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HomeMy WebLinkAboutCO 819CONSERVATION ORDER 819
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 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
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Docket Number: CO-24-009
Conservation Order 819
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 defining a new oil pool, the Coyote Oil
Pool (COP), within the KRU and prescribing rules governing the development and
operation of that pool.
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 20th 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 comments on September 6, 2024.
Santos submitted additional comments regarding CPAI’s September 6 comments on
September 13, 2024. Since both letters were submitted after the record closed, they are
therefore 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 (DMLW), 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
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November 27, 2024
Page 2 of 12
Alaska II, Inc., Chevron U.S.A. Inc., and ExxonMobil Alaska Production, Inc. are the
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. Affected Area: CPAI is proposing (see Figure 1 below) that the Affected Area encompass
a portion of the KRU and extends beyond the area it proposed1 for the Coyote Participating
Area. The proposed COP 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.
4. Exploration, Delineation, and Development History: The proposed COP 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 2022-2023 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 On October 22, 2024, the DOG approved a Coyote PA that was approximately 5.5% smaller than what CPAI
proposed in its application.
CO 819
November 27, 2024
Page 3 of 12
Figure 1. Proposed Coyote Oil Pool Affected Area (Source: ConocoPhillips Alaska, Inc.)
5.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 COP 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
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November 27, 2024
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Figure 2 below) between 4,270 and 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.)
6. Relationship to Nanushuk Developments in the 38CRU and %78: The Nanushuk Oil
3RROin 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.
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November 27, 2024
Page 5 of 12
7. Geology:
A. Stratigraphy:
CPAI’s proposed COP 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 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 expands 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, 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.
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.
8. 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.
9. 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
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November 27, 2024
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Gas formation factor at Pb (RB/MSCF)
at saturation pressure
1.3
10. 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
11. 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-foot spacing between 3S-701A and 3S-704 which were
used for the pilot project. The 3S-701A has consistently taken 4,000 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.
12. 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.
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.
13. Reservoir Surveillance Plans: CPAI proposes the following reservoir surveillance plan:
a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior
to initiating injection.
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November 27, 2024
Page 7 of 12
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 COP, concentrating on injection wells.
d. In lieu of stabilized bottom-hole pressure measurements, the alternative pressure
survey methods below can be implemented:
i. Open-hole wireline formation fluid pressure measurements,
ii. Cased hole pressure buildups with bottom-hole pressure measurement,
iii. Injector surface pressure fall-off,
iv. Static pressure surveys following extended shut-in periods, or
v. 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.
Wellbore Construction: CPAI plans to develop the COP with 2- and 3-string wellbore
designs. The conductor would be set a minimum of 75 feet below the pad with cement
returns to surface verified by visual inspection. Surface casing will be set below the West
Sak Reservoir and cemented to surface. No hydrocarbon-bearing intervals have been
encountered to this depth in this area of the KRU. In 3-string wells, an intermediate casing
will be set in the top of the Coyote interval and cemented in place with a minimum of 500
feet MD / 250 feet true vertical depth (TVD) cement above the Coyote interval then
aproduction hole would be drilled to total depth (TD) and a production liner run
andcemented in place. In 2-string wells, the well will be drilled into the Coyote interval
andthen a smaller bit would be used to drill to TD and a tapered casing string would be
runand cemented from TD to a minimum of 500 feet MD / 250 feet TVD above the
Coyoteinterval. Plans are to utilize cemented production casing/liners with frac
sleeves, butuncemented slotted liners may be used on an as-needed basis.
Metering and Measurement Processes: Production from the COP will be commingled at
the surface with production from other KRU and Oooguruk Unit pools as it is transported
to Central Processing Facility (CPF) 2 and CPF 3. Well testing and production allocation
will be conducted in accordance with 20 AAC 25.230.
Waivers: CPAI requested the following waivers:
DWellbore Surveys: in lieu of the requirements of 20 AAC 25.050(b) CPAI proposes
submitting the following information with permit to drill applications:
LA plan view,
LLA vertical section,
LLLClose approach data, and
LYDirectional data
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November 27, 2024
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b. Well Spacing: The interwell spacing restrictions of 20 AAC 25.055 be waived for
development wells in the proposed COP to accommodate horizontal, line-drive wells
and maximize ultimate recovery. The property line off set regulations in 20 AAC
25.055 would remain in effect.
c. Logs and Geologic Data: CPAI requests that the requirements of 20 AAC 25.071(a)
only apply to one well from each drill site and be waived for all other wells because a
number of wells have been drilled in the area and additional data will not significantly
add to the geologic knowledge.
d. Measurement, Allocation, and Reporting of Well Production: CPAI proposes that 20
AAC 25.230(a) be waived and that instead each producing well will be tested at least
monthly.
e. Workover Operations: CPAI requests that the COP be included in the existing order
CO 261B, that governs workover operations on CPAI operations.
17. Interwell Spacing Requirements: Effective September 27, 2022, the statute governing
interwell spacing was changed and interwell spacing requirements were eliminated.
