the injection pressure is 0.67 psi/ft or less.
22. Waivers: CPAI is requesting a waiver of 20 AAC 25.412(b) which requires injection wells
to be equipped with tubing and a packer with the packer set not more than 200 feet MD
above the upper most perforation in the well. In lieu of this, CPAI is requesting the packer
be allowed to be set more that 200 feet MD above the upper most perforation, but not above
the upper confining interval. There must be at least 100 feet MD of cement above the
packer on the back side of the casing/liner the packer is set in.
23. Santos August 20 letter: Santos addressed several issues in their letter:
A. The Santos operated Quokka Unit (QU) overlies the same broad geologic formation that
CPAI is proposing being covered by the COP pool rules.
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November 27, 2024
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B. Santos supports development of the COP but says they cannot evaluate the potential
impacts from injection in the COP on the QU.
C. Santos objects to the 3S-701/701A and 3S-704 wells still being held confidential because
they were permitted as exploratory wells despite being on production or injection since
March/April 2023.
D. Santos requests that the AOGCC consider a voidage replacement ratio requirement for the
COP but did not provide any details about what it wanted done.
CONCLUSIONS:
1. An area injection order is necessary for the proposed to allow for the injection of fluids for
enhanced recovery purposes in the COP is appropriate and will lead to greater ultimate
recovery from the pool.
2. Reservoir modelling shows that a waterflood will greatly increase ultimate recovery from
the COP over primary depletion alone. The effectiveness of a water-alternating-gas
recovery method is still under evaluation.
3. CPAI plans to maintain the voidage replacement ratio in the COP around 1:1. This rate will
prevent excessive loss of reservoir energy while also avoiding the risk of over pressuring
the reservoir leading to a loss of confinement.
4. Maintaining injection pressures at or below 0.67 psi/ft will prevent fractures from
propagating in the upper confining layer.
5. An aquifer exemption is not necessary for this project because the total dissolve solids of
water in the COP is over 21,000 mg/l, and the KRU has a valid aquifer exemption from the
US EPA under 40 CFR 147.102(b)(3).
6. Waivers to the packer setting depth requirements for injection wells contained in 20 AAC
25.412(b) are common in projects with high angle wells, as are being drilled for the
development of the COP and are appropriate in this situation.
7. Santos has provided no evidence that the proposed injection activities in the COP could
impact its correlative rights.
NOW THEREFORE IT IS ORDERED:
Enhanced Recovery Injection Order No. 8 is hereby rescinded, and its record incorporated by
reference in this order. The underground injection of fluids for pressure maintenance and enhanced
recovery purposes is authorized in the following area, subject to the following rules and 20 AAC
25, to the extent not superseded by these rules:
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November 27, 2024
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Affected Area: Umiat Meridian (See Figure 1)
Township 12 North, Range 7 East Sections 1-3, 10-15, 22-36, & 35-36: all
Sections 9, 16, & 21: E/2
Township 12 North, Range 8 East Sections 4-9, 16-20, & 30: all
Sections 3 & 10: W/2
Sections 15 & 31: NW/4
Sections 21 & 29: N/2, SW/4
Township 13 North, Range 7 East Sections 22-27 & 34-36: all
Sections 28 & 33: E/2
Township 12 North, Range 8 East Sections 19 & 30-32: all
Section 20: SW/4
Section 29: S/2, NW/4
Section 33: W/2
Rule 1 Authorized Injection Strata
The authorized injection interval is defined as the accumulation of oil and gas common to and
correlating with the interval within the Palm No. 1 well (API Number 50-103-20361-00-00)
between the depths of 4,270 and 5,115 feet MD (4,038 and 4,720 feet TVDSS) (see Figure 2,
above.)
Rule 2 Well Construction
In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment
depth for injection wells may be located above 200 feet MD 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 a minimum of 100 feet MD above the planned packer
depth.
Rule 3 Authorized Fluids
Fluids authorized for injection are:
x Source water from the Kuparuk Seawater Treatment Plant
x Produced water from all present and yet-to-be defined oil pools within the Kuparuk
River Field and the Oooguruk Unit (OU)
x Enriched hydrocarbon gas (MI): blend of KRU and OU lean gas with indigenous and/or
imported natural gas liquids
x Lean gas
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.)
AIO 45
November 27, 2024
Page 10 of 11
x Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Rule 4 Authorized Injection Pressure for Enhanced Recovery
Injection pressures will be managed to not exceed the maximum injection gradient of 0.67 psi/ft
to ensure containment of injected fluids within the Coyote Oil Pool.
Rule 5 Monitoring Tubing-Casing Annulus Pressure
Inner annulus, outer annulus, and tubing pressure 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 COP and are located within a quarter-mile radius of a COP 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 72 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 injection 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, operating pressure observation, test,
survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where
the COP is not cemented. If the operator’s investigation supports a conclusion of pressure
communication, leaking, or lack of injection zone isolation, the operator must submit a corrective
action plan to the AOGCC, following the KRU sundry matrix (CO 261B). The operator must shut
in any well for which: (a) continued operation would be unsafe, (b) continued operation would
threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well.
The operator must submit a monthly report of daily tubing and casing annuli pressures and
injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or
(b) lack injection zone isolation.
AIO 45
November 27, 2024
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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 may not be restarted unless approved by the AOGCC.
DONE at Anchorage, Alaska and dated November 27, 2024.
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: 2024.11.27 11:14:39 -09'00'
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.11.27
11:22:50 -09'00'
From:Coldiron, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] Conservation Order 819 and Area Injection Order 45 (CPAI)
Date:Wednesday, November 27, 2024 11:39:05 AM
Attachments:co 819.pdf
aio 45.pdf
THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order for classification of a new
oil pool and to prescribe pool rules for development of the proposed Coyote Oil Pool
within the Kuparuk River Unit
THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order authorizing underground
injection of fluids for enhanced oil recovery in the Kuparuk River Unit, Coyote 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
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6
Oil Search (Alaska), LLC
a subsidiary of Santos Limited
900 E. Benson Blvd
Anchorage, Alaska 99508
PO Box 240927
Anchorage, Alaska 99524
(T) +1 907 375 4642
—santos.com
1/2
September 11, 2024
Samantha Coldiron
Alaska Oil and Gas Conservation Commission
333 W 7th Ave.
Anchorage, AK 99501
Re: Docket Numbers CO-24-009 and AIO-24-019
Dear Ms. Coldiron:
Correspondence transmitted to the Commission on September 6 asserts that the Applicant has
provided information and engaged in coordinating and knowledge sharing activities with Santos.
We wish to provide a more complete picture on these assertions.
Under the terms of a data exchange agreement executed in 2021, we were able to obtain
certain information on the 3S-24B well. The last transmission of data occurred in the third
quarter of 2022. Knowledge sharing sessions occurred following execution of the agreement,
with the final meeting occurring in February of 2022. Since that time, Santos extended
numerous invitations to continue exchanges of data and knowledge sharing. Those invitations
have gone unanswered and there has been no further collaboration or coordination on
development of the Nanushuk reservoir in the vicinity of Quokka and Coyote.
In the time that has passed since the final transmission of data, three additional wells classified
as exploratory have been drilled and tested. The public data from those wells published by the
Commission is not sufficient for a review of potential impacts of the drilling, fracking, and
injection activities proposed adjacent to the Quokka Unit. Two wells nearing completion are
classified as development and the additional detailed data will be helpful but only over time.
The following table identifies the timing and status of all six wells drilled in the Coyote area that
target the Nanushuk formation. Thank you for your consideration.
Sincerely,
Joe Balash
Senior Vice President, External Affairs
JJJoJeBalash
By Samantha Coldiron at 8:11 am, Sep 13, 2024
2/2 Well Class PTD Submitted PTD Approval Spud Complete P&A Status Detailed Data KRU 3S-24B Exploratory 9/21/2021 10/6/2021 11/28/2021 12/7/2021 10/1/2023 P&A Recv'd data through data exchange agreement KRU 3S-701 Exploratory none listed 10/26/2022 none listed 1/13/2023 1/13/2023 P&A (vertical to ST) Recv'd public production data only public release of well data March 2025 KRU 3S-701A Exploratory none listed 10/27/2022 none listed 2/5/2023 N/A WAG Injection Recv'd public production/injection data only. Public release of well data March 2025 KRU 3S-704 Exploratory none listed 12/16/2022 none listed 3/8/2023 N/A Oil Well, Single Completion Recv'd public production data only. Public release of well data April 2025 KRU 3S-718 Development 5/10/2024 5/13/2024 none listed none listed none listed Permit not closed out initial data has been posted to AOGCC website KRU 3S-722 Development 5/20/2024 7/19/2024 none listed none listed none listed Permit not closed out Permits and associated data have been posted to AOGCC website
5
September 6, 2024
Commissioner Jessie Chmielowski and Commissioner Greg Wilson
c/o Samantha Coldiron, Special Assistant
Alaska Oil and Gas Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501
VIA EMAIL samantha.coldiron@alaska.gov
Re: Docket Numbers CO-24-009 and AIO-24-019 (Coyote)
Dear Commissioners Chmielowski and Wilson:
On August 20, 2024, the Commission held a public hearing on ConocoPhillips Alaska, Inc. (CPAI)
applications in the above-referenced dockets (CPAI Applications). Also on August 20, Oil Search
(Alaska), LLC (Santos) submitted comments to the CPAI Applications (Santos Comments). CPAI received
the Santos Comments after the hearing, at which point the Commission had closed the record. CPAI
provides this response to the Santos Comments for the Commission’s general awareness.
The Santos Comments assert that CPAI has not provided Santos with certain confidential exploration
well data (Well Data), assert that CPAI has made no effort to coordinate development activities, and
make two requests of the Commission regarding the Coyote area injection order (AIO) and
conservation order (CO). In relevant part, the Santos Comments state:
Other than supplying to Santos the application for the AIO as required by Commission
regulations, there has been no efforts by CPAI to coordinate with Santos development
activities across the Nanushuk Formation and jointly investigate ways to prevent waste
of resources along property lines.
Given the lack of data sharing and coordination to date, Santos respectfully requests
that its interests be protected by the AOGCC by including the following conditions in
any CO or AIO approval for the Coyote Oil Pool: (1) restrict well locations to one mile
from the KRU boundary; and (2) consider a voidage replacement ratio requirement to
protect correlative rights across unit boundaries and avoid waste. Exceptions to such
an order could be filed at a later date if and when additional data sharing and
coordination has occurred between the unit operators.
Santos’ assertions and requests are addressed in turn below.
Donald Allan
GKA Asset Development Manager
P.O. Box 100360
Anchorage, AK 99510-0360
(907) 263-4560
Donald.Allan@conocophillips.com
By Samantha Coldiron at 3:54 pm, Sep 06, 2024
September 6, 2024
Page 2
CPAI Has Provided Information and Engaged in Coordinating and Knowledge Sharing Activities
with Santos
On June 20, 2024, in accordance with AOGCC regulations, CPAI provided its Coyote AIO Application
to Santos. CPAI did not receive any feedback or questions from Santos on the AIO Application.
On the afternoon of August 19, the day before the AOGCC’s public hearing, Santos sent CPAI an email
requesting the confidential Well Data. CPAI had provided Santos some of the requested Well Data
prior to its August 19 request (and it is not clear why Santos re-requested it). However, in response to
Santos’ request, CPAI engaged in discussions with Santos regarding access to the other Well Data.
Separate from the Well Data, CPAI and Santos have mutually engaged in information exchanges and
technical knowledge sharing arrangements and workshops regarding Nanushuk reservoirs (Pikka /
Narwhal and Quokka / Coyote). We expect this collaboration will continue.
Alaska Law Does Not Support Santos’ Requests for Coyote AIO/CO Conditions
Santos offers no regulatory or statutory support (or any geologic rationale) for its requested Coyote
AIO/CO conditions: a one-mile setback and an unspecified voidage replacement ratio. CPAI opposes
both requested conditions.
On setbacks, the law is clear. 20 AAC 25.055 specifies a 500’ setback, subject to case-by-case waiver
requests for drilling within 500’ of a property line. On voidage replacement, the “normal” ratio is 1:1
(see e.g., Nanushuk AIO 44 Conclusion 3). Both of these principles are ably demonstrated in the
AOGCC’s August 21, 2024 Nanushuk Order (CO 807), which addressed Santos’ Nanushuk development
– a development that is substantially similar to the Coyote development in that it occurs in the Pikka
Unit and borders the Colville River Unit. In relevant part, the Order states:
September 6, 2024
Page 3
The Nanushuk AIO also orders a normal 1:1 voidage replacement ratio (AIO 44 Conclusion 3).
In short, CPAI opposes Santos’ August 20 requests for a one-mile setback and an undefined voidage
replacement ratio. CPAI, in accordance with its Applications, supports Coyote AIO/CO conditions that
are substantially equivalent to those ordered by the AOGCC for Santos’ Nanushuk development: a
normal 20 AAC 25.055 500’ setback, subject to case-by-case waiver requests for drilling within 500’ of
a property line, and a normal voidage replacement ratio of 1:1.
Sincerely,
Donald Allan
cc by email:
Dave Roby, AOGCC Senior Reservoir Engineer (dave.roby@alaska.gov)
Joe Balash, Santos Senior Vice President, External Affairs (Joe.Balash@santos.com)
4
Page 1 of 2
Oil Search (Alaska), LLC a subsidiary of Santos Limited
601 W Fifth Ave
Anchorage, Alaska 99501
PO Box 240927
Anchorage AK 99524-0927
o: +1 907 375-4642 | m: +1 907 830-3956
Telephone: +1 907-375-4600
www.santos.com
August 20, 2024
Samantha Coldiron
Alaska Oil and Gas Conservation Commission
333 W 7th Ave.
Anchorage, AK 99501
Re: Docket Numbers CO-24-009 and AIO-24-019
Dear Ms. Coldiron:
Oil Search (Alaska), LLC, a subsidiary of Santos Limited (Santos), is the operator of the Quokka
Unit (QKU). I write today regarding the application filed by ConocoPhillips (Alaska), Inc. (CPAI) as
operator of the Kuparuk River Unit (KRU) to establish an Area Injection Order (AIO) and
Conservation Order (CO) for the formation of the Coyote Oil Pool.
The QKU overlies the same broad geologic formation identified as the Nanushuk reservoir that the
KRU operator proposes to develop. While Santos supports the proposed development of the
Coyote Oil Pool, we are presently unable to evaluate the potential for the AIO to impact resources
in the adjacent QKU, particularly impacts arising from injection operations. Given the limited
production history of the Nanushuk reservoir, access to every piece of data available is particularly
critical to informing our understanding of how the reservoir performs under different development
strategies. Presently, there is data that would aid our evaluation of the AIO proposal, but it is
unavailable to us for review due to an idiosyncrasy of the well classification regime, as described
herein.
The KRU Operator has recently drilled several wells from the 3S pad into the Coyote Undefined Oil
Pool in the Nanushuk reservoir within the KRU and is producing one or more of them, presumably
into and saving and delivering oil from KRU facilities operated by the KRU Operator. These wells,
the 3S-24B, 3S-701, 3S-701A, and 3S-704, were each submitted to AOGCC to be classified under
20 AAC 25.005 as “Exploratory.”
The “Exploratory” 3S-704 well was completed in March of 2023 from the KRU 3S gravel pad
operated by the KRU Operator and AOGCC records indicate the well has produced over 650,000
barrels of oil since completion. AOGCC records also indicate the “Exploratory” 3S-701A well has
been in injection service since September of 2023 and has injected nearly two million barrels of
liquid during that period, presumably in support of 3S-704 production.
As you know, well classification is significant because, amongst other things, it determines whether
data submitted to the AOGCC related to the well is held confidential for a period of time or released
By Samantha Coldiron at 10:01 am, Aug 20, 2024
Page 2 of 2
immediately to the public. Information submitted for wells classified as “Development” or “Service”
is subject to immediate release, while information submitted for wells classified as “Exploratory” is
held confidential for at least 24 months following completion.
Allowing an operator to classify wells as “Exploratory” and maintain well data as confidential despite
long-term production appears contrary to the State and AOGCC’s interest in maximizing the
conservation of Alaska’s resources and protecting the rights of all owners to recover their share of
the resource. This outcome does not appear to be a deliberate choice by the AOGCC but rather a
gap in the system of regulation otherwise designed to protect these interests.
Without access to the well data from the 3S-24B, 3S-701, 3S-701A and 3S-704 wells, it is not
possible for Santos to evaluate the impacts to QKU from the AIO and CO for the Coyote Oil Pool.
Other than supplying to Santos the application for the AIO as required by Commission regulations,
there has been no efforts by CPAI to coordinate with Santos development activities across the
Nanushuk Formation and jointly investigate ways to prevent waste of resources along property
lines.
Given the lack of data sharing and coordination to date, Santos respectfully requests that its
interests be protected by the AOGCC by including the following conditions in any CO or AIO
approval for the Coyote Oil Pool: (1) restrict well locations to one mile from the KRU boundary; and
(2) consider a voidage replacement ratio requirement to protect correlative rights across unit
boundaries and avoid waste. Exceptions to such an order could be filed at a later date if and when
additional data sharing and coordination has occurred between the unit operators.
Thank you for your consideration.
Sincerely,
Joe Balash
Senior Vice President, External Affairs
3
Pool & Area Injection Public Hearing
Coyote
August 20, 2024
Expert Witnesses Patrick Perfetta: Geology
•B.S. Geology, Indiana University of Pennsylvania
•M.S. Geology, University of Missouri
•Industry experience
•26 years, all with ConocoPhillips and its heritage companies (~15 years in Alaska)
–Field appraisal & development
–Exploration
–Technical oversight
ConocoPhillips 2
Nathan Sisemore: Reservoir Engineering
•B.S.Petroleum Engineering, University of Houston
•Industry experience
•10 years of work experience, all with ConocoPhillips (6 years in Alaska)
•Field appraisal & development
•Base performance
•Waterflood optimization
Mike Callahan: Drilling
•B.S. Petroleum Engineering, University of Texas
•Industry experience
•13 years, all with ConocoPhillips (9 years in Alaska)
–Drilling engineer
–Coiled tubing drilling engineer Madeline Woodard: Completions
•B.S. Mechanical Engineering, Colorado School of Mines
•Industry Experience
•10 years, all with ConocoPhillips (10 years in Alaska)
•Drilling Engineer
•Completions Engineer
Lynn Aleshire: Production
•B.S.Geological Engineering,South Dakota School of Mines
•M.S. Civil Engineering,UAA
•M.S. Arctic Engineering,UAA
•Industry Experience
–18 years with Amoco,MMS and ConocoPhillips. All in Alaska.
–Production,Resource Evaluation, Base performance,Waterflood optimization
Agenda
•Background and Project Overview (Patrick Perfetta)
•Geology and Pool Description (Patrick Perfetta)
•Resource and Recovery (Nathan Sisemore)
•Operations and Containment Assessment
•Well Design (Mike Callahan)
•Containment (Madeline Woodard)
•Facilities (Lynn Aleshire)
•Injection Fluids & Compatibility (Lynn Aleshire)
•Proposed Rules (Patrick Perfetta)
ConocoPhillips 3
AAC: Alaska Administrative Code
ADL: Alaska Division of Lands
AOGCC: Alaska Oil and Gas Conservation Commission
API: American Petroleum Institute
CIBP: Cast Iron Bridge Plug
CPAI: ConocoPhillips Alaska, Inc.
CPF: Central Processing Facility
DS: Drillsite
DFIT: Diagnostic Fracture Injection Test
ERIO: Enhanced Recovery Injection Order
GKA: Greater Kuparuk Area
GLM: Gas Lift Mandrel
GOR: Gas Oil Ratio
KRU: Kuparuk River Unit
LWD: Logging While Drilling
MD: Measured Depth
md: Millidarcy
MI: Miscible Injectant
MIT: Mechanical Integrity Test
MMSTB: Million Stock Tank Barrels
OSA: Oil Search Alaska
P&A: Plug and Abandon
PPG: Pounds Per Gallon
PSI: Pounds Per Square Inch
PW: Produced Water
RST: Reservoir Surveillance Tool
SHMIN: Minimum Horizontal Stress
STOOIP: Stock Tank Original Oil In Place
TOC: Top of Cement
TVD: True Vertical Depth
TVDSS/SSTVD: True Vertical Depth Subsea
Acronyms List
ConocoPhillips 4
Area Overview
•Proposed Coyote Oil Pool & area for injection located in western portion of the Kuparuk River Unit (KRU)
•Operator: ConocoPhillips Alaska, Inc.
•Partners: ExxonMobil, Chevron
•Pilot area previously approved for Coyote
•Enhanced Recovery Injection Order (ERIO 8)
•Surface owners
•State of Alaska
•Multiple Native Allotments
ConocoPhillips 5
Suspended
P&A’d
Active
CPAI Torok Oil Pool “Moraine”
Coyote Planned
Wells DisplayedProposed Pool and Area for Injection
Proposed Coyote Participating Area
Kuparuk River Unit
Proposed Kuparuk River Unit Expansion
Legend
Pikka Unit
Quokka Unit
Kuparuk River Unit
Oooguruk Unit
3S-701A / 3S-704
3S-24B
Palm 1
Geology and Pool Description
Exploration/Data Summary
•Numerous historical penetrations in wells targeting deeper stratigraphic intervals
•Typically, minimal data collection through Coyote
–Basic log suites
•Provide good depth, thickness, and mapping control to delineate the reservoir
•Recent focused data collection
•2020: OSA Mitquq wells
•2022: CPAI side-track with vertical production test
•2023: CPAI horizontal producer/injector well pair w dedicated pilot hole for data collection
•2024: CPAI horizontal producer
ConocoPhillips 7Coyote thickness/depth/mapping control point. Data varies by well
Logs Advanced LWD
Flow Longterm horizontal production
Pressure Multiple build-ups
CPAI: 3S-704
Logs LWD & Advanced Wireline
Core Sidewall: 76
Pressure Wireline pressures
PVT From downhole samples
OSA: Mitquq 1
Logs LWD & Advanced Wireline
Core Whole core 360' MD
Flow Short production test
Pressure Wireline pressures
PVT From downhole samples
OSA: Mitquq 1 ST1
Logs Advanced LWD
Flow Short clean-up period
Pressure Multiple: build-ups/fall-off's
Injection Longterm horizontal injection
CPAI: 3S-701A
Logs LWD Quad combo
Flow Longterm production data
Pressure Multiple build-ups
PVT From surface samples
CPAI: 3S-24B
Logs LWD, Advanced wireline
CPAI: Moraine 1
Logs Advanced wireline
Pioneer: Nuna 1 PB1
Logs Advanced LWD
Core Whole core ~390'
CPAI: 3S-701
Logs Advanced LWD
CPAI: 3S-718
Coyote Oil Pool Definition (Palm 1 Type Log)
ConocoPhillips 8
Top Coyote
4,270’ MD
(4,038’ SSTVD)
Base Coyote
5,115’ MD
(4,720’ SSTVD)NanushukTorokSeabeeKuparuk River:
Torok Oil Pool
Lower
Confining Zone
Upper
Confining Zone
Proposed Coyote
Oil Pool Formation•Confining intervals
•Upper: Distal toe of slope Seabee clay/siltstones, ~350’ thick
•Lower: Distal toe of slope Torok mudstones, ~300’ thick
Geologic Overview
ConocoPhillips 9
•Structure/Trap
•Generally low relief (~1 degree dip)
•Limited faulting
•Plunges to east & northeast outboard of current shelf margin
Top Coyote Depth StructureContour Interval 50’
Shallow
Deep
ConocoPhillips 10
Geologic Overview
•Depositional setting
•West to east progradational topset reservoir –Shelf edge deltaic influenced system–Thinly bedded from top to base (sand and silt)
•Elongate northeast to southwest, parallel to paleo-shelf margin
•Reservoir/Fluid properties
•Net pay: ~40 feet average (inside polygon)
•Average porosity: ~23-24%, permeability: ~10-20 md
•Water saturation: ~53%
Coyote Net PayContour Interval 20’
Thick
Thin
3S-701 Petrophysical Display
Top Coyote
Base Coyote
Well Log Cross-Section (Structural Datum)
ConocoPhillips 11
Log Legend
A
A’
B
B’A A’
Cored interval
B B’
Proposed AIO/Pool Boundary
Resource and Recovery
Development Layout
•Conceptual 40 well development (~1/2 producers, 1/2 injectors)
•Inter-well spacing: 1,300’
•Final well count pending phased drilling programs to understand reservoir performance & facility impacts
–3S existing slot/slot recovery drilling program
–Expanded section development
–Paleo-shelf development
ConocoPhillips 13
3S Existing Slot/Slot Recovery
Expanded Section Development
Paleo-shelf Development
Existing
Conceptual Coyote Development WellsProposed Pool and Area for Injection
Proposed Coyote Participating Area
Kuparuk River Unit
Proposed Kuparuk River Unit Expansion
Legend
Coyote Development Overlain on Net Pay
Thick
Thin
Net Pay
3T
3S
In Place Volume and Recovery
•Volumetric estimates are based off the mapping of core calibrated log model results from wells within and beyond the proposed pool area, guided by 3D seismic interpretations.
•Expected ultimate recovery based on reservoir simulation, calibrated to Phase 1 Coyote performance and North Slope fields with similar rock and fluid properties.
14
Coyote Pool Properties (@ -4150ft TVDSS)
Initial Pressure (psig)1,857
Temperature (F)105
GOR (scf/bbl)580-650
API Gravity (deg)32-35
Saturation Pressure (psig)1,794
Oil Volume Factor (rb/stb)1.28
Oil Viscosity (cp)1.0
Gas Volume Factor (rb/mscf)1.3
Combined Dev Area STOOIP (MMSTB)508-646
Total Pool Area STOOIP (MMSTB)636-810
Well Count (additional wells)30-40
Primary Recovery <5%
Primary + Waterflood Recovery 20-30%
Primary + Water Alternating Gas Under Evaluation
3S Slot Recovery
Expanded Section Development
Paleo-shelf DevelopmentExisting
Proposed Pool and Area for Injection
Proposed Coyote Participating Area
Kuparuk River UnitProposed Kuparuk River Unit Expansion
Coyote Development Overlain on Net Pay
Operations and Containment
Well Design
•2-string or 3-string casing design
•7” or 7-5/8” casing set in the reservoir and cemented to a minimum of 500’ MD / 250’ TVD above top Coyote
•Packer/isolation equipment may be located greater than 200' from top perforation/open interval (in lieu of 20 AAC 25.412(b) requirement of setting within 200' of top perforation/open interval) and shall be set within confining zone and at least 100’ below the top of cement
•Cemented 4-1/2” casing/liner within reservoir
•Fracture stimulated laterals with 500’ stage spacing
Injection Containment
ConocoPhillips 1717
Fracture closure pressure: 0.62 psi/ft (4,109 SSTVD, 4,165’ TVD)
Source: Interpreted closure pressure from mini-frac
Overburden fracture closure pressure: 0.67 psi/ft (3,951’ SSTVD, 4,007’ TVD)
Source: Diagnostic fracture injection test (DFIT) -> 0.02 psi/ft greater than
originally estimated
No current data on leak off or formation breakdown pressure
Shmin Curves
Upper Confining Zone: Distal toe of slope Seabee clay/siltstones, ~350’ thick
OB Perfs: 7,793’ MD / 4,007’ TVD to 7,798’ MD / 4,012’ TVD
Reservoir Perfs: 7,943’ MD / 4,154’ TVD to 7,953’ MD / 4,164’ TVD 7,958’ MD / 4,168’ TVD to 7,963’ MD / 4,174’ TVD
3S-24B History Match
18
Frac height interpretation from CARBONRT
•Strong signals observed on all log measurements: 7,898 – 7,993’ MD (95’)
•Represents minimum height growth interpretation
0
5
~120’
VSHALE SSTVD MD Pay RES History Matched Proppant Concentration lb/ft2
Perfs
Coyote Gross IntervalGas Cap
~280’
RST Pulsed Neutron Interpretation
High confidence fracture
Possible fracture
~230’
147’118’
95’
High Confidence Fracture
160 ft
270 ft
Prop
Con
0 – 5
lb/ft2
0
1
2
3
4
5
•Pressure history match completed on 3S-24B
using GOHFER fracture modeling software
̶Inputs based on 3S-24B well logs calibrated to
geomechanical laboratory tests
•History match did not show overburden fracture
growth although logs showed potential for fracture
growth into the overburden
̶Laboratory Conductivity testing proves no remaining
conductivity in the overburden
•Lateral placement updated to 100 ft below the top
of Coyote based on the 3S-24B post job stimulation
modeling and history matching
̶Moved lateral deeper than originally planned after
post job analysis on 3S-24B
̶3S-701A history match does not show overburden
growth
Injection Pressures
•There is risk that fractures could grow into the overburden during hydraulic fracture stimulation operations
•Most recent history matching with deeper lateral placement does not show overburden growth of hydraulic fractures
•If a hydraulic fracture does grow into the overburden during stimulation, there is almost no remaining conductivity due to gel damage and proppant embedment
•Injecting at or under the overburden closure pressure would not re-open or extend any fracture in the overburden
•Injection pressure request: 0.67 psi/ft
•Potential future request to increase if formation breakdown pressure or leak off data is obtained in the overlying seal
Overburden Reservoir
Pc 0.67 psi/ft
Pc 0.62 psi/ft
FBP
Facilities
ConocoPhillips 20
Primary Injection Fluids
•Produced water and gas from all present and yet-to-be defined oil pools within the KRU
•Beaufort seawater sourced from the Oliktok Point seawater treatment plant which provides seawater for GKA.