However, property line setback requirements were unchanged. (See AOGCC Industry
Guidance Bulletin 22-002).
18. Santos August 20 Letter: Santos addressed several issues in its letter:
A. The Santos operated Quokka Unit (QU) overlies the same broad geologic formation that
CPAI is proposing to be covered by the COP pool rules.
B. Santos supports development of the COP but says it 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 a one-mile property line setback requirement be imposed on the COP
instead of the 500-foot setback requirement contained in 20 AAC 25.055(a)(1).
CONCLUSIONS:
1. Establishing pool rules for the COP is appropriate and will aid in the efficient development
of the field while not promoting waste and protecting correlative rights.
2. A waiver of the requirements of 20 AAC 25.050(b) is commonly granted to simplify the
permit to drill application and review process and is appropriate for the COP.
3. The interwell spacing requirements of 20 AAC 25.055 are no longer supported by Alaska
Statutes and are therefore unenforceable. (See AOGCC Industry Guidance Bulletin 22-
002). Thus, CPAI’s requested waiver of the interwell spacing regulation is unnecessary.
The offset from property lines requirements, which is 500 feet for oil wells, are still in
place.
4. A waiver of the logging requirements of 20 AAC 25.071(a) is commonly granted for pools
where development will occur from drill sites with multiple wells. Receiving the required
CO 819
November 27, 2024
Page 9 of 12
data from more than one well per drill site will not significantly add to the geologic
knowledge of the area and is an appropriate waiver for the COP.
5. In its request to waive the requirements of 20 AAC 25.230(a) CPAI proposes instead to
conduct monthly well tests. Monthly well tests are required by 20 AAC 25.230(a) so a
waiver of the regulation is not required.
6. Applying CO 261B to the COP is appropriate to ensure all pools in the KRU have the same
rules regarding when a sundry permit/report is required.
7. Alaska Statute 31.05.035(c) dictates that exploratory wells are entitled to 24 months of
confidentiality following the 30-day report filing period from the date of initial completion,
suspension, or abandonment. The 3S-24B, 3S-701, 3S-701A, and 3S-704 were all properly
classified as exploratory wells when they were permitted and drilled and therefore their
data (except for regular production/injection volume reporting, which is always public data
per the statutes) is required to be held confidential for the statutory 24 month period unless
CPAI decides to allow the data to be released sooner. There are no provisions to allow the
AOGCC to release the data even when the wells have been put on long-term production or
injection as is the case for 3S-704 and 3S-701A wells.
8. The confidentiality period for 3S-24B expired in January 2024 and the data for that well
has been released to the public. The data for 3S-701, 3S-701A, and 3S-704 will be released
to the public in March and April of 2025. All new COP development and service wells will
not be classified as exploratory and as such the data from them will be made available to
the public immediately.
9. Santos has provided no evidence that increasing the property line offset requirement for
COP wells from the statewide regulatory standard of 500 feet to one mile, over a tenfold
increase, is necessary to protect its correlative rights.
NOW THEREFORE IT IS ORDERED:
Development and operation of the Coyote Oil Pool is subject to the following rules and the
statewide requirements under 20 AAC 25 to the extent not superseded by these rules:
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
CO 819
November 27, 2024
Page 10 of 12
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 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 (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 3 Gas Oil Ratio Exemption
Wells producing from the Coyote Oil Pool are exempt from the gas-oil ratio limitations set forth
in 20 AAC 25.240 so long as there is an active enhanced oil recovery injection project.
Rule 4 Drilling and Completion Practices
A. Alternate casing and completion programs, in addition to those specified in 20 AAC 25,
may be administratively approved by the AOGCC upon application and presentation of
data which demonstrate the alternatives are appropriate and based upon sound engineering
principles.
B. In lieu of the requirements under 20 AAC 25.050(b) permit to drill applications shall
include:
a. A plan view,
b. Vertical section,
c. Close approach data, and
d. A directional plan.
C. The requirements of 20 AAC 25.071(a) have already been satisfied for both the KRU 3S
and 3T drill sites, the primary pads from which the COP will be developed. For the COP,
the AOGCC may specify which types of logs are to be run on a well-by-well basis.
Rule 5 Well Spacing
The interwell spacing requirements of 20 AAC 25.055(a)(3) & (4) and 20 AAC 25.055(b) & (c)
do not apply. The property line offset requirements of 20 AAC 25.055(a)(1) & (2) that apply when
the owners or landowners are not the same on both sides of the line remain in effect.
Rule 6 Reservoir Surveillance
a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior to
initiating injection.
CO 819
November 27, 2024
Page 11 of 12
b. Static surveys will be performed on production wells at the discretion of CPAI.
c. 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.
d. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork
due to the limited number of surveys.
e. The datum depth for pressure surveys shall be 4,150 feet TVDSS.
f. The Coyote Oil Pool shall be included in the annual reservoir surveillance report submitted
for the Kuparuk River Unit
Rule 7 Workover Operations
Conservation Order No. 261B shall apply to the Coyote Oil Pool.