•Enriched hydrocarbon gas (MI): KRU lean gas blended with indigenous and/or imported natural gas liquids
Secondary Injection Fluids
•Fluids used during hydraulic fracture stimulation in accordance with 20 AAC 25.283
•Tracer survey fluids to monitor reservoir performance
•Fluids used to improve near-wellbore injectivity (solvents, acids, etc.)
•Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, polymer, etc.)
•Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
•Freeze-protect fluids
Water Compatiblility
•Modeling indicates potential for scale formation in the wellbore. Produced water injection will reduce that risk.
•Coyote wells will be included in the GKA scale inhibition program which includes regular produced water sampling and scheduled inhibition treatments.
Injection Fluids & Compatibility
ConocoPhillips 21
Proposed Pool Rules
Proposed Pool Rules
•Rule 1: Field and Pool Name
•The field is the Kuparuk River Field, and the pool is the Coyote Oil Pool.
•Rule 2: Pool Definition
•The Coyote Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the Palm No. 1 well between the depths of 4,270’ MD and 5,115’ MD (-4,038’ and -4,720’ TVDSS respectively).
•Rule 3: Gas Oil Ratio Exemption
•Wells producing from the Coyote Oil Pool are exempt from the gas-oil ratio (GOR) limit set forth in 20 AAC 25.240.
•Rule 4: Drilling and Completion Practices
A.Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles.
B.In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: plan view, vertical section, close approach data, and directional data.
C.In lieu of the requirements under 20 AAC 25.071(a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio-activity log unless the commission specifies which type of log is to be run. This has already been satisfied for both drill sites 3S and 3T, the primary pads from which Coyote development wells will be drilled.
Proposed Pool Rules, Continued
•Rule 5: Well Spacing
•There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500’ of an external property line where the working interest owners are not the same on both sides of the line.
•Rule 6: Reservoir Surveillance
A.Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating injection.
B.Static surveys will be performed on production wells at the discretion of CPAI.
C.For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the Coyote Oil Pool, concentrating on injection wells.
D.In lieu of stabilized bottom-hole pressure measurements, the alternative pressure survey methods below can be implemented:
a.open-hole wireline formation fluid pressure measurements,
b.cased hole pressure buildups with bottom-hole pressure measurement,
c.injector surface pressure fall-off,
d.static pressure surveys following extended shut-in periods, or
e.bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector
E.All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys.
•Rule 7: Production Practices
•In lieu of the requirements under 20 AAC 25.230(a), CPAI proposes that each producing well will be tested at least monthly.
Proposed Rules for Area Injection
Proposed Rules for Area Injection
•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 recover y within the proposed Coyote Oil Pool, which is defined as the accumulation of oil and gas common to and correlating with the interval within the Palm 1 well between the measured depths of 4,270’ MD and 5,115’ MD (-4,038’ TVDSS and -4,720’ 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 more than 200’ measured depth 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 100’ measured depth above the planned packer depth.
•Rule 3: Authorized Fluids for Injection or Enhanced Recovery
•Source water from the Kuparuk seawater treatment plant
•Produced water from all present and yet-to-be defined oil pools within the Kuparuk River Field
•Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids
•Lean gas
•Fluids used during hydraulic stimulation
•Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.)
•Fluids used to improve near wellbore injectivity (via use of acid or similar treatment)
•Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.)
•Fluids associated with freeze protection (diesel, glycol, methanol, etc.)
•Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Proposed Rules for Area Injection, Continued
•Rule 4: Authorized Injection Pressure for Enhanced Recovery
•Injection pressures will be managed to not exceed the maximum injection gradient of 0.67 psi/ft to ensure containment of injected fluids within the Coyote Oil Pool.
•Rule 5: Monitoring Tubing-Casing Annulus Pressure
•Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the Coyote Oil Pool and are located within a ¼-mile radius of a Coyote Oil Pool 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 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 of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, 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.
Proposed Rules for Area Injection, Continued
•Rule 7: Well Integrity and Confinement
•Whenever the Operator observes an indication of pressure communication, leakage, or lack of injection zone isolation, the Operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer annulus pressure monitoring in wells within one-quarter mile radius of where the Coyote Oil Pool is not cemented. If the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the Operator must submit a corrective action plan to the AOGCC, following the KRU Sundry Matrix (CO 261B). The Operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the Operator to shut in the well. The Operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation.
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
ALASKA OIL AND GAS CONSERVATION COMMISSION
In the Matter of the Application of )
ConocoPhillips Alaska for an Area )
Injection Order and Pool Rules for the )
Coyote Interval. )
_________________________________________)
Docket No.: CO-24-009 and AIO-24-019
PUBLIC HEARING
August 20, 2024
10:00 o'clock a.m.
Anchorage, Alaska
BEFORE: Jessie Chmielowski, Commissioner
Greg Wilson, Commissioner
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
1 TABLE OF CONTENTS
2 Opening remarks by Commissioner Chmielowski 03
3 Remarks by Patrick Perfetta 09
4 Remarks by Nathan Sisemore 19
5 Remarks by Mike Callahan 21
6 Remarks by Madeline Woodard 28
7 Remarks by Lynn Aleshire 33
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 3
1 P R O C E E D I N G S
2 (On record - 10:00 a.m.)
3 COMMISSIONER CHMIELOWSKI: .....Tuesday, August
4 20th, 2024. This is a public hearing on docket number
5 CO-24-009 and AIO-24-019 to consider ConocoPhillips
6 Alaska's application for an area injection order and
7 pool rules for the Coyote interval. I am Commissioner
8 Jessie Chmielowski and with me is Commissioner Greg
9 Wilson.
10 Today's hearing is being held in person and via
11 Microsoft Teams. The in person location is the Alaska
12 Oil and Gas Conservation Commission office at 333 West
13 Seventh Avenue, Anchorage, Alaska. For those on Teams
14 please be mindful of any background noise and make sure
15 you are muted when you're not testifying or addressing
16 the Commission.
17 If you require any special accommodation please
18 contact Samantha Coldiron. She can be reached at 907-
19 793-1223 or send her a message through the Microsoft
20 Teams chat icon and she will do her best to accommodate
21 you.
22 Samantha Coldiron will be recording the
23 hearing. Computer Matrix will be preparing the
24 transcript. Upon completion and preparation of the
25 transcript anyone desiring a copy will be able to
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 4
1 obtain it by contacting Computer Matrix.
2 This hearing is being held in accordance with
3 Alaska statute 44.62 and 20 AAC 25.540 of the Alaska
4 Administrative Code.
5 The notice of hearing was published on the
6 State of Alaska online notices website as well as the
7 AOGCC's website and was sent through the AOGCC email
8 listserv on July 12th, 2024. The AOGCC also published
9 the notice in the Anchorage Daily News on July 14th,
10 2024.
11 To date the AOGCC has just received one public
12 comment on this matter, written comment.
13 Background on the purpose of this hearing. The
14 AOGCC prescribes pool rules that govern the development
15 of oil and gas pools when a modification of a statewide
16 regulation is needed to facilitate development of the
17 pool. Some common rules are modification of the permit
18 to drill application process when additional data would
19 not add to the understanding of the geology in the
20 project area. Oh, I misspoke. Modification of the
21 permit to drill application process to streamline
22 applications and of the data collection requirements
23 when additional data would not add to the understanding
24 of the geology in the project area.
25 Additionally the AOGCC approved injection
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 5
1 orders for several purposes including enhanced oil
2 recovery, EOR, storage and disposal either on an
3 individual well or an areawide basis in Alaska. EOR
4 injection orders establish rules for conducting
5 operations that are intended to increase the amount of
6 oil or gas that could be recovered from a pool by one
7 or more of the following mechanisms, maintaining
8 reservoir energy, sweeping oil through the reservoir to
9 a production well or modifying the properties of the
10 oil to make it more mobile. This is consistent with
11 the portion of the AOGCC's mission that seeks to
12 promote greater ultimate recovery.
13 The Commissioners will ask questions during
14 testimony. We may also take a recess to consult with
15 Staff to determine whether additional information or
16 clarifying questions are necessary.
17 Representatives from ConocoPhillips, are you
18 ready to make your presentation.
19 (No audible response)
20 COMMISSIONER CHMIELOWSKI: Great. I will now
21 swear in the witnesses, it looks like there are four of
22 you presenting today; is that correct?
23 (No audible response)
24 COMMISSIONER CHMIELOWSKI: Five. Okay. Great.
25 Well, if you could all please raise your right hand and
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 6
1 respond.
2 (Oath administered)
3 (No audible response)
4 COMMISSIONER CHMIELOWSKI: Yes. So let the
5 record reflect that the witnesses responded in the
6 affirmative.
7 Do any of you presenting today wish to be
8 recognized as experts.
9 (No audible response)
10 COMMISSIONER CHMIELOWSKI: Yes. All of you.
11 Okay. So please identify your field of expertise and
12 your credentials one at a time and we'll go through all
13 of them and then affirm at the end.
14 (No audible response)
15 COMMISSIONER CHMIELOWSKI: Sounds great.
16 (No audible response)
17 COMMISSIONER CHMIELOWSKI: Yeah. And make sure
18 your microphone is on. There should be a bright green
19 light. Perfect.
20 MR. PERFETTA: Hello. This is Patrick
21 Perfetta. I wish to be recognized as an expert witness
22 in the field of geology. I have a bachelor's degree in
23 geology from Indiana University of Pennsylvania and a
24 master's degree in geology from the University of
25 Missouri. I've worked for ConocoPhillips for about 26
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 7
1 years. A lot of that has been in Alaska and I have
2 experience in exploration, field appraisal and
3 development and technical oversight.
4 COMMISSIONER CHMIELOWSKI: Thank you. Next.
5 MR. SISEMORE: My name is Nathan Sisemore. I'd
6 like to be recognized as a witness in reservoir
7 engineering. I have a bachelor of science in petroleum
8 engineering from the University of Houston. Been in
9 the industry for 10 years primarily working in
10 conventional (indiscernible) waterflood, six years in
11 Alaska working with multiple assets.
12 COMMISSIONER CHMIELOWSKI: Great.
13 MS. ALESHIRE: My name is Lynn Aleshire. I
14 have a bachelor's in geological engineering from South
15 Dakota School of Mines, a master's in civil in the
16 arctic from UAA Engineering. I've had 18 years with
17 Amoco, MMS and ConocoPhillips, all of that in Alaska.
18 And I focus on production, resource evaluation, base
19 performance and waterflood.
20 COMMISSIONER CHMIELOWSKI: Thank you.
21 MR. CALLAHAN: My name is Mike Callahan. I've
22 got a bachelor's degree in petroleum engineering from
23 the University of Texas. I've been in the industry all
24 with ConocoPhillips for 13 years, nine of which have
25 been in Alaska all in drilling engineering and coil
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 8
1 tubing drilling engineering.
2 MS. WOODARD: Hi. My name is Madeline Woodard.
3 I'm currently a completions engineer for
4 ConocoPhillips. I have a bachelor's degree in
5 mechanical engineering from Colorado School of Mines.
6 I have worked for ConocoPhillips for 10 years all in
7 Alaska as a drilling engineer and completions engineer.
8 COMMISSIONER CHMIELOWSKI: Thank you.
9 Commissioner Wilson, do you have any questions for the
10 presenters.
11 COMMISSIONER WILSON: Nothing at this time.
12 COMMISSIONER CHMIELOWSKI: Ah. All right. Any
13 objections to certifying the witnesses, I mean, as
14 experts.
15 COMMISSIONER WILSON: Not at all.
16 COMMISSIONER CHMIELOWSKI: All right. Neither
17 do I. You will all be recognized as experts in the
18 fields you identified.
19 Thank you very much.
20 So before beginning the presentation just I
21 want to check, Commissioner Wilson, do you have any
22 questions before we start.
23 COMMISSIONER WILSON: Not at this time.
24 COMMISSIONER CHMIELOWSKI: Okay. Thank you.
25 So for those testifying please remember to speak into
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 9
1 the microphone, I want to kind of make it so we can all
2 hear in the room and then it won't -- we will know the
3 transcript is picking it up.
4 Also please reference your slides by number or
5 title so that the public record can follow along,
6 people reading the transcript will know what slide
7 you're speaking to when they read it. And then as
8 you're speaking please say again your names and job
9 titles clearly for the record. And whenever you're
10 ready to start please do.
11 PATRICK PERFETTA
12 previously sworn, called as a witness on behalf of
13 ConocoPhillips Alaska testified as follows.
14 MR. PERFETTA: Okay. Great. This is Patrick
15 Perfetta. I'm -- I'm on slide 1 and I am a geologist
16 by background.
17 Hello, Commissioners. On behalf of
18 ConocoPhillips Alaska and its partners we're here today
19 to present on the proposed application for the
20 requested formation of the Coyote oil pool and area
21 injection. Before we begin I'd like to thank the AOGCC
22 Staff who met with us and reviewed and provided
23 feedback on our draft applications prior to their final
24 submittal.
25 I'm going to skip slide 2 because that was our
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 10
1 expert witness swear-in and move to slide 3. This is
2 basically a simple agenda slide for our presentation
3 today. It also lists those individuals who will be
4 covering each topic in the -- in the presentation
5 today.
6 Slide 4. This is purely a reference slide that
7 contains a list of acronyms that may be used during the
8 presentation today or found on slides within the
9 presentation.
10 Moving to slide 5. I will begin with an area
11 overview. The map on the -- the right side of the
12 slide shows the area of interest. There's a lot of
13 information on this map so I'll methodically walk
14 through what is -- what's included on it. Highlighted
15 in yellow with the red border is the current Kuparuk
16 River Unit which is operated by ConocoPhillips. Our
17 partners in this unit are ExxonMobil and Chevron. The
18 single lease shown in gray shading has a lease that
19 currently resides outside of the Kuparuk River Unit.