Rule 8 Sustained Casing Pressure for Production Wells
a. At the time of installation or replacement, the operator shall conduct and document a
pressure test of tubulars and completion equipment in each production well that is sufficient
to demonstrate that planned well operations will not result in failure of well integrity,
uncontrolled release of fluid or pressure, or threat to human safety.
b. The operator shall monitor each production well daily to check for sustained pressure,
except if prevented by extreme weather conditions, emergency situations, or unavoidable
circumstances. Monitoring results shall be kept available for AOGCC inspections.
c. The operator shall notify the AOGCC within three working days after the operator
identifies a well as having: (i) sustained inner annulus pressure that exceeds 2,000 pounds
per square inch gauge (psig) for all production wells, or (ii) sustained outer annulus
pressure that exceeds 1,000 psig.
d. If the operator identifies sustained pressure in the inner annulus of a production well that
exceeds 45 percent of the burst pressure rating of the well’s production casing for inner
annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the
burst pressure rating of the well’s surface casing for outer annulus pressure, the operator
shall notify the AOGCC within three working days and take corrective action. Unless well
conditions require the operator to take emergency corrective action before AOGCC
approval can be obtained, the operator shall submit in an Application for Sundry Approvals
(Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s
proposal or require other corrective action, including a mechanical integrity test or other
CO 819
November 27, 2024
Page 12 of 12
diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing
schedule to allow the AOGCC to witness the tests.
e. Except as otherwise approved by the AOGCC under (d) of this rule, before a shut-in well
is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that
the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that
the outer annulus pressure at operating temperature will be below 1,000 psig.
A well subject to (c) but not (d) of this rule may reach an annulus pressure at operating
temperature that is described in the operator’s notification to the AOGCC under (c) of this
rule, unless the AOGCC prescribes a different limit.
f. For purposes of this rule,
i. “inner annulus” means the space in a well between tubing and production casing;
ii. “outer annulus” means the space in a well between production casing and surface
casing; and
iii. “sustained pressure” means pressure that (A) is measurable at the casing head of an
annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been
applied intentionally.
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 10:06:06 -09'00'
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.11.27
10:15:58 -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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v
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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
AOGCC 8/20/2024ITMO: APPLICATION OF CONOCOPHILLIPS AK FOR AN AREA INJECTION ORDER & POOL RULES FOR THE COYOTE INTERVAL
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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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Computer Matrix, LLC Phone: 907-227-5312
Page 37
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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13
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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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v
Lisi Misa being first duly sworn on oath deposes
and says that she is a representative of the An-
chorage Daily News, a daily newspaper. That
said newspaper has been approved by the Third
Judicial Court, Anchorage, Alaska, and it now
and has been published in the English language
continually as a daily newspaper in Anchorage,
Alaska, and it is now and during all said time
was printed in an office maintained at the afore-
said place of publication of said newspaper.
That the annexed is a copy of an advertisement
as it was published in regular issues (and not in
supplemental form) of said newspaper on
AFFIDAVIT OF PUBLICATION
______________________________________
Notary Public in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
______________________________________
07/14/2024
and that such newspaper was regularly distrib-
uted to its subscribers during all of said period.
That the full amount of the fee charged for the
foregoing publication is not in excess of the rate
charged private individuals.
Signed________________________________
Subscribed and sworn to before me
Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501
Order #: 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
1
By Samantha Coldiron at 10:38 am, Jun 20, 2024
Application to the Alaska Oil and Gas Conservation Commission
(AOGCC) for Formation of the Coyote Oil Pool
Kuparuk River Unit
June 20, 2024
Application to the AOGCC for Formation of the Coyote Oil Pool
2
Contents
Section A Introduction .................................................................................................................................. 4
Document Scope ....................................................................................................................................... 4
Project Background ................................................................................................................................... 5
Section B Geology ......................................................................................................................................... 6
Pool Description ........................................................................................................................................ 6
Upper Confining Interval ....................................................................................................................... 6
Proposed Pool ....................................................................................................................................... 6
Lower Confining Interval of the Proposed Coyote Oil Pool .................................................................. 6
Coyote Trap and Structure ........................................................................................................................ 7
Coyote Deposition, Stratigraphy and Reservoir Quality ........................................................................... 8
Section C Reservoir ..................................................................................................................................... 11
Reservoir Properties ............................................................................................................................... 11
Defining Net Pay ..................................................................................................................................... 12
Reservoir Fluids and Pressure, Volume and Temperature (PVT) Properties .......................................... 12
Original Oil in Place (OOIP) ..................................................................................................................... 12
Section D Reservoir Development .............................................................................................................. 12
Current Development Approach ............................................................................................................. 12
Hydrocarbon Recovery ........................................................................................................................... 13
Recovery Process Selection..................................................................................................................... 13
Future Optimization ................................................................................................................................ 13
Producing Gas Oil Ratio (GOR) Expectations .......................................................................................... 13
Well Conversion Strategy ........................................................................................................................ 14
Section E Drilling ......................................................................................................................................... 14
Drilling/Well Design ................................................................................................................................ 14
Drilling Fluids ........................................................................................................................................... 17
Blowout Prevention ................................................................................................................................ 18
Directional Drilling .................................................................................................................................. 18
Well Spacing ............................................................................................................................................ 18
Logging Operations ................................................................................................................................. 18
Section F Well Operations .......................................................................................................................... 18
Well Design and Completions ................................................................................................................. 18
Artificial Lift ............................................................................................................................................. 19
Application to the AOGCC for Formation of the Coyote Oil Pool
3
Sidetracks ................................................................................................................................................ 19
Reservoir Surveillance ............................................................................................................................. 19
Well Work Operations ............................................................................................................................ 20
Stimulation Methods .............................................................................................................................. 20
Surface Safety Valves .............................................................................................................................. 20
Section G Facilities ...................................................................................................................................... 20
Introduction and Scope ........................................................................................................................... 20
Drill Site Facilities .................................................................................................................................... 21
Central Processing Facility ...................................................................................................................... 21
Production Allocation ............................................................................................................................. 21
Section H Proposed Coyote Oil Pool Rules ................................................................................................. 22
Rule 1: Field and Pool Name .................................................................................................................. 22
Rule 2: Pool Definition ........................................................................................................................... 22
Rule 3: Gas Oil Ratio Exemption ............................................................................................................. 23
Rule 4: Drilling and Completion Practices .............................................................................................. 23
Rule 5: Well Spacing ............................................................................................................................... 23
Rule 6: Reservoir Surveillance ................................................................................................................ 23
Rule 7: Production Practices ................................................................................................................... 23
Application to the AOGCC for Formation of the Coyote Oil Pool
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Section A Introduction
Document Scope
This application for formation of the Coyote Oil Pool is submitted for approval by the Alaska Oil and Gas
Conservation Commission (AOGCC) to define the proposed Coyote Oil Pool and establish Pool Rules for
the oil pool pursuant to 20 AAC 25.520.
ConocoPhillips Alaska, Inc. (CPAI), submits this application to the AOGCC in its capacity as Operator of the
Kuparuk River Unit (KRU). The scope of this application includes a discussion of geological and reservoir
properties of the proposed Coyote Oil Pool as they are currently understood, and CPAI’s plans for reservoir
development, reservoir surveillance, and well construction.
This application and supporting testimony will enable the AOGCC to establish rules that will allow
economic development of resources, promote greater ultimate recovery, and prevent waste within the
Coyote Oil Pool. Confidential data and interpretation concerning the Coyote Reservoir, as defined below
in this application, may be provided to the Commission by CPAI as additional support for this application
in accordance with the provisions of AS 31.05.035 and 20 AAC 25.537.
The proposed area to be covered by the Coyote Oil Pool is shown in Figure 1. The entire area of the
proposed Coyote Oil Pool and the area to which the proposed Area Injection Order (AIO) applies is within
the western portion of the KRU and an adjoining lease (ADL392374, which CPAI has applied to bring into
the KRU).
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 2). CPAI also proposes that the base of the Coyote Oil Pool
be defined by the top of the Torok Formation (5,115’ MD) and the top of the Coyote Oil Pool be defined
by the top of the Nanushuk Formation (4,270’ MD) (Figure 2 and Figure 3).
Application to the AOGCC for Formation of the Coyote Oil Pool
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Figure 1: Location Map
Project Background
The Coyote reservoir has numerous historical penetrations from wells drilled to deeper targets dating
back to the mid-1960s, with most wells drilled from the early 90s to 2010s. The Coyote interval was
historically overlooked due to its subtle petrophysical response (driven by thin-bed suppression). The
interval was first flow tested by Oil Search (Alaska), LLC (OSA) in the Mitquq 1 ST1 well. CPAI tested the
correlative interval within KRU in 2021 by drilling a vertical side-track (3S-24B). The 3S-24B allowed for
long-term production, long-term pressure build-ups, fracture height data, and overburden strength
calibration. Positive results from the 3S-24B led to the drilling of the first horizontal producer/injector well
pair (3S-701A/3S-704) in 2022-23. This drilling program included a dedicated pilot-hole (3S-701) for data
acquisition, including whole core and advanced logs. These wells have successfully demonstrated
Application to the AOGCC for Formation of the Coyote Oil Pool
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production from, and injection into, the Coyote reservoir. In addition, the wells have also confirmed
pressure communication at 1,500’ well spacing between the horizontal producer and horizontal injector.
Numerous on-pad development wells, and off-ice vertical exploration wells drilled to deeper intervals
have provided other data for static characterization of the Coyote reservoir. CPAI has also acquired and
analyzed 3D seismic, including merged and reprocessed depth migrated data.
CPAI plans to develop the Coyote Oil Pool from the existing 3S and 3T drill sites. On the surface, Coyote
Oil Pool production will be commingled with other KRU production as it is carried to Central Processing
Facilities 2 and 3. All Coyote production will be measured as described in Section G of this application.
Subject to AOGCC approval of the facilities and measurement program, no separate approval for
commingling is necessary under 20 AAC 25.215.