20 Application has been submitted to the DNR to expand the
21 KRU to include this lease. The black dashed polygon is
22 the proposed Coyote participating area. The
23 application just for -- has also been submitted to DNR
24 and it is pending. The blue dashed polygon is the
25 proposed area of the Coyote oil pool and area for
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 11
1 injection associated with our application submitted to
2 the AOGCC. The blue solid polygon is the area
3 associated with the existing Coyote enhanced recovery
4 injection order, EORI 8. This was previously approved
5 by the AOGCC in January of 2023. Inside that polygon
6 are the initial wells drilled by ConocoPhillips for
7 production and injection associated with the Coyote
8 interval. These include the 3S24B which was our
9 initial Coyote production well and has subsequently
10 been P&A'd. And our first Coyote horizontal producer,
11 3S704, shown in green and 3S701A, our first Coyote
12 horizontal injection well which is shown. Another well
13 of interest highlighted on the map is the Palm 1 which
14 is our proposed type well for definition of the Coyote.
15 Also included on the map are other historical well
16 siders in black, recent Torok oil pool wells in light
17 blue and the conceptual Coyote development reddish
18 color. Prior to leaving this slide I'd also like to
19 mention surface owners who are within the blue dashed
20 polygon and a quarter-mile buffer around it, may
21 include the state of Alaska as well as multiple Native
22 allotments, all of which have been identified or
23 notified and sent a copy of our application.
24 COMMISSIONER CHMIELOWSKI: Thank you, Mr.
25 Perfetta. You said that the -- the expansion of the --
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 12
1 of the -- is it the unit or the PA here that's in
2 progress. Do you have any idea when that might occur
3 or.....
4 MR. PERFETTA: We expect a decision from DNR by
5 October 28th.
6 COMMISSIONER CHMIELOWSKI: October 28th. Thank
7 you.
8 MR. PERFETTA: Moving on to slide 6. I will
9 now present on the geology of the proposed Coyote.
10 Slide 7. This slide gives a brief historical
11 background specific to Coyote, some of the data that is
12 available for its characterization. Shown on the map
13 on the right side of the slide are the wells drilled in
14 the area that have penetrated interval and are
15 available for mapping. These are indicated by the red
16 circles placed where each of these wellbores intersects
17 the top of the Coyote reservoir. Most of these wells
18 were drilled to deeper reservoirs and had a mix of data
19 collection through the Coyote interval, typically
20 basically LWD sweeps including gamma ray resistivity.
21 There are numerous wells that have porosity logs and
22 occasionally sonic. These wells provide good depth,
23 thickness and general mapping control to define the
24 Coyote trend. Highlighted in the call out boxes are
25 historical wells that had some advance level of
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 13
1 additional data collection in the interval and other
2 more recent Coyote specific data -- data collection
3 wells some of which I referenced on the previous slide.
4 These include the Mitquq wells drilled in 2020 by Oil
5 Search Alaska just southwest of the Kuparuk River Unit
6 boundary, ConocoPhillips' 3S20D drilled in 2022,
7 ConocoPhillips' horizontal producer injector pilot
8 drilled in 2023. This drilling program also included a
9 pilot hole, the 3S701 where hole core and advance logs
10 were required through the Coyote interval. The most
11 recent Coyote dedicated drilling is our 3S18 horizontal
12 producer that reached TD earlier this month. It is
13 located to the northeast of 3S pad.
14 COMMISSIONER CHMIELOWSKI: May I ask a question
15 on this slide before you move on. Those wells, those
16 horizonal wells in gray that kind of go to the north
17 are those the Torok wells you mentioned before?
18 MR. PERFETTA: That's correct.
19 COMMISSIONER CHMIELOWSKI: Okay. Thank you.
20 MR. PERFETTA: Moving on to slide 8. This
21 slide shows the proposed type log for the Coyote oil
22 pool which is the Palm 1 well previously mentioned. It
23 was drilled from 3S pad within the Kuparuk River Unit.
24 It's location is highlighted by the yellow star in the
25 inset map at the bottom half of the slide. The
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 14
1 proposed Coyote oil pool is highlighted in yellow log
2 display. It has gamma ray as the first track followed
3 by resistivity, NC neutron and sonic in the subsequent
4 non-depth track. The Coyote reservoir interval is part
5 of the regional Nanushuk formation. It is bound below
6 by the lower confining interval which consists of
7 distil tow slope mudstones associated with the Torok
8 formation. It should be noted that these mudstones
9 form the upper confining interval of the Kuparuk River
10 Torok oil pool. The Coyote interval is found above by
11 distil tow slope claystone and minor very thin
12 siltstones associated with the CB formation. And it
13 should be noted that both the Torok and CB intervals
14 are present in thicknesses greater than 300 feet TVD
15 over the proposed area of injection.
16 COMMISSIONER CHMIELOWSKI: Another question.
17 So those Torok wells you mentioned before, those are in
18 the -- what you're calling the Torok oil pool which is
19 just below the Torok confining zone?
20 MR. PERFETTA: That is correct.
21 COMMISSIONER CHMIELOWSKI: Okay.
22 MR. PERFETTA: Moving on to slide 9. This is a
23 depth structure map of the top of the proposed Coyote
24 oil pool. The structure at this -- this level is
25 generally low release with structural dips of
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 15
1 approximately one degree. There is limited faulting at
2 this stratigraphic level and when present the faults
3 generally trend in a southwest to northeast
4 orientation. The only area where dip is much greater
5 than one degree is to the east and northeast outward of
6 Coyote's final associated shelf-margins.
7 Slide 10. This is an overview of the
8 depositional setting and reservoir characteristics of
9 the Coyote interval. The Coyote is a west to east
10 progradational topset reservoir consisting of Deltaic
11 influenced shelf edge deposits. The reservoir is
12 thinly bedded at the sub-inch to inch scale from top to
13 base. The Coyote trend is elongated in a northeast to
14 southwest direction and shows expansion outward of the
15 paleo shelf-margin the trend of which is shown by the
16 gray polygon on the net pay map on the right side of
17 this slide.
18 (Technical problems - screen down).
19 COMMISSIONER CHMIELOWSKI: One moment. We're
20 just getting the presentation back on the screen.
21 (Technical problems - screen down).
22 COMMISSIONER CHMIELOWSKI: We need to get
23 someone in?
24 MS. COLDIRON: Yeah, because there's
25 (indiscernible - away from microphone).
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 16
1 COMMISSIONER CHMIELOWSKI: Okay. Let's take a
2 10 minute recess everyone and we'll troubleshoot these
3 issues. Thanks for your patience. We'll get that on
4 as soon as we can. So the time is 10:19. We'll shoot
5 for 10:30 to restart.
6 Thank you.
7 (Off record - 10:19 a.m.)
8 (On record - 10:30 a.m.)
9 COMMISSIONER CHMIELOWSKI: All right. Thank
10 you, everyone. It's 10:30 on the dot. And I think we
11 got -- have our technical difficulty solved. There
12 were some comments that people online had a hard time
13 hearing the presenters. So if you can -- you can -- I
14 can hear myself in the room, just make sure, you know,
15 you're close to the microphone so that people on Teams
16 can hear you that would be great. And we'll go ahead
17 and -- and restart and I think we were on geologic
18 overview slide. Is that where we're going to continue
19 there?
20 MR. PERFETTA: Yes, that's.....
21 COMMISSIONER CHMIELOWSKI: Great.
22 MR. PERFETTA: .....where we can continue.
23 COMMISSIONER CHMIELOWSKI: Thank you.
24 MR. PERFETTA: Okay. So we are on slide 10
25 which is an overview of the depositional setting and
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 17
1 reservoir characteristics of the Coyote interval. The
2 Coyote is a west to east progradational topset
3 reservoir consisting of Deltaic influenced shelf edge
4 deposits. The reservoir is thinly bedded at the sub-
5 inch to inch scale from top to base. The Coyote trend
6 is elongated in a northeast to southwest direction and
7 shows expansion outward of the paleo shelf-margin the
8 trend of which is shown by the gray polygon on the net
9 pay map on the right side of this slide. Coyote is
10 predominantly a stratigraphic trap with pinch-out
11 generally to the west and shale out generally to the
12 east. The reservoir has an average of approximately 40
13 feet of net pay inside the blue dashed polygon.
14 Average properties of reservoir sand include porosities
15 of 23 to 24 percent, permeabilities of 10 to 20
16 milliedarcys and water saturation of approximately 53
17 percent. Included for reference on the bottom left of
18 the slide is a log display of interpreted petrophysical
19 curves from the Coyote core calibrated petrophysical
20 model. To the left of the depth track is gamma ray
21 shaded by the volume of shale. To the right of the
22 depth tracks are porosity of sand, water saturation of
23 sand, volume sandstone, a bulk volume water display,
24 mud gas curves and the current Coyote net pay flag.
25 COMMISSIONER CHMIELOWSKI: Question. I believe
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 18
1 in the application Conoco stated that the oil/water
2 contact depth was at 4,260 TVD subsea; is that correct?
3 MR. PERFETTA: Yes, that's approximately where
4 we think it is. There's some uncertainty in that.
5 COMMISSIONER CHMIELOWSKI: Okay. And then it
6 says generally that the reservoir dips below the
7 oil/water contact south of the KRU. Can you kind of
8 generally point out what you mean by south of the KRU
9 or.....
10 MR. PERFETTA: Sure. It is -- actually we
11 believe it is south of what is shown on the map.
12 COMMISSIONER CHMIELOWSKI: Oh, it is. Okay.
13 So not in the KRU at all, but.....
14 MR. PERFETTA: That's correct.
15 COMMISSIONER CHMIELOWSKI: .....below it?
16 Okay.
17 MR. PERFETTA: Yeah.
18 COMMISSIONER CHMIELOWSKI: Thank you.
19 MR. PERFETTA: Uh-huh.
20 COMMISSIONER WILSON: I guess I have a question
21 about the trend to the northeast then. Is that a loss
22 of reservoir or is that dipping below the oil/water
23 contact?
24 MR. PERFETTA: Yeah, that is where the
25 structure begins to dip below the -- the presumed
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 19
1 4,260.
2 So slide 11. Included on this slide are two
3 structurally datums willow cross-sections, A to A prime
4 and B to B prime, the locations of which can be seen on
5 the inset structure map. Both cross-sections have
6 gamma ray to the left -- left of the -- the depth
7 tracks and resistivity to the right. A to A prime on
8 the upper portion of the slide is a dip oriented
9 section trending from northwest to southeast. On this
10 cross-section you can see the previously mentioned
11 paleo shelf area to the northwest where the Coyote
12 interval is relatively thin, an expansion to the
13 southeast outward of the paleo shelf margin. B to B
14 prime is a strike oriented cross-section trending from
15 southwest to northeast. The Coyote gross thickness is
16 generally consistent in a strike parallel direction.
17 Both of these sections also highlight the Coyote
18 interval in the yellow shading and the upper and lower
19 confining intervals in the gray shading.
20 And that concludes the -- the geology portion.
21 I'll now turn it over to Nathan.
22 COMMISSIONER CHMIELOWSKI: All right.
23 NATHAN SISEMORE
24 previously sworn, called as a witness on behalf of
25 ConocoPhillips Alaska, testified as follows.
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 20
1 MR. SISEMORE: Hello. My name is Nathan
2 Sisemore, a reservoir engineer and I will be presenting
3 on slides 12 through 14.
4 Slide 12 is our title slide for this section
5 entitled Resource and Recovery. Continue to slide 13.
6 On slide 13 to the right we show a conceptual
7 development layout map with similar polygons as those
8 described by Pat Perfetta on slide 5, overlaying a net
9 pay map as described by Pat on slide 10. This map also
10 includes roughly 40 well sticks that make up our
11 conceptual development design. Wells are oriented
12 northwest to southeast, aligning with regional stress
13 trends to achieve longitudinal hydraulically stimulated
14 fractures in both producers and injectors, creating
15 horizonal line drive waterflood patterns at 1,300 foot
16 spacing. The final development layout will be informed
17 by a phased drilling program in late 2024 and early
18 2025 where we intend to test reservoir performance
19 across the participating area. The first phases of
20 development utilize existing infrastructure using shut-
21 in Kuparuk slots at 3S and new well slots from new
22 drillsite 3T for appraisal drilling. These wells are
23 shown as purple dashed lines on the map. We will
24 incorporate learnings from this phase into our final
25 development concept which could include infrastructure
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1 upgrades at drillsites 3S and 3T. These potential
2 future wells are shown as black dashed lines for the
3 thicker section of the Coyote trend and gray dashed
4 lines for the thinner paleo shelf region to the
5 northwest.
6 Are there any questions currently regarding
7 development layout?
8 COMMISSIONER WILSON: Yeah, I have a question.
9 It's regarding that southern lease. The western 3T
10 wells terminate in what ConocoPhillips' map says
11 significant pay. I was just curious why the wells
12 terminate where they do -- I have a couple questions
13 here, why the wells terminate where they do, what the
14 length of the well is there and obviously you show pay
15 across the lease boundary and so has there been any
16 discussion with the offset operator?
17 MIKE CALLAHAN
18 previously sworn, called as a witness on behalf of
19 ConocoPhillips Alaska, testified as follows.
20 MR. CALLAHAN: Yeah, I can take that. Mike
21 Callahan, drilling engineer. The wells to the
22 southwest there drilled from 3T pad, total measured
23 depth is around 25,000 feet with laterals in the range
24 of about 12,000 feet. And that is roughly the longest
25 extent we project we can drill from existing
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1 infrastructure. We don't believe we can reach those
2 with our current drilling capabilities any further.
3 COMMISSIONER CHMIELOWSKI: Which rig do you
4 plan to use again?
5 MR. CALLAHAN: Currently proposed to use either
6 Doyon 142 or Doyon 25 with potential for another rig
7 later in the development drilling.
8 COMMISSIONER CHMIELOWSKI: Okay. Thank you.
9 COMMISSIONER WILSON: And the second part of
10 that question has there been any discussion with the
11 operator on the other side of the lease boundary?
12 MR. SISEMORE: We have not had discussions with
13 the offset operator to this point.
14 COMMISSIONER WILSON: That's all.
15 MR. SISEMORE: We're moving to slide 14 where
16 we show the same development concept map on the right.
17 To the left is a table of relevant rock and fluid
18 properties including total stock tank oil in place for
19 the development area within the black dashed line and
20 the entire pool area within the blue dashed line.