Section B Geology
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 2).
The Coyote reservoir is part of the Brookian Nanushuk formation. The Nanushuk was deposited in a
shallow marine to upper slope setting in the Colville foreland basin. The Colville basin was created by
loading from the south from the emerging Brooks Range and pinning to the north by the antecedent
Jurassic rift shoulder (‘Barrow Arch’, or ‘North Slope Anticlinorium’). The basin was dominantly filled
axially from west to east, with sediments originating from an uplift region in the Chukotka area of what is
now eastern Russia. The sedimentary fill sequence is broadly divided into two time-transgressive
formations that are delineated by their gross environments of deposition. The ‘topset’ Nanushuk
Formation forms a series of eastward prograding deltaic - shoreface - uppermost slope sediments. The
equivalent middle - lower slope - basin floor sediments are grouped into the Torok formation. The Coyote
reservoir is located at the easternmost portion of this progradational system, deposited just prior to a
major basin-wide transgressive flooding event that forms the top of the Nanushuk/Torok sequence.
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 of more than 350’ TVD across the
area.
Proposed Pool
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 2). A detailed description is provided under the Statigraphy
and Sedimentology section of this application.
Lower Confining Interval of the Proposed Coyote Oil Pool
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
Application to the AOGCC for Formation of the Coyote Oil Pool
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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 2 below.
Figure 2: Type log, Palm 1, UWI: 501032036100
Coyote Trap and Structure
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 and thins to the south-southwest, where it also dips
below the same presumed oil-water-contact south of KRU. The top Coyote structure is very low relief
within the development area, with structural dips averaging ~1 degree or less (Figure 3). 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 3.
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Coyote Deposition, Stratigraphy and Reservoir Quality
The gross Coyote trend is a generally west to east progradational system that is elongated in a northeast
to southwest direction (Figure 4). 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 4).
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 5 and Figure 6 for reference.
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Figure 3: Top Coyote depth structure map
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Figure 4: Coyote net pay
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Figure 5: Depositional dip well log cross-section (structural datum)
Figure 6: Depositional strike well log cross-section (structural datum)
Section C Reservoir
Reservoir Properties
The Coyote Reservoir consists of Lower Cretaceous Nanushuk deltaic deposits comprised of thinly
laminated, very fine-grained sandstones, siltstones, and mudstones.
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Two whole cores have been acquired in the Coyote reservoir (Mitquq 1 ST1, and 3S-701). Average porosity
and permeability from core data is ~24% and ~32 md (air at 1,600 psi confining stress), respectively.
Average water saturation is ~52%. The reservoir sands can be characterized as litharenites.
Defining Net Pay
The Coyote reservoir interval consists of thinly bedded sands and silts from the top to the base of the
interval. Individual sand beds are below well log resolution for basic logging suites. Therefore, net pay
calculations for the Coyote reservoir are based on a core and advanced log calibrated, thin bed
petrophysical model. CPAI has estimated OOIP (see below) in the upper 200’ of the interval, above an
interpreted hydrocarbon water contact depth at -4,260’ SSTVD.
Reservoir Fluids and Pressure, Volume and Temperature (PVT) Properties
Reservoir fluid PVT and oil characterization studies have been completed on fluids gathered from the
Mitquq 1 ST 1 and 3S-704 wells.
Coyote Reservoir and fluid properties are (-4,150’ TVDSS datum):
- Initial Reservoir pressure: 1857 psig
- Reservoir temperature: 105 degF
- GOR: 580 scf/bbl
- API gravity: 32 deg API
- Bubble point pressure: 1794 psig
- Oil formation volume factor: 1.28 rb/stbo
- Oil viscosity: 1.0 cp
- Gas formation volume factor: 1.3 bbl/mscf (at saturation pressure)
Original Oil in Place (OOIP)
The stock tank OOIP volumetric estimates for the proposed Coyote Oil Pool range from 508 to 646 MMSTB
for the area encompassing conceptual development wells currently planned from the 3S and 3T drillsites
(brown well “sticks” in Figure 1). This increases to 636 to 810 MMSTB for the area inside the proposed
pool polygon. The 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.
Section D Reservoir Development
Current Development Approach
The Coyote Oil Pool will be developed in a phased approach from existing KRU drill sites 3S and 3T, which
are currently connected to KRU Central Procession 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.
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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 4000 bbls/day seawater, and a pressure response has been noticed in the offset 3S-
704 horizontal producer.
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.
Recovery Process Selection
A 3-D compositional model was constructed covering the productive interval. Waterflooding was the
recovery method selected, with lean and miscible gas injection evaluated as potential future recovery
improvements. The largest remaining uncertainty for the Coyote development is the question of
interconnectivity of the reservoir at the proposed development scale of 1,300’ well spacing. The highly
interbedded nature of the proposed Coyote Oil Pool could result in poor inter-well communication at that
distance. Early observed pressure communication between the 3S-704 and 3S-701A, at an inter-well
distance of 1,500’, indicates waterflood support is likely at the current well spacing. Additionally,
simulation modeling using existing core data and geologic descriptions has predicted that communication
will occur.