21 These volumes are based on mapping of core calibrated
22 log model results within and outside of the proposed
23 pool area guided by 3D seismic interpretation. Also in
24 the table are expected ranges for primary and
25 waterflood recovery. These are based off full field
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1 reservoir simulation which calibrates with early time
2 performance data using our existing horizontal well
3 here as well as long term trends from North Slope
4 fields with similar properties. As previously
5 mentioned our development strategy is based on a
6 horizontal line drive waterflood pattern which we
7 estimate to have a recovery of 20 to 30 percent. Both
8 seawater and produced water will be used for
9 waterflooding purposes as requested in rule 3 of the
10 area injection order. Also requested in rule 3 is the
11 ability to inject both lean gas and miscible gas.
12 While waterflood is our current base premise we have
13 concluded lab testing on Coyote fluid samples earlier
14 this year and will be quantifying the potential
15 benefits of gas injection, both lean and miscible gas,
16 in the fourth quarter of this year to inform our future
17 strategy.
18 Are there any questions at this time on in
19 place volumes and recovery?
20 COMMISSIONER CHMIELOWSKI: I have a question
21 about future gas injection. Is that going to be for a
22 later part of the presentation?
23 MR. SISEMORE: We don't have currently.....
24 COMMISSIONER CHMIELOWSKI: Okay.
25 MR. SISEMORE: .....in the presentation on gas
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1 injection.
2 COMMISSIONER CHMIELOWSKI: So the question is I
3 think the -- the application states that gas injection
4 is being evaluated to -- to estimate, you know,
5 incremental recovery. So the question is what other
6 data does Conoco plan to collect and that are the
7 evaluation plans and timeline to evaluate whether gas
8 injection is worthwhile?
9 MR. SISEMORE: So we -- we did some advance PPT
10 testing earlier this year and we are incorporating the
11 -- the results now into the simulation to quantify the
12 benefit. And we expect to have that done by Q4 of this
13 year.
14 COMMISSIONER CHMIELOWSKI: 4Q. Okay. Thank
15 you.
16 MR. CALLAHAN: This is Mike Callahan, drilling
17 engineer talking to slides 15 and 16. Slide 15 is just
18 the title slide of our operations and containment
19 section.
20 Moving on to slide 16 I'll talk through our
21 proposed well design. For the Coyote development we
22 plan to use either a two string or a three string
23 casing design for all of the wells. This is a very
24 standard design for us on the North Slope. Beginning
25 with surface casing set below the base of the West Sac
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1 and that casing will be cemented to surface. We will
2 then run either seven inch or seven and five-eights
3 casing which will be set within the Coyote pool and
4 cemented to a minimum of 500 feet measured depth or 250
5 feet TVD, whichever is greater, above the top of the
6 Coyote interval. There are no known hydrocarbon zones
7 between where we plan to set our surface casing and the
8 top of the Coyote interval. In lieu of the
9 requirements to set our isolation equipment within 200
10 feet of the top of the uppermost open interval, in our
11 pool rules we proposed setting that within the
12 confining zone at a minimum of 100 feet below the top
13 of that cement on our intermediate casing. Our lateral
14 sections will be drilled with six and a half inch hole
15 and completed with four and a half inch cemented liner
16 or casing that will be cemented back within the seven
17 inch or seven and five-eights. And then our completion
18 design involves fracture stimulation currently proposed
19 at a stage spacing of 500 feet.
20 COMMISSIONER CHMIELOWSKI: Thank you. So which
21 wells are planned for the two string design versus the
22 three string design?
23 MR. CALLAHAN: As of right now all of our wells
24 are planned with a three string. We have an upcoming
25 trial in early 2025 for our first two string design.
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1 Basically the shorter, simpler trajectories in the
2 program anywhere from four to 10 wells could be two
3 string design pending the success of that first well
4 from 3T pad early next year. The end result of the --
5 the two designs is roughly the same and the two string
6 design will run a seven inch or seven and five-eights
7 by four and a half inch tapered string. And that will
8 be cemented all the way back up to that 500 or 250 foot
9 same cement height depth. The three string design is
10 basically the same except the four and a half will be
11 run as a liner set within the seven and five-eights.
12 COMMISSIONER CHMIELOWSKI: Okay. So the three
13 string is kind of your base plan, if the 3T well trial
14 goes well you might consider more?
15 MR. CALLAHAN: Correct.
16 COMMISSIONER CHMIELOWSKI: So we'll expect to
17 see a drilling permit for that?
18 MR. CALLAHAN: CORRECT. Yeah, the.....
19 COMMISSIONER CHMIELOWSKI: Okay.
20 MR. CALLAHAN: .....the permit to drill for the
21 first two string will be coming up later this year,
22 like I mentioned I believe currently on our schedule in
23 early Q1.....
24 COMMISSIONER CHMIELOWSKI: Okay.
25 MR. CALLAHAN: .....of '25.
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1 COMMISSIONER CHMIELOWSKI: And so is this two
2 string design like a new design so this is the first
3 trial or has it been used elsewhere by Conoco?
4 MR. CALLAHAN: It'll be the -- the first trial
5 for us at.....
6 COMMISSIONER CHMIELOWSKI: Okay.
7 MR. CALLAHAN: .....Coyote.
8 COMMISSIONER CHMIELOWSKI: Uh-huh.
9 MR. CALLAHAN: We completed a similar design,
10 the Tinmiaq 20 well a number of years ago.
11 COMMISSIONER CHMIELOWSKI: Okay.
12 MR. CALLAHAN: That was a seven inch by four
13 and a half tapered two string. But this will be our --
14 our first in the Coyote area.
15 COMMISSIONER CHMIELOWSKI: Okay. And then are
16 you able to speak to how Conoco will ensure adequate
17 cementing of the deeper string, like is there going to
18 be a two stage job or do you know yet how that would be
19 accomplished?
20 MR. CALLAHAN: On a two string specifically?
21 COMMISSIONER CHMIELOWSKI: Yeah, on a two
22 string.
23 MR. CALLAHAN: Yeah. So on the two string
24 prior to running our upper completion we plan to run a
25 cement bond log or equivalent to evaluate the quality
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1 of cement from the top of the reservoir to our required
2 cement height depth.
3 COMMISSIONER CHMIELOWSKI: Okay. Great. Thank
4 you. Oh, and you're going to talk about fracks later.
5 I -- I see you have plans to fracture these wells, but
6 I recall in the application that fracture stimulation
7 option -- operations may exceed the fracture pressure
8 of the overburden; is that correct?
9 MR. CALLAHAN: Yes, Madeline.....
10 COMMISSIONER CHMIELOWSKI: You're going to talk
11 to that later?
12 MS. WOODARD: Yes.
13 COMMISSIONER CHMIELOWSKI: Okay. Great. Thank
14 you.
15 MADELINE WOODARD
16 previously sworn, called as a witness on behalf of
17 ConocoPhillips Alaska, testified as follows.
18 MS. WOODARD: Hi. I'm Madeline Woodard,
19 completion engineer and I'll be speaking to slide 17,
20 18 and 19. I'll begin with slide 17 on injection
21 containment.
22 On the right side of the slide is a schematic
23 of the 3S24B well that was included in the pilot area
24 previously approved for the Coyote. On the schematic
25 the reservoir perforations that were utilized for a
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1 hydraulic fracture stimulation are shown and the
2 perforations circled in red indicate the perforations
3 in the upper confining zone. These perforations were
4 used to perform a diagnostic fracture injection test or
5 a DFIT to help understand the strength of the upper
6 confining zone. On the left side of the slide are the
7 logs from the 3S24B with the minimum horizontal stress
8 curve on the far right track. The red dots on the far
9 right track indicate measured fracture closure pressure
10 values obtained during fracture diagnostic tests in the
11 upper confining zone in the Coyote reservoir. The
12 fracture closure pressure gradient measured by the DFIT
13 performed at the overburden perforations previously
14 highlighted is six -- 0.67 PSI per foot and .02 PSI per
15 foot higher than the log drive value. The fracture
16 pressure closure gradient of the reservoir is
17 represented by the lower red dot on the far right track
18 and was measured at 0.62 PSI per foot from a remaining
19 frack that was pumped prior to the main fracture
20 treatment in the 3S24B. Currently ConocoPhillips does
21 not have leakoff or formation breakdown pressure --
22 pressures measured in the upper confining zone. Next
23 slide, please.
24 Slide 18 covers information on the fracture
25 geometry. A simulation of the 3S24B well included
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1 tracers to help gather a better understanding of
2 fracture height growth in the Coyote and the results of
3 the tracer log are on the bottom of the slide. The
4 analysis shows there is high confidence of fracture
5 presence over a 95 foot interval from 7,898 foot
6 measured depth to 7,993 foot measured depth indicated
7 by the bright yellow. The orange indicates possible
8 fracture presence with potential to be 147 feet in
9 height. Above the fracture height analysis are the
10 logs from the 3S24B and the fracture geometry created
11 by matching the bottom hole pressure during the
12 simulation using Go for Fracture modeling software.
13 The inputs for the history match were the 3S24B logs
14 calibrated to geomechanical laboratory tests. The
15 color scale on the right side of the fracture image
16 represents the carbon concentrations throughout the
17 fracture scaled from zero to five pounds per square
18 foot. This history match geometry is also compared
19 against the high confidence and possible fracture
20 height analysis where the history match does not show
21 growth into the overburden although the tracer results
22 do show that. However laboratory conductivity testing
23 was completed on the overburden rock and proved there
24 was no remaining conductivity in the upper confining
25 layer due to gel damage from the fracture fluid and
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1 proppant embedment in the rock. Finally the lateral
2 placements for the 3S701A and 3S704 wells in the pilot
3 area previously approved for the Coyote are moved
4 deeper than the perforations in the 3S24B well. This
5 placed the laterals at 100 feet below the top of the
6 Coyote and the image shown on the far right side of the
7 slide illustrates the fracture geometry created at the
8 new lateral landing depth where no overburden growth is
9 observed. This fracture is modeled as 300,000 pounds
10 of 16/20 proppant. A history match was also completed
11 for the 3S701A well no overburden growth was observed
12 either. Next slide.
13 Slide 19 reviews the data that ConocoPhillips
14 has gathered to date. The two charts on the slide are
15 identical and represent a typical pressure trend seen
16 while pumping fluid into formation where the Y axis
17 represents pressure and the X axis represents fluid
18 volume. The left chart illustrates the trend for the
19 upper confining interval or the overburden and the
20 chart on the right illustrates the trend for the Coyote
21 reservoir. The fracture closure pressure or PC for
22 each interval are highlighted with the red and gray
23 dashed lines on the chart. The upper confining
24 interval measured at 0.67 PSI per foot in the Coyote at
25 a lower value of 0.62 PSI per foot. No formation
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1 breakdown pressure or SEP data has been gathered for
2 the upper confining interval, but would be higher than
3 the fracture closure pressure gradient of 0.67 PSI per
4 foot as illustrated by the chart on the left. For the
5 fracture height information reviewed on slide 18 there
6 is risk of fractures in the Coyote -- there is risk the
7 fractures in the Coyote could grow into the upper
8 confining interval during hydraulic fracture
9 stimulation operation, however the most recent history
10 match performed at the deeper lateral placement does
11 not show hydraulic growth into the overburden. If a
12 hydraulic fracture were to grow into the overburden
13 during stimulation geomechanical testing completed in
14 the lab supports that there is no remaining
15 conductivity in the overburden rock due to gel damage
16 from the frack fluid and proppant embedment in the
17 rock. And also injecting at or under the overburden
18 closure pressure would not reopen or extend a fracture
19 in the overburden. ConocoPhillips is requesting an
20 injection pressure of 0.67 PSI per foot with potential
21 to increase this pressure if formation breakdown
22 pressure or early goth (ph) data is obtained in the
23 overlying seal.
24 Any questions on the hydraulic fractures or
25 injection pressure?
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1 COMMISSIONER CHMIELOWSKI: Yeah, just to make
2 sure I heard you correctly the -- if a fracture were
3 created in the overburden you're saying that the gel
4 and materials used in the frack would damage that
5 fracture such that it wouldn't continue to flow fluids
6 through it?
7 MS. WOODARD: Correct.
8 COMMISSIONER CHMIELOWSKI: Yeah. Okay. And so
9 is the .67 like your max injection pressure for just
10 normal operations or during frack, frack operations
11 too?
12 MS. WOODARD: During normal operations.
13 COMMISSIONER CHMIELOWSKI: Okay. So you don't
14 plan to exceed it during the fracture simulation?
15 MS. WOODARD: Yes.
16 COMMISSIONER CHMIELOWSKI: Okay. Do you know
17 about what pressure that would be?
18 MS. WOODARD: I do not know right now, no.
19 COMMISSIONER CHMIELOWSKI: Okay. Okay. I
20 don't have any other questions on this right now.
21 COMMISSIONER WILSON: I'm good. Thanks.
22 COMMISSIONER CHMIELOWSKI: Okay. Thank you.
23 LYNN ALESHIRE
24 previously sworn, called as a witness on behalf of
25 ConocoPhillips Alaska testified as follows.
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1 MS. ALESHIRE: I'm Lynn Aleshire and I will
2 speak to slide 20 and 21.
3 The first slide is about our facility. The map
4 on the left is a map of GK, Greater Kuparuk area
5 drillsite showing the roads and pipelines. Central
6 processing facility 3, CPF3 is starred in green.
7 Coyote wells will be drilled from 3S and 3T which are
8 starred in red and we've already described that. To
9 the right is a sketch of GKA processing and
10 transportation facilities. Current Coyote production
11 from drillsite 3S is commingled is Kuparuk, Marine and
12 West Sac production as it flows through CPF3 for
13 primary separation. CPF3's wet oil is sent to CPF1 and
14 CPF2 for final separation to sales quality oil.
15 Produced water is routed for water injection, produced
16 gas is used for lift gas, lean gas, MI blends or
17 consumed as fuel gas. Future plans under consideration
18 include routing of all drillsite 3S production directly
19 to CPF2 to minimize backout with the Nuna 3T production
20 comes online. This would be the Torok production.
21 Slide 21 addresses injection fluids and
22 compatibility. Primary injection fluids are produced
23 water, seawater and enriched gas and they'll be
24 injected into the reservoir to replace voidage and
25 enhance recovery. Secondary fluids include those that
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1 are used during frack stimulation for reservoir
2 surveillance such as tracers for well work that would
3 include solvents, acids, cements, resins and polymers
4 and for operations there would be scale and corrosion
5 inhibitors and freeze protect fluids. About water
6 compatibility, the connate water in the reservoir does
7 have the potential for barium sulfate scale formation.
8 Produced water injection helps with that risk. Coyote
9 wells will be included in GKA scale inhibition program
10 which includes regular water sampling and scheduled
11 inhibition squeeze treatment.