Future Optimization
Optimizing field development will be an ongoing process requiring additional data, laboratory studies, and
reservoir modeling. The effective length and skin of the model wells is being tuned based on well test
data. Simulation studies to determine the incremental recovery from MWAG are also underway.
Producing Gas Oil Ratio (GOR) Expectations
CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed Coyote Oil
Pool for two reasons: 1) the Coyote reservoir has a small gas cap that will be produced out, and 2) in the
future, CPAI may implement enhanced recovery techniques involving injection of gas into the Coyote Oil
Pool. As a result, the GOR is expected to rise above solution GOR in some wells. The breakthrough of re-
injected gas may also cause GORs of some producing wells to exceed limits set forth in 20 AAC 25.240.
However, potential gas re-injection would be expected to enhance ultimate recovery.
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Well Conversion Strategy
The Coyote Oil Pool development will target a voidage replacement ratio of 1.0. The injector/producer
ratio will be dictated by the voidage replacement performance and well spacing relative to the
developable area. Dependent on facility constraints, pre-production of injection wells may occur. After
the pre-production period, these wells will be converted to injection, unless service conversion is
determined beneficial for ultimate recovery or necessary to meet the voidage replacement ratio target.
Section E Drilling
Drilling/Well Design
The Coyote Oil Pool will be accessed from wells drilled from gravel pads utilizing drilling procedures, well
designs, and casing and cementing programs consistent with current practices in other North Slope fields.
Figure 7 and Figure 8 below illustrate generic Coyote 2-string and 3-string well designs. Producers and
injectors will both be completed with the same well design.
Conductor casing will either be driven or drilled and cemented at least 75’ below the pad. Cement returns
to surface will be verified by visual inspection.
Surface holes will be drilled and set below the base of the West Sak Reservoir. This casing setting depth
provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high
departure wells. Within the planned development area, the base of permafrost is interpreted to be
between -1500’ and -1,700’ SSTVD. Surface casing strings will be cemented in accordance with 20 AAC
25.030(d)(4). No hydrocarbon bearing intervals have been encountered to this depth in previous wells.
The blowout prevention equipment (“BOPE”) will be installed and tested in accordance with 20 AAC
25.035 requirements. A Formation Integrity Test (“FIT”) will be performed in accordance with 20 AAC
25.030(f). In 3-string well designs, the intermediate hole will be drilled to a casing point within the upper
Coyote interval at approximately 85 degrees inclination. In 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 in accordance with 20 AAC
25.030(d)(5). The section between the proposed surface casing shoe and the top of the Coyote Reservoir
consists primarily of mudstones and siltstones with very few minor sandstones.
Based on current knowledge of reservoir characteristics, CPAI expects to develop the Coyote Oil Pool using
horizontal wells with cemented production casing/liners with frac sleeves to facilitate staged hydraulic
fracture stimulation treatments. Both injection and production wells will likely be completed with 4-1/2”
tubing to facilitate hydraulic stimulation.
Uncemented slotted liners are included in the drilling plans on an “as-needed” basis. For example,
wellbores that encounter significant shale or lost circulation intervals may receive slotted liners with
external casing packers (“ECP”). At some point in the future coil tubing workovers may place slotted or
cemented liners within the proposed pool.
In addition to horizontal wells with cemented solid liners including frac sleeves to facilitate staged
hydraulic fracture stimulation treatments, CPAI proposes that the Coyote Oil Pool Rules also authorize the
following alternative completion methods:
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A. Open-hole liner or casing and perforated completions with the option of hydraulic fracture
stimulation treatments.
B. Slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole
and which may then be gravel packed.
C. Vertical or “conventional” open-hole completions. Open-hole completions may subsequently be
completed with slotted or perforated liners, wire-wrapped screen liners, or combinations thereof,
and may be gravel packed.
D. Horizontal or “high angle” completions with liners, slotted or perforated liners, wire-wrapped
screens, or combination thereof, landed inside the horizontal extension, and which may be
cemented and perforated, or gravel packed.
E. Multi-lateral type completions in which more than one wellbore penetration is completed in a
single well, with production gathered and routed back to a central wellbore.
Other casing and completion methods may be approved by the Commission by administrative approval
upon request by CPAI supported by data demonstrating that such alternatives are based on sound
engineering principles.
Application to the AOGCC for Formation of the Coyote Oil Pool
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Figure 7: Proposed 2-String Coyote Well Schematic
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Figure 8: Proposed 3-String Coyote Well Schematic
Drilling Fluids
The drilling fluid program designed for wells within the Coyote Oil Pool will be prepared and implemented
in accordance with 20 AAC 25.033. Formation pressures for the strata to be penetrated will be estimated
and documented based on the current wells targeting the Coyote Reservoir as well as from the KRU wells
which have already penetrated the proposed Coyote Oil Pool.
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Blowout Prevention
General well control for drilling and completion operations will be performed in accordance with 20 AAC
25.035.
Directional Drilling
CPAI requests that the requirements described in 20 AAC 25.050(b) be waived for the proposed Coyote
Oil Pool to relieve administrative burden. In lieu of the requirements under 20 AAC 25.050(b), CPAI
proposes that permit(s) to drill shall include:
1) Plan view
2) Vertical section
3) Close approach data
4) Directional data
Well Spacing
CPAI requests that the requirements described in 20 AAC 25.055 be waived for the proposed Coyote Oil
Pool because the horizontal well development of the proposed Coyote Oil Pool, via line-drive flood
pattern, will yield greater recovery than a conventional vertical/slant well development plan with a
minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes without prior
approval, development wells may not be completed any closer than 500’ to an external boundary where
working interest ownership changes.
Logging Operations
The basic log suite planned in the Coyote Reservoir includes gamma ray (GR) and resistivity logs for the
purpose of facies interpretation. If log identification of formation facies is not possible, rate of penetration
(ROP) and cuttings will become the reservoir quality determinants. At some point in the future, it is
possible that Coyote wells could be drilled using GR as well as other drilling indicators to locate the pay
zones.
CPAI requests that the requirements described in 20 AAC 25.071(a) be waived for the proposed Coyote
Oil Pool since these requirements will not significantly add to the geologic knowledge of the area
considering the information that is available from the numerous well penetrations in the area. 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.
As the first Coyote reservoir targeted wells on drill site 3S (3S-24B/3S-701/3S-701A/3S-704) were
successfully investigated with a suite of gamma ray/resistivity/neutron/density logs, additional log
investigation of formations from the 3S drill site of the proposed Coyote Oil Pool would be performed at
CPAI’s discretion.
Section F Well Operations
Well Design and Completions
Both injectors and producers are planned to be completed with 4-1/2” tubing and production liner to
facilitate hydraulic stimulation and to exploit the production potential of horizontal wells. All wells will be
equipped with gas lift mandrels and a production packer to anchor the tubing in place during stimulation
Application to the AOGCC for Formation of the Coyote Oil Pool
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and to provide isolation for the tubing-casing annulus. The 4-½” liners will be set with a liner
hanger/packer system and have frac sleeves integral to the string, although alternative completion
methods are included as additional potential options above. (Tubular size and other well design elements
are, of course, planned and subject to change.)
Artificial Lift
The current development plan utilizes gas lift as the artificial lift mechanism to produce from the Coyote
Oil Pool; however, CPAI may employ several different techniques (jet pump, electrical submersible pumps,
etc.) to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance
production rates at increased water cuts, which are anticipated following waterflood response.
Sidetracks
In the event early waterflood breakthrough is encountered due to high permeability intervals, the initial
completions may be plugged back and sidetracked to improve sweep and enhance recovery. Sidetracks
may also become necessary if the parent wellbore does not produce/inject as expected or no longer
supplies required integrity. In addition to pattern conformance, sidetracks could increase water injection,
sidestep faulting or penetrate bypassed oil.
Sidetracking scenarios can be expected to target maturing reservoir sections for increased injectivity,
reach undrained or isolated pockets, and improve enhanced recovery techniques. As such, sidetracks can
be expected to radiate out laterally from the parent wellbore. This further supports the request for a
waiver of regulation 20 AAC 25.055.
Reservoir Surveillance
The initial reservoir pressure of the Coyote Oil Pool, as required by 20 AAC 25.270(a), was measured in
the 3S-24B well.
CPAI requests that the Commission approves the proposed reservoir pressure monitoring plan:
• Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating
injection.
• Static surveys will be performed on production wells at the discretion of CPAI.
• For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted
annually in the Coyote Oil Pool, concentrating on injection wells.
• Since lengthy horizontal wells require extended shut-in periods, often months long, to achieve
stabilized bottom-hole pressures, the alternative pressure survey methods below can be
implemented:
o open-hole wireline formation fluid pressure measurements,
o cased hole pressure buildups with bottom-hole pressure measurement,
o injector surface pressure fall-off,
o static pressure surveys following extended shut-in periods, or
o bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of
a stabilized shut-in injection well.
• All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to
the limited number of surveys.
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While the top of the pool extends between approximately -3,950’ TVDSS and -4,200’ TVDSS, a
representative common datum for reporting should be -4,150’ TVDSS. The -4,150’ TVDSS datum will be
representative of the targeted depth since the estimated oil/water contact depth is approximately -4,260’
TVDSS.
Well Work Operations
Well work operations in the Coyote Oil Pool will include routine mechanical integrity tests of each
wellbore and artificial lift maintenance. Operations will also include remedial management of scale,
paraffin, etc. with slickline or hot diesel treatments. Unlike more typical multi-zone or multi-layer fields
on the North Slope, the Coyote Oil Pool represents a single hydrocarbon accumulation. Production from
a single pool minimizes profile modifications.
For ongoing well work CPAI requests that the Coyote Oil Pool be included in the existing KRU sundry
matrix, CO 261B. This is intended to reduce the paperwork burden on both the Commission and CPAI.
Summary reports and records will continue to be kept in accordance with 20 AAC 25.280c) and (d).