12 And that's all. Any questions on those?
13 COMMISSIONER CHMIELOWSKI: So you're talking
14 about MI injection at this time, but not necessarily
15 just gas injection, correct?
16 MS. ALESHIRE: It could be either or.
17 COMMISSIONER CHMIELOWSKI: Could be either or.
18 MS. ALESHIRE: Yeah.
19 COMMISSIONER CHMIELOWSKI: Okay. And it sounds
20 like there is some backout at CPF3 currently
21 anticipated in bringing on this production?
22 MS. ALESHIRE: Yeah, it's -- it's the Torok
23 wells are very high water cut so there's some water
24 handling issues and -- and so we're looking at.....
25 COMMISSIONER CHMIELOWSKI: Okay.
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1 MS. ALESHIRE: How best to address that.
2 COMMISSIONER CHMIELOWSKI: Right. Thank you.
3 MR. PERFETTA: Okay?
4 COMMISSIONER CHMIELOWSKI: Go ahead. Thanks.
5 MR. PERFETTA: Thanks, Lynn. This is Patrick
6 Perfetta again. We are now on slide 22. That
7 concludes the prepared presentation materials that
8 ConocoPhillips has. The following slides are simply a
9 cut and paste of the proposed rules from our pool and
10 area injection applications for reference. I was not
11 planning on reading through them unless you'd like me
12 to. At this point we'd be happy to discuss anything
13 specific that you haven't asked about or have any
14 questions with respect to the proposed rules.
15 COMMISSIONER CHMIELOWSKI: Do you have any
16 questions at this time?
17 COMMISSIONER WILSON: No, I'm -- I'm good on
18 the rules.
19 COMMISSIONER CHMIELOWSKI: Okay. I have a
20 question about the drillsite 3S wells in general. I
21 know that which -- how many wells there have been
22 abandoned all the way to the surface, I know there's
23 sort of been a plugging and abandonment campaign. Is
24 that to prepare for this Coyote development?
25 MS. ALESHIRE: I don't know exactly how many we
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1 have abandoned. There are three Kuparuk wells that are
2 remaining that we intend to keep.
3 COMMISSIONER CHMIELOWSKI: Intend to keep as
4 Kuparuk producers?
5 MS. ALESHIRE: Correct.
6 COMMISSIONER CHMIELOWSKI: Okay. And are you
7 able to speak to the results of the perf and wash
8 campaign that Conoco has at 3S, the success of it or
9 how -- you know, if it's planned to be something that
10 Conoco will continue?
11 MR. PERFETTA: Yeah, it has been largely
12 successful in its containment of the Coyote.....
13 COMMISSIONER CHMIELOWSKI: Okay.
14 MR. PERFETTA: .....or the P&A of the Coyote
15 wells in the prev -- I mean, the historic Kuparuk
16 wells.
17 COMMISSIONER CHMIELOWSKI: Yeah. Okay. And
18 are -- are there any more wells that are planned to
19 have a perf and wash cement job?
20 MS. ALESHIRE: There's one Kuparuk well
21 remaining to be abandoned, 308, and it will have a perf
22 wash.
23 COMMISSIONER CHMIELOWSKI: Okay.
24 MS. ALESHIRE: But it's not needed I don't
25 believe until next year.
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 38
1 COMMISSIONER CHMIELOWSKI: Okay. Great. Well,
2 thanks. I'm glad to hear that's going well.
3 I have one clarifying question is all the
4 existing wells in this Coyote development area that
5 Conoco, the state of Alaska and some Native
6 corporations are the only affected owners for all of
7 those and they've all been notified and are involved
8 with this progress?
9 MR. PERFETTA: Yes, that is correct.
10 COMMISSIONER CHMIELOWSKI: Okay. Thanks. Do
11 you have any questions, Commissioner, are you ready for
12 recess?
13 COMMISSIONER WILSON: I'm ready for recess.
14 COMMISSIONER CHMIELOWSKI: Okay. Great. All
15 right. Well, we'll take a recess. I always like to
16 say it'll be short, but we tend -- end up taking a
17 little bit longer. So it's 10:56, let's try for 10 or
18 11:25, does that work for everybody?
19 (No comments)
20 COMMISSIONER CHMIELOWSKI: All right. So we'll
21 see you back here at 11:25.
22 Thank you.
23 (Off record - 10:56 a.m.)
24 (On record - 11:25 a.m.)
25 COMMISSIONER CHMIELOWSKI: All right. Good
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 39
1 morning, everyone. We're back on the record, it's
2 11:25. And we -- thank you for that time. We have a
3 few questions we'd like to ask as follow-up and
4 Commissioner Wilson will start.
5 COMMISSIONER WILSON: Yes. We'd had a little
6 bit of discussion about fracture propagation into the
7 upper confining interval and I suppose this is more of
8 a geology question though. I was just curious if you
9 could describe the stratigraphy a little bit between
10 the top of the CV and your surface casing in a typical
11 well?
12 MR. PERFETTA: Yeah. So the -- there is a --
13 immediately above the Coyote there's the CV formation
14 which is several hundred feet thick that transitions
15 into kind of distill -- also distill tulip slope type
16 deposits in the overlying set of clinoforms of the
17 lower Schrader. And then it's predominantly a shale
18 prone section, very thin siltstones are present in that
19 interval, minor sands, but it's predominantly shale
20 prone.
21 COMMISSIONER WILSON: And in the ConocoPhillips
22 terminology what would be your markers that you use
23 there?
24 MR. PERFETTA: We use several markers. There's
25 -- coming out of surface casing the first one we
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 40
1 encounter is the -- the C80 which associated with that
2 is a thin sandstone called the Campanian sand. It's
3 typically 10 to 20 feet thick in the 3S area, non-
4 hydrocarbon bearing. And then below that we drill a
5 shale section until we hit another shale marker called
6 the C50 and then further on a marker called the C35.
7 COMMISSIONER WILSON: Thank you.
8 COMMISSIONER CHMIELOWSKI: So I'll just follow-
9 up a little bit on that. You know, we as a Commission
10 have been looking at shallow hydrocarbon zones and
11 ensuring they're properly cemented. So what you're
12 saying is there are no known shallow hydrocarbon zones
13 below the surface casing shoe to the cement top for
14 your formation, correct?
15 MR. PERFETTA: That is correct.
16 COMMISSIONER CHMIELOWSKI: Okay. And so what
17 logs has Conoco run or plans to run to ensure that
18 there isn't one there, you don't encounter one?
19 MR. PERFETTA: We have run full log suites of
20 gamma ray resistivity and density neutron along with
21 mud logging on multiple wells in multiple directions
22 from the 3S pad and have done that at 3T as well.
23 COMMISSIONER CHMIELOWSKI: Great. And is
24 Conoco using the similar criteria for evaluation that
25 was used like at CD1 with the halo, I think those
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 41
1 criterion were updated after that; is that correct?
2 MR. PERFETTA: Yes, that is correct. We use
3 that log model to QC the.....
4 COMMISSIONER CHMIELOWSKI: Okay.
5 MR. PERFETTA: .....the overburden section.
6 COMMISSIONER CHMIELOWSKI: Right. Thank you.
7 And I have a couple -- a question about reservoir
8 volumes and recovery. So I was looking at slide 14 and
9 it has, you know, the estimated oil in place for the
10 combined development area which I understand is what
11 can be reached by the planned wells, right, and then
12 you have the oil in place for the total pool area which
13 is what you've outlined as your potential pool, right,
14 so -- so there's a difference of it looks like quite a
15 bit of oil there. Has Conoco considered, you know,
16 getting a different rig like to drill longer wells or
17 an additional pad or what does Conoco think about
18 leaving that oil in place?
19 MR. PERFETTA: So I can't speak to the -- to
20 the rig decision for a longer rig, Mike might be able
21 to.....
22 COMMISSIONER CHMIELOWSKI: Uh-huh.
23 MR. PERFETTA: .....answer that question
24 better. But part of the appraisal strategy is moving
25 to the northwest and to the northeast to -- to find the
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 42
1 productivity of different regions of the reservoir and
2 there could be some additional expansion at a later
3 date from 3T specifically for the northwest area
4 highlighted in pink on the slide.
5 COMMISSIONER CHMIELOWSKI: Okay. So you think
6 the potential is more to the north versus to the south?
7 MR. PERFETTA: So whenever you say south do you
8 mean beyond the toes of those (indiscernible -
9 simultaneous speech)?
10 COMMISSIONER CHMIELOWSKI: Yes, that's what I
11 mean because that's -- it looks like a thicker net pay
12 down there. So.....
13 MR. PERFETTA: Yeah, we believe there is
14 potential in that area, but it's.....
15 COMMISSIONER CHMIELOWSKI: Okay.
16 MR. PERFETTA: .....a challenge from a.....
17 COMMISSIONER CHMIELOWSKI: Right.
18 MR. PERFETTA: .....drilling perspective.
19 COMMISSIONER CHMIELOWSKI: Okay.
20 MR. CALLAHAN: Yeah, and on the -- the rig part
21 of your question there. The limit isn't really our --
22 our rig it's the -- the torque and drag and pipe
23 buckling when trying to run casing. So.....
24 COMMISSIONER CHMIELOWSKI: Right.
25 MR. CALLAHAN: .....a bigger rig wouldn't
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 43
1 necessarily alleviate that issue.
2 COMMISSIONER CHMIELOWSKI: Okay. Just a
3 shallow reservoir (indiscernible - simultaneous
4 speech)?
5 MR. CALLAHAN: Yeah, we're at 4,000 to 4,200
6 TVD and 25,000 measured depth are already well into
7 the.....
8 COMMISSIONER CHMIELOWSKI: Right.
9 MR. CALLAHAN: .....extended reach zone.
10 COMMISSIONER CHMIELOWSKI: Okay. Thank you. A
11 question about a frack and -- and it's possible you
12 still -- you still don't know, maybe I had asked the
13 question. You know, you talked about the overburden
14 posing pressure at .67 and that that -- when you do
15 your hydraulic fracturing though you would exceed that.
16 So I asked what that pressure would be, but maybe you
17 know the gradient for the frack, you know, pressure,
18 the PSI per foot, you know, I'm just curious how high
19 you would go under fraction -- fracturing operations?
20 Am I making sense?
21 MS. ALESHIRE: No, I'm not sure I understand
22 the question.
23 COMMISSIONER CHMIELOWSKI: Okay. So if -- if
24 the fracture pressure or the closing pressure of the
25 overburden is .67 PSI per foot and you say you'll go
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 44
1 over that while you're fracturing the reservoir.....
2 MS. ALESHIRE: Uh-huh.
3 COMMISSIONER CHMIELOWSKI: .....what would the
4 -- what would that pressure be or that gradient be
5 during the fracturing operation, do you know?
6 MS. ALESHIRE: I don't know what the gradient
7 would be, I know.....
8 COMMISSIONER CHMIELOWSKI: Okay.
9 MS. ALESHIRE: .....I know that we build higher
10 than the 250 PSI net pressure during the fracture
11 stimulation.....
12 COMMISSIONER CHMIELOWSKI: Okay.
13 MS. ALESHIRE: .....which is that difference
14 between the .67 and .62 PSI per foot.
15 COMMISSIONER CHMIELOWSKI: Okay. Do you know
16 about how far those fractures extended into the
17 overburden?
18 MS. ALESHIRE: Our results from the log
19 analysis performed on the 3S24B was 34 feet into the
20 overburden.
21 COMMISSIONER CHMIELOWSKI: Thirty-four feet.
22 Okay.
23 MS. ALESHIRE: Yes.
24 COMMISSIONER CHMIELOWSKI: Thank you. And then
25 a question about injection fluids. Under primary
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 45
1 injection fluids Conoco states enriched hydrocarbon
2 gas. Is that fully miscible gas or is it a rich gas?
3 MS. ALESHIRE: I don't know that we have
4 decided that yet.
5 COMMISSIONER CHMIELOWSKI: You haven't decided?
6 MS. ALESHIRE: Yes.
7 COMMISSIONER CHMIELOWSKI: Okay. And I think
8 that's all I have. Do you have anything else,
9 Commissioner Wilson?
10 COMMISSIONER WILSON: No, nothing additional.
11 COMMISSIONER CHMIELOWSKI: Okay. So now we're
12 going to go into the opportunity for public comment
13 part of the hearing. So I would like to offer any
14 member of the public the opportunity to testify or
15 provide comments. We have received written comments
16 from one party, that's Santos on this matter. Is there
17 anybody in the room who would like to provide testimony
18 or public comment?
19 (No comments)
20 COMMISSIONER CHMIELOWSKI: All right. Seeing
21 nobody. So I will switch over, is there anyone on the
22 phone or on Teams who wishes to comment so I'll switch
23 over to that? I'll just say that on Teams the code to
24 unmute is star six. If anyone has technical
25 difficulties Samantha Coldiron can be reached at 907-
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 46
1 793-1223 or you can call the main AOGCC number at 907-
2 279-1433. Again the code to unmute is star six. And
3 we will pause for 60 seconds to allow people time to
4 unmute.
5 (No comments)
6 COMMISSIONER CHMIELOWSKI: All right. Sam,
7 have you received any information from anybody online
8 or on the phone?
9 MS. COLDIRON: No.
10 COMMISSIONER CHMIELOWSKI: Okay. All right.
11 Any other comments from you, Commissioner?
12 COMMISSIONER WILSON: I just wanted to thank
13 ConocoPhillips for two well organized and informative
14 application packages and then also for the informative
15 presentation and discussion here today and for getting
16 the presentation to us in a timely manner also so we
17 had an opportunity to see it ahead of this
18 presentation.
19 Thank you.
20 COMMISSIONER CHMIELOWSKI: Yes, I concur.
21 Thank you very much. The time is 11:34 and this
22 hearing is adjourned.
23 Thank you.
24 (Hearing adjourned - 11:34 a.m.)
25 (END OF PROCEEDINGS)
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
DOCKET No. CO-24-009 AIO-24-019
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 47
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 02 through 47 are a true,
4 accurate, and complete transcript of proceedings in
5 Docket No.: CO-24-009 and AIO-24-019, transcribed under
6 my direction from a copy of an electronic sound
7 recording to the best of our knowledge and ability.
8
9
_______________ _______________________________
10 DATE SALENA A. HILE, (Transcriber)
11
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2
Notice of Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RE: 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.
The AOGCC prescribes Pool Rules that govern development of oil and gas pools when a
modification of a statewide regulation is needed to facilitate development of the pool. Some
common rules are modification of the permit to drill application process to streamline applications
and modify the data collection requirements when additional data would not add to the
understanding of the geology in the project area. Additionally, 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 CPAI. 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 scheduled for August 20, 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: 538 807 168#. 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.