Stimulation Methods
Stimulation techniques will be used to enhance productivity of the Coyote Oil Pool. Stimulation to remove
drilling induced formation damage and enhance near wellbore flow characteristics may be performed to
increase the commercial flow rates in this reservoir. Additional hydraulic fracture stimulation (in addition
to initial hydraulic fracturing during completion) may also be performed to increase the commercial flow
rates of the Coyote Reservoir. Wellbore trajectories, cementing programs, and tubulars will be designed
to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will also be
performed in accordance with 20 AAC 25.283.
Surface Safety Valves
Wells will be equipped with appropriate well safety valve systems in accordance with 20 AAC 25.265.
Periodic inspections and testing, at least semi-annually, will be conducted following notification of the
Commission.
Section G Facilities
Introduction and Scope
The Coyote Oil Pool will be initially developed from the existing KRU drill sites 3S and 3T, which are
currently connected to KRU CPF3. The 3S and 3T onshore gravel drill sites were selected for the initial
development due to the ability to adequately target the Coyote Oil Pool from that surface location with
adequate infrastructure to deliver fluids to CPF3 (~11 miles away). To accommodate the full production
potential of the Coyote Oil Pool, upgrades to the current infrastructure will be necessary. Currently
proposed improvements include a new produced oil pipeline and water injection pipeline between 3S drill
site to CPF2. Final infrastructure improvement designs are being evaluated.
Injection water will consist of produced water, with the future potential of injecting seawater. Injection
gas will be sourced from KRU processing facilities. Although the future availability of gas for injection
purposes cannot be predicted, some form of IWAG/MWAG may occur in one or more injection patterns.
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Drill Site Facilities
Coyote Oil Pool wells will be located at existing KRU drillsites 3S and 3T. Wells at 3S will be tested using
the current test separator and at 3T, muti-phase meters will be installed.
Production will be commingled with Torok Oil Pool production at the drillsites and processed at CPF3 and,
likely, also CPF2.
Central Processing Facility
CPF3 receives production from CPAI operated drill sites and ENI’s Oooguruk Unit and provides primary
separation into wet oil, gas, and water. Wet oil is then sent to CPF1 and CPF2 through pipelines for further
processing. Gas is dehydrated and compressed for artificial lift and fuel gas to support the facility.
Produced water pressure is boosted and used for reinjection.
At CPF3, the primary separator removes gas and most of the water from the produced fluid. Wet oil is
then transferred to CPF1 and CPF2 for further separation to sales quality. Wet oil is metered to balance
flow between CPF1 and CPF2 to optimize field-wide processing.
The gas stream from the primary separator is processed and compressed for artificial lift and fuel gas in
two stages. First-stage compressors A and B, powered by General Electric Frame 3 units, boost gas to ~500
psig for fuel gas usage. Second stage compression consists of gas turbine-driven centrifugal compressors
that boost pressure to ~1400 psig for CPF3 lift gas. CPF3 does not have compression capacity to generate
injection gas; CPF3 drill sites receive injection gas from CPF1 and CPF2.
Produced water is separated from the produced fluids and reinjected into the reservoir for pressure
maintenance and waterflood support. Additionally, CPF3 also has two seawater injection pumps for
seawater injection.
CPF3 generates its own power using a General Electric Frame 5 gas turbine as the primary generator. The
Frame 5 can generate 23-27 MW depending on the ambient temperatures. There is also a single
permanent Ruston gas turbine generator (~3.2MW capacity) and a portable emergency diesel generator.
CPF3 is tied into the Kuparuk Power Grid, with redundant tie-lines, and is typically an exporter of power.
Other utility systems include instrument air, nitrogen, plant air, cooling glycol, and heating glycol.
Production Allocation
Production will be measured with equipment in accordance with 20 AAC 25.228. Production will be
allocated to producing wells based on the actual oil sales volume and well tests on individual producing
wells. The well tests will be used to create performance curves to determine the daily theoretical
production of each well. The CPF allocation factor will be applied to adjust total production from the
associated drill sites. All the wells are connected to a test header system, which goes to a test separator
on the 3S pad. In the future, a multiphase flow meter (MPFM) will be installed at 3T pad to measure
production from each well drilled from that location.
A separate participating area is planned for the Coyote Oil Pool. The Coyote project area is also subject to
the KRU Unit Agreement. The State of Alaska is the royalty owner.
The control system for the Coyote Oil Pool wells will continuously gather operating data from the wells
and the test separators. To accurately allocate the production the following actions will be followed:
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• All wells will be periodically tested.
• The stabilization and test duration of each test will be optimized by CPAI to obtain a
representative test.
• Well and field operating condition information required for the construction of a field production
history will be maintained.
• Major test separator meters and major gas system meters will be installed and maintained
according to industry recommended practices or standards.
• CPAI will maintain records that permit verification of the satisfactory execution of the approved
production allocation methodologies.
Section H Proposed Coyote Oil Pool 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
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)
Application to the AOGCC for Formation of the Coyote Oil Pool
23
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.
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.