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 the conclusion of the August 20, 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 13, 2024.
Jessie L. Chmielowski
Commissioner
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.07.12
13:39:09 -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
__________________________________
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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
______________________________________
07/14/2024
and that such newspaper was regularly distrib-
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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 #: W0046984 Cost: $340.94
Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION
RE: 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. The AOGCC prescribes Pool Rules that govern development of
oil and gas pools when a modification of a statewide regulation is needed to facilitate development of the pool. Some common rules are modification of the permit to drill application process
to streamline applications and modify the data collection
requirements when additional data would not add to the understanding of the geology in the project area. Additionally, 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 CPAI. 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 scheduled for August
20, 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: 538 807 168#.
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. 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 the conclusion of the August 20, 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 13, 2024.
Jessie L. ChmielowskiCommissioner
Pub: July 14, 2024
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
______________________________________2024-07-15
2028-07-14
Document Ref: VHJBB-XS8AX-RP9JA-G9NRM Page 5 of 28
By Samantha Coldiron at 10:38 am, Jun 20, 2024
Application to the Alaska Oil and Gas Conservation Commission
(AOGCC) for a Coyote Area Injection Order
Kuparuk River Unit
June 20, 2024
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
2
Contents
Section A Introduction .................................................................................................................................. 3
Section B (20 AAC 25.402(c)(1)) Plot of Project Area ................................................................................... 5
Section C (20 AAC 25.402(c)(2)) Operators and Surface Owners ................................................................. 6
Section D (20 AAC 25.402 (c)(3)) Affidavit to Surface Owners ..................................................................... 7
Section E (20 AAC 25.402(c)(4)) Description of the Proposed Operation .................................................... 8
Section F (20 AAC 25.402(c)(5)) Pool Description ........................................................................................ 8
Section G (20 AAC 25.402(c)(6)) Formation Geology ................................................................................... 9
Section H (20 AAC 25.402(c)(7)) Logs of the Injection Wells ...................................................................... 14
Section I (20 AAC 25.402(c)(8)) Mechanical Integrity of Injection Wells.................................................... 15
Section J (20 AAC 25.402(c)(9)) Injection Fluid Analysis and Injection Rates ............................................. 18
Section K (20AAC 25.402(c)(10)) Injection Pressures ................................................................................. 18
Section L (20AAC 25.402(c)(11)) Fracture Information .............................................................................. 19
Section M (20AAC 25.402(c)(12)) Quality of Formation Water .................................................................. 21
Section N (20AAC 25.402(c)(13)) Aquifer Exemption ................................................................................. 22
Section O (20AAC 25.402(c)(14)) Hydrocarbon Recovery .......................................................................... 23
Section P (20AAC 25.402(c)(15)) Mechanical Condition of Wells Within ¼ Mile of Injection .................... 24
Section Q Proposed Rules ........................................................................................................................... 26
Rule 1: Authorized Injection Strata for Enhanced Recovery .................................................................. 27
Rule 2: Well Construction ...................................................................................................................... 27
Rule 3: Authorized Fluids for Injection or Enhanced Recovery .............................................................. 27
Rule 4: Authorized Injection Pressure for Enhanced Recovery ............................................................. 27
Rule 5: Monitoring Tubing-Casing Annulus Pressure .............................................................................. 27
Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity ................................................ 27
Rule 7: Well Integrity and Confinement ................................................................................................. 28
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
3
Section A Introduction
ConocoPhillips Alaska, Inc. (CPAI), as operator of the Kuparuk River Unit (KRU) submits this application to
the Alaska Oil and Gas Conservation Commission (AOGCC) for establishment of an Area Injection Order
(AIO) for the Coyote Oil Pool. CPAI is concurrently seeking a Conservation Order by the Commission
regarding the formation of the Coyote Oil Pool and its rules under a separate application.
The Commission previously approved a Coyote Enhanced Recovery Injection Order (ERIO 8) in January of
2023. Since that time, CPAI has drilled and begun injection operations in a horizontal producer/injector
pilot well pair (3S-701A injector/3S-704 producer) (Figure 1). This pilot has proved injectivity and pressure
support from the horizontal injector to the horizontal producer within the Coyote reservoir.
Future development of the Coyote Oil Pool will be completed in a phased approach, to continue to de-
risk different portions of the field. Wells will be drilled from both KRU drillsite 3S, and 3T. The planned
development concept is that of a horizontal line-drive waterflood for enhanced recovery, with both
producers and injectors being fracture stimulated. Water alternating gas injection may be used in the
future to further enhance recovery from the Coyote Oil Pool.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
4
Figure 1: Reference Map
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
5
Section B (20 AAC 25.402(c)(1)) Plot of Project Area
Figure 2 shows all wells as of May 9, 2024 within the proposed injection area.
Figure 2: Plat of All Wells Within the Proposed Coyote Area of Injection
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
6
Section C (20 AAC 25.402(c)(2)) Operators and Surface Owners
Operators:
ConocoPhillips Alaska, Inc. II Oil Search (Alaska), LLC
700 G Street, Suite ATO 1226 900 E. Benson Blvd.
Anchorage, Alaska 99510 Anchorage, Alaska 99508
Attn: Land Manager Attn: Tim Jones
Eni US Operating Co. Inc. Finnex, LLC
3700 Centerpoint Drive, Suite 500 301 Calista Ct., Suite 103
Anchorage, Alaska 99503 Anchorage, Alaska 99518
Attn: Angie Wiese Attn: Dr. Harry Bockmeulen
Surface Owners:
State of Alaska
Department of Natural Resources
Division of Oil and Gas
550 West 7th Ave., Suite 1100
Anchorage, Alaska 99501
Attn: Derek Nottingham, Director
AKFF 085283 – Gertrude Ahsogeak (Deceased)
*AKFF 085536 – Ahsoogeak Woodrow (Deceased)
AKFF 085282 – Horace K. Ahsogeak
AKFF 014646 – Johnny K. Ahtuangaruak
*AKFF 085603 – Beulah E. Williams
AKFF 011952 – Benjamin Tukle (Deceased)
AKFF 000128 – Martha Magdalene Helmericks
Bureau of Indian Affairs
3601 C Street, Suite 1258
Anchorage, Alaska 99503
State of Alaska
Department of Natural Resources
Division of Mining, Land and Water
550 West 7th Ave., Suite 1050A
Anchorage, Alaska 99501
Attn: Christianna Colles, Director
*ADNR-DMLW is “Party-in-Interest” to AKFF 085536 and AKFF 085603
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
7
Section D (20 AAC 25.402 (c)(3)) Affidavit to Surface Owners
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.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
8
Section E (20 AAC 25.402(c)(4)) Description of the Proposed Operation
This application to the AOGCC seeks authorization for area injection into the Coyote Oil Pool.
The Coyote Oil Pool will be developed from existing KRU drill sites 3S and 3T which are currently connected
to KRU Central Processing Facility 3 (CPF-3). An estimated 20 horizontal multi-staged fracture stimulated
producers and 20 horizontal multi-staged fracture stimulated injectors may be drilled to develop the
Coyote reservoir.
The base development plan will employ a horizontal well line drive pattern waterflood with the possibility
of employing immiscible water alternating gas (IWAG) to enhance recovery from the reservoir. Due to the
thinly bedded nature of the reservoir all the wells (including injectors) will be hydraulically fracture
stimulated to enhance productivity and improve vertical sweep.
Wells will be oriented northwest to southeast to generally align with the maximum principal stress
direction to improve waterflood performance and will range in length from ~6,000’ to ~12,000’ within the
reservoir. Wells will be arranged end to end to form alternating rows of injectors and producers in a line-
drive flood pattern. Studies suggest a 1,300’ inter-well spacing is optimal assuming modest secondary
response. This is slightly closer than the spacing at which the initial 3S-701A/3S-704 horizontal well pair
was drilled.
Injection into the initial Coyote injection well, 3S-701A, has shown positive results. The well has
consistently injected greater than 4000bbls/day seawater, and a pressure response has been noticed in
the offset 3S-704 horizontal producer.
Section F (20 AAC 25.402(c)(5)) Pool Description
CPAI proposes that the Coyote Oil Pool be defined as the accumulation of hydrocarbons common to and
correlating with the interval between the measured depths of 4,270’ and 5,115’ MD (-4,038’ and -4,720’
TVDSS respectively) in the Palm 1 well (Figure 3). Location of the Palm 1 is shown on the map in Figure 4
and Figure 5 (yellow star), with bottom hole location immediately west of drillsite 3S.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
9
Figure 3: Type log, Palm 1 (UWI: 501032036100) showing the Coyote reservoir interval, upper
confining zone, and lower confining zone
Section G (20 AAC 25.402(c)(6)) Formation Geology
Structure and Trap Configuration
The Coyote reservoir is contained in a combination structural-stratigraphic trap. The interval pinches out
to the west-northwest, shales-out to the east-southeast, dips below a potential oil-water-contact (~-
4,260’ SSTVD) to the north-northeast and narrows & thins to the south-southwest where it also dips below
the same presumed oil-water-contact south of CPAI’s acreage. The top Coyote structure is very low relief
within the development area, with structural dips averaging ~1 degree or less (Figure 4). The exception to
this is where the interval plunges basin-ward at the ultimate Coyote shelf-margin. Very small four-way dip
closures are present at the top Coyote which harbor thin gas caps. Very limited faulting is present at the
Coyote reservoir level, as seen on the structure map in Figure 4.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
10
Seals
Confining intervals shown in Figure 3, are as follows:
Upper Confining Interval
This interval is represented by distal toe of slope (deep marine) claystone with thin siltstone beds of the
Cretaceous Seabee Formation. This interval is present in thicknesses more than 350’ TVD across the area.
Lower Confining Interval
The lower confining interval of the proposed pool comprises slope to basin floor mudstones of the Torok
formation, which are present in thicknesses greater than 300’ TVD across the area. This same confining
zone forms the upper confining interval of the Kuparuk River Unit Torok Oil Pool, as approved by the
AOGCC in Orders AIO 39 and AIO 39A, as shown in Figure 3.
Stratigraphy and Sedimentology
The gross Coyote trend is a generally west to east progradational system that is elongated in a northeast
to southwest direction (Figure 5). The northern portion of the trend is broader in the stratigraphic dip
direction (west to east) and narrows to the south-southwest. The system can be divided into two broadly
defined regions. A western area that is relatively thin and resides on top of a paleo-shelf and an eastern
area that is expanded outboard of the paleo-shelf margin (gray polygon in Figure 5).
The gross environment of deposition for the Coyote interval is delta-front to distal delta-front. The best
reservoir quality within the gross Coyote package is located at the top. There are general trends of
decreasing net to gross and grain size with depth that cause a degradation in reservoir quality. The
reservoir is thinly bedded throughout. When combined with the presumed oil-water-contact and
measured/modeled fracture geometry, the primary target interval of the gross Coyote package is the
upper ~200’ of the interval. Depositional dip and depositional strike well log cross-sections are included
in Figure 6 and Figure 7 for reference.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Figure 4: Top Coyote depth structure map. Top Coyote penetrations marked by red x's.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Figure 5: Coyote net pay
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Figure 6: Depositional dip well log cross-section (northwest to southeast)
Figure 7: Depositional strike well log cross-section (southwest to northeast)
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Section H (20 AAC 25.402(c)(7)) Logs of the Injection Wells
Upon drilling of the injection well(s), logs will be sent to the Commission in accordance with applicable
AOGCC regulations.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
15
Section I (20 AAC 25.402(c)(8)) Mechanical Integrity of Injection Wells
See Figure 8 and Figure 9 below for proposed injector schematics.
The injection well design is like other injection wells in the KRU. Injectors will utilize either a two or three
string design as shown in Figure 8 and Figure 9.
Surface casing set below the base of the West Sak in the Colville Group will be cemented back to surface.
Within the area, the base of permafrost is interpreted to be between -1,500’ and -1,700’ SSTVD. In the 3-
string wells, the intermediate hole will be drilled to a casing point within the upper Coyote interval at
approximately 85 degrees inclination. In the
2-string wells, the crossover from 7-5/8” to 4-1/2” casing will be at approximately the same depth. In
both designs, cement will be brought to a minimum of 500’ MD/250’ TVD above the top of the Coyote
interval.
The Coyote interval will be drilled horizontally and solid liner containing fracture sleeves will be cemented
in place. In the 3-string wells, a liner top hanger and packer will be set no greater than 200’ inside the
intermediate casing shoe.
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, CPAI requests the packer/isolation equipment
depth may be located above 200’ 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 100’ measured depth above the planned packer depth. Since the Coyote
Oil Pool well injectors are 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’
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 AAC
25.412(c). Drilling and completion operations will be performed in accordance with applicable AOGCC
regulations. 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.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
16
Figure 8: Proposed 2-string Injection Well Schematic
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
17
Figure 9: Proposed 3-string Injection Well Schematic
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Section J (20 AAC 25.402(c)(9)) Injection Fluid Analysis and Injection Rates
Coyote injection will occur at KRU 3S and 3T pads, which are connected to the KRU in-field pipeline
network. This in-field network can transport only one type of water, either produced water or seawater,
to each drill site. Water service for each drillsite is selected to optimize the production potential of the
entire unit. 3S is currently on produced water service with the intent to remain so long-term, but this
could change in the future. The ERIO pilot also confirmed compatibility with seawater injection. Injection
rates may exceed 15,000 bbl/d for each injection well drilled, depending on reservoir quality. A gas
injection rate schedule will be dependent on post-drill analysis of pore volume and voidage replacement.
Water and gas injection rates will ultimately be constrained by bottom hole pressure and overburden
strength. Primary injection fluids include:
• Produced water and gas from within the KRU; and
• Beaufort seawater sourced from the KRU seawater treatment plant
• Gas and NGLs imported from the Greater Prudhoe Area
Other fluids may also be injected for reservoir stimulation, reservoir performance evaluation, freeze
protection, chemical inhibition, or to otherwise ensure efficient and safe operation of the Coyote injection
well(s). These fluids are not planned for continuous injection, or as a means for enhanced recovery. The
volumes of these other fluids are not expected to hinder the recovery efficiency or performance. These
other fluids include:
• Fluids used during hydraulic stimulation
• Tracer survey fluids to monitor reservoir performance
• Fluids used to improve near wellbore injectivity (acids, solvents, etc.)
• Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.)
• Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.)
• Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Barium sulfate scale formation in production wells, as has been experienced to various degrees in KRU
pools, is possible due to the mixing of seawater (containing sulfate) and formation water (containing
barium). Coyote wells will be included in the GKA scale inhibition treatment program.
Section K (20AAC 25.402(c)(10)) Injection Pressures
The sand-face injection pressure of the injection well(s) will be maintained below the estimated strength
of the upper confining zone.
At the time of application submittal for a temporary injection order, analysis of available data in the
confining zone yielded a fracture closure pressure gradient of ~0.65 psi/ft, based on log interpretation of
rock strength. A subsequent DFIT in the confining interval resulted in a measured fracture closure
pressure gradient of 0.67 psi/ft.
The pilot project targeted an injection gradient of 0.61 psi/ft, based on a demonstrated fracture closure
pressure gradient in the 3S-24B of 0.62 psi/ft within the Coyote reservoir interval. Subsequent testing
along the 3S-701A and 3S-704 laterals demonstrates a gradient between 0.62-0.65 psi/ft. To optimize
injectivity into the Coyote formation, without exceeding the confining zone fracture closure pressure, CPAI
proposes an upper injection limit of 0.67 psi/ft.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
19
At -4,112’ TVDSS the maximum injection pressure will be 2,755 psi (0.67 psi/ft). The sand-face injection
pressure of each injector will be set based on the realized depth of the reservoir.
Section L (20AAC 25.402(c)(11)) Fracture Information
In the area of the proposed Coyote injection pilot, the Coyote reservoir is overlain by distal toe of slope
claystone with thin siltstone beds of the Cretaceous Seabee formation in thicknesses greater than 350’
TVD. The underlying confining zone beneath the Coyote reservoir consists of slope mudstones associated
with the Torok formation in thicknesses greater than 300’ TVD. The lower confining zone forms the upper
confining zone of the KRU, Torok Oil Pool (Figure 3).
The calculated fracture closure gradient for the overlying Seabee Formation is based on rock strength
curves calibrated to data collected during the stimulation of the Coyote reservoir and a diagnostic
fracturing injection test (DFIT) performed in the overlying zone in the 3S-24B well. This DFIT resulted in a
measured fracture closure pressure gradient of 0.67 psi/ft.
Fractures will not propagate within the Coyote Reservoir with injection pressures at or below 0.62 psi/ft
(minimum measured fracture closure pressure gradient of the reservoir) and based on the DFIT data will
not propagate into the confining interval if injection pressures are at or below 0.67psi/ft (fracture closure
pressure gradient of the overlying seal). Currently, ConocoPhillips does not have formation breakdown
pressure or leak off data of the overlying seal. Using the fracture closure pressure as a maximum injection
pressure limit is a conservative approach as the fracture closure pressure is lower than the breakdown
and leak off pressures. If these data are to be acquired in the future, a request to increase maximum
injection pressure will be submitted.
The anticipated water injection rate for this project will be up to 15,000 BWPD per injection well. Injection
into the Coyote Oil Pool will occur at or below fracture closure pressure gradient of the overlying confining
shales (0.67 psi/ft). At 4,150ft TVDSS the maximum injection pressure will be 2,780 psi (0.67 psi/ft
gradient).
CPAI has verified that the 0.67 psi/ft injection gradient will not initiate or propagate fractures through the
upper or lower confining strata by conducting containment analysis via a DFIT in the overlying confining
zone. In addition, it was verified that any fracture that does grow into the overlying confining zone does
not have any resultant conductivity after closure via conductivity testing using overburden core. Finally, a
pressure history match was completed for 3S-24B using frac modeling software to verify fracture growth
behavior. The inputs were based on the 3S-24B well logs that were calibrated with data from geo-
mechanical laboratory tests. The frac modeling software used was Grid Oriented Hydraulic Fracture
Extension Replicator (“GOHFER”), due to its reliability and common use within ConocoPhillips 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. Figure 10 shows results of the 3S-24B history match while
Figure 11 shows the fracture geometry after moving the landing point deeper to where the laterals will
be placed for the future development.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Figure 10: 3S-24B Stimulation Pressure History Match
Figure 11: Updated Landing Depth Stimulation Geometry
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Section M (20AAC 25.402(c)(12)) Quality of Formation Water
A small amount of sustained formation water (~11% sustained water cut) was produced from the 3S-24B
production test from the Coyote reservoir interval. Composition of this water, from laboratory analysis of
a sample taken on January 28, 2022, is included in Table 1. The TDS of this sample was 21,185 mg/l, which
is above the 10,000 mg/l cut-off for freshwater.
Table 1: 3S-24B Produced Water Composition
Analysis Name Value Unit
Aluminum - mg/l
Boron 26.2 mg/l
Barium 1.3 mg/l
Bicarbonate 2,409.8 mg/l
Calcium 99.4 mg/l
Carbonate 13.0 mg/l
Chloride 10,081.1 mg/l
Conductivity 17,850.0 uS/cm
Iron 0.1 mg/l
Potassium 48.2 mg/l
Lithium 2.2 mg/l
Magnesium 91.7 mg/l
Manganese 0.2 mg/l
Sodium 8,246.5 mg/l
Phosphorus 0.3 mg/l
PH 8.3
Silicon 6.1 mg/l
Sulfate 151.5 mg/l
Specific Gravity @ 60 degrees F 1.0
Strontium 7.5 mg/l
Zinc - mg/l
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Section N (20AAC 25.402(c)(13)) Aquifer Exemption
The EPA has adopted an aquifer exemption for the “portions of aquifers on the North Slope described by
a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field” 40 C.F.R.
147.102(b)(3). The commission has adopted that exemption by reference 20 AAC 25.44(c). The proposed
Coyote area for injection is within the KRU and within the scope of the aquifer exemption.
One lease proposed for inclusion in this ERIO application is ADL 392374, depicted in Figure 1. This lease is
not presently within and part of the KRU. Historically, the lands were within the KRU in 1984, when the
EPA adopted the aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer
exemption.
An aquifer exemption is not required for injection into the proposed Coyote Oil Pool as it exceeds the
10,000 mg/l cut-off for freshwater.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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Section O (20AAC 25.402(c)(14)) Hydrocarbon Recovery
Fluid quality requires adoption of a secondary recovery mechanism to obtain an economic production
profile. Water injection has been the main improved recovery process for the KRU to date and is also
planned for the proposed Coyote Oil Pool. This waterflood technique has been widely used across the
North Slope with consistent success.
CPAI estimates that primary recovery will recover approximately 5% of the OOIP and that waterflood
recovery will range from 15-25% incremental recovery of OOIP, yielding a total recovery after waterflood
of 20-30%. Gas injection, whether miscible or immiscible, is being evaluated to estimate the incremental
recovery in the Coyote Oil Pool. Resource recovery for floods is heavily dependent on injection
throughput, waterflood recovery efficiency, and gas injection recovery efficiency.
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
24
Section P (20AAC 25.402(c)(15)) Mechanical Condition of Wells Within ¼
Mile of Injection
Table 2 below shows the wells within the ¼ mile radius of the proposed area. Use Figure 2 above for
referenced well locations. Figure 2
Table 2: Wells Within 1/4 Mile Radius of the Proposed Area
Well Name Well Type Status Mech Integrity Notes
3G-27 Injector Produced Water ACTIVE No Issues
3G-28 Oil Producer ACTIVE No Issues
3H-25 Plugged and Abandoned PA No Issues
3H-25A Suspended SUSP No Issues Suspended since 2009,
suspension renewal
granted 2020.
3H-25APB1 Plugged and Abandoned PA No Issues
3H-25APB2 Plugged and Abandoned PA No Issues
3H-28 Plugged and Abandoned PA No Issues
3H-28A Oil Producer ACTIVE No Issues
3H-32 Oil Producer ACTIVE No Issues
3H-32PB1 Plugged and Abandoned PA No Issues
3H-36 Oil Producer ACTIVE No Issues
3S-03 Suspended SUSP No Issues Well to be P&A’d by
2025
3S-06 Plugged and Abandoned PA No Issues
3S-06A Plugged and Abandoned PA No Issues
3S-07 Oil Producer ACTIVE No Issues
3S-08 Plugged and Abandoned PA No Issues
3S-08A Plugged and Abandoned PA No Issues
3S-08B Plugged and Abandoned PA No Issues
3S-08C Oil Producer ACTIVE No Issues
3S-08CL1 Oil Producer ACTIVE No Issues
3S-08CL1PB1 Plugged and Abandoned PA No Issues
3S-09 Water Injector ACTIVE Waivered well TxIA communication on
gas – water injection
only
3S-10 Plugged and Abandoned PA No Issues
3S-14 Plugged and Abandoned PA No Issues
3S-15 Plugged and Abandoned PA No Issues
3S-16 Injector Miscible Water
Alternating Gas
ACTIVE No Issues
3S-17 Plugged and Abandoned PA No Issues
3S-17A Plugged and Abandoned PA No Issues
3S-18 Plugged and Abandoned PA No Issues
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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3S-19 Suspended SUSP No Issues To be P&A’d by 2025
3S-21 Plugged and Abandoned PA No Issues
3S-22 Plugged and Abandoned PA No Issues
3S-23 Plugged and Abandoned PA No Issues
3S-23A Suspended SUSP No Issues To be P&A’d by 2025
3S-24 Plugged and Abandoned PA No Issues
3S-24A Plugged and Abandoned PA No Issues
3S-24B Plugged and Abandoned PA No Issues
3S-26 Plugged and Abandoned PA No Issues
3S-606 Injector ACTIVE No Issues
3S-610 Oil Producer ACTIVE No Issues
3S-611 Oil Producer ACTIVE No Issues
3S-612 Injector Miscible Water
Alternating Gas
ACTIVE No Issues
3S-613 Injector Produced Water ACTIVE No Issues
3S-615 Oil Producer ACTIVE No Issues Failed ESP, pending
work to fish stuck ESP
motor and replace.
Currently on gas lift
3S-617 Oil Producer ACTIVE No Issues
3S-620 Oil Producer ACTIVE No Issues
3S-624 Oil Producer ACTIVE No Issues
3S-625 Injector Produced Water ACTIVE No Issues
3S-626 Injector ACTIVE No Issues
3S-701 Plugged and Abandoned PA No Issues
3S-701A Injector Produced Water ACTIVE No Issues First Coyote injector
3S-704 Oil Producer ACTIVE No Issues First horizontal Coyote
producer
3W-07 Plugged and Abandoned PA No Issues
COLV DELTA
2
Plugged and Abandoned PA No Issues
MORAINE 1 Plugged and Abandoned PA No Issues
NDST-02 Suspended SUSP Collapsed
tubing. No
known issues in
surface/int
casing
To be P&A’d by 2025.
RWO planned to pull
damaged tubing
05/2024
NDST-02PB1 Plugged and Abandoned PA No Issues
NUNA 1 Suspended SUSP No Issues To be P&A’d by 2025
NUNA 1PB1 Plugged and Abandoned PA No Issues
ODSK-41 Oil Producer ACTIVE No Issues
ODSN-17 Oil Producer ACTIVE No Issues
ODSN-17L1 Oil Producer ACTIVE No Issues
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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ODST-47 Oil Producer SUSP No Issues
PALM 1 Plugged and Abandoned PA No Issues
3H-18 Injector Produced Water ACTIVE No Issues
3H-16 Plugged and Abandoned PA No Issues
3H-16A Oil Producer ACTIVE IAxOA
communication
Minor leak, currently
monitoring and bleed
less than twice per
week
3H-16APB1 Plugged and Abandoned PA No Issues
3H-35 Injector Miscible Water
Alternating Gas
ACTIVE No Issues
ODSK-41PB1 Plugged and Abandoned PA No Issues
ODSN-42B Well ACTIVE No Issues
Section Q Proposed Rules
The rules set forth apply to the following area referred to in this order:
Township, Range Sections
T12N, R07E Sections 1 – 3, 10 – 15, 22 – 26, 35 – 36: All
Sections 9, 16, 21: E/2
T12N, R08E
Sections 4 – 9, 16 – 20, 30: All
Sections 3, 10: W/2
Sections 15, 31: NW/4
Sections 21, 29: N/2, SW/4
T13N, R07E Sections 22 – 27, 34 – 36: All
Sections 28, 33: E/2
T13N, R08E
Sections 19, 30 – 32: All
Section 20: SW/4
Section 29: S/2, NW/4
Section 33: W/2
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
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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 Coyote Oil Pool, which is defined as the
accumulation of oil and gas common to and correlating with the interval within the Palm 1 well between
the measured depths of 4,270’ MD and 5,115’ MD (-4,038’ TVDSS and -4,720’ 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 more than 200’ measured depth 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 100’ measured depth above the planned packer depth.
Rule 3: Authorized Fluids for Injection or Enhanced Recovery
Fluids authorized for injection are:
• Source water from the Kuparuk seawater treatment plant
• Produced water from all present and yet-to-be defined oil pools within the Kuparuk River Field
• Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural
gas liquids
• Lean gas
• Fluids used during hydraulic stimulation
• Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.)
• Fluids used to improve near wellbore injectivity (via use of acid or similar treatment)
• Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin,
etc.)
• Fluids associated with freeze protection (diesel, glycol, methanol, etc.)
• Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.)
Rule 4: Authorized Injection Pressure for Enhanced Recovery
Injection pressures will be managed to not exceed the maximum injection gradient of 0.67 psi/ft to ensure
containment of injected fluids within the Coyote Oil Pool.
Rule 5: Monitoring Tubing-Casing Annulus Pressure
Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner
annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded for all injection
and production wells. The outer annulus pressures of all wells that are not cemented across the Coyote
Oil Pool and are located within a ¼-mile radius of a Coyote Oil Pool 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
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
Application to the AOGCC for Approval of Coyote Area Injection and Pool Formation
28
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 of 1,500 psi or 0.25 psi/ft multiplied by the
vertical depth of the packer, 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 the Operator observes an indication of pressure communication, leakage, or lack of injection
zone isolation, the Operator must notify the AOGCC by the next business day. Such indication may arise
from information including but not limited to injection rate, operating pressure observation, test, survey,
log, or outer annulus pressure monitoring in wells within one-quarter mile radius of where the Coyote Oil
Pool is not cemented. If the Operator’s investigation supports a conclusion of pressure communication,
leaking, or lack of injection zone isolation, the Operator must submit a corrective action plan to the
AOGCC, following the KRU Sundry Matrix (CO 261B). The Operator must shut in any well for which: (a)
continued operation would be unsafe, (b) continued operation would threaten contamination of
freshwater; or (c) the AOGCC directs the Operator to shut in the well. The Operator must submit a monthly
report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject
to administrative approval (AA) to operate; or (b) lack injection zone isolation.
1
