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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAboutCO 807CONSERVATION ORDER 807
Pikka Unit
1. March 6, 2023 OilSearch application for pool rules for the Nanushuk Oil
Pool
2. March 14, 2023 Public Hearing Notice, Affidavit of Publication, Email list,
bulk mail list.
3. April 18, 2023 Hearing transcript and presentation
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage, Alaska 99501
Re: THE APPLICATION OF Oil Search
(Alaska), LLC for an order for
classification of a new oil pool and to
prescribe pool rules for development of
the proposed Nanushuk Oil Pool within
the Pikka Unit
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Docket Number: CO-23-003
Conservation Order 807
Nanushuk Oil Pool
Pikka Unit
North Slope Borough, Alaska
July 20, 2023
IT APPEARING THAT:
1. By application received March 7, 2023, Oil Search (Alaska), LLC (OSA), a subsidiary of
Santos Ltd (Santos), as operator of the Pikka Unit (PU), requested an order defining a new
oil pool, the Nanushuk Oil Pool (NOP), within the PU 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 April 18, 2023. On March 14, 2023, 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 March 16, 2023, the notice was also published in
the Anchorage Daily News.
3. No public comments on the application were received.
4. The hearing commenced at 10:00 a.m. on April 18, 2023. Testimony was received from
representatives of OSA.
5. The record was closed at the end of the hearing.
FINDINGS:
1. Owners and Landowners: Surface owners in the proposed NOP area are Kuukpik
Corporation, the State of Alaska, heirs, devisees and/or assigns of Neil Allen, Katherine
Brown, Jim T. Allen, and the estate of Helen E. Tukle. Subsurface owners of the NOP are
Alaska Department of Natural Resources (DNR) and the Arctic Slope Regional
Corporation. OSA and Repsol E&P USA LLC (Repsol) are the working interest owners
of the leased acreage within the proposed Affected Area, as defined below.
2. Operator: OSA is operator of all the leased acreage in the proposed Affected Area.
3. Affected Area: OSA is proposing that the Affected Area encompass the entirety of the PU,
which lies between the Colville River Unit (CRU) to the west, the Kuparuk River,
Oooguruk, and Quokka Units to the east, the Beaufort Sea to the north and non-unitized
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state lands to the south. The unit lies mostly onshore on the North Slope of Alaska but also
extends onto state submerged lands in the Beaufort Sea.
4. Exploration and Delineation History: OSA, along with predecessor operators Repsol and
Armstrong Energy, LLC., have conducted significant exploration activity in the project
area. More than 20 wells have penetrated the Nanushuk Formation in the area and 6 of
these had successful flow tests and 4 collected cores from the Nanushuk Formation. Key
wells used to define the NOP include the Qugruk-3, Qugruk-3A, Qugruk-7, Qugruk-301,
Qugruk-8, Qugruk-9, Qugruk-9A, Fiord-2, Fiord-3, Pikka B, and Pikka C.
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Figure 1. Pikka Project Area Showing Unit Boundary, Leases, Exploratory Wells,
and Development Infrastructure (Source: Oil Search (Alaska), LLC)
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5. Pool Identification: As proposed, the NOP encompasses a thick accumulation of deltaic
shelf deposits that were time-equivalent to shale-dominated Torok Formation sediments
that were deposited in deeper water. The proposed NOP is the accumulation of
hydrocarbons common to and correlating with that portion of the Nanushuk Formation
(Nanushuk) shown on the Qugruk 3 reference log between 3,892 and 5,166 feet measured
depth (MD), which is equivalent to 3,785 and 4,985 feet true vertical depth below mean
sea level (also termed true vertical feet sub-sea, or TVDSS). OSA’s informally named
“Nanushuk 3” sandstone interval will be OSA’s primary development target, but towards
the western edge of the proposed NOP the underlying Nanushuk 2 interval becomes more
developed, and it may also be a development target.
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Figure 2. Qugruk 3 type log (Source: Oil Search (Alaska), LLC)
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6. Relationship to Nanushuk Developments in the CRU and KRU: At the public hearing,
OSA testified that the Nanushuk is composed of several imbricated, sand-rich, eastward-
prograding, top-set intervals. The axes of these intervals strike north-northeast and they off
lap progressively toward the east across the boundary between the CRU and the PU.
According to Conservation Order (CO) 605, CO 605A, and Area Injection Order (AIO)
No. 35, the Qannik Oil Pool (QOP) in ConocoPhillips Alaska, Inc.’s (CPAI) CRU
comprises sandstone intervals within the Nanushuk that are overlain and underlain by thick
shales and siltstones assigned to the Seabee and Torok Formations respectively. The QOP
was initially defined as the interval that correlates to 6,086 to 6,249 feet MD in the CRU
CD2-11 well (API 50-103-20515-00-00), and AIO 35 currently specifies this as the
approved injection interval. However, the QOP was subsequently expanded vertically by
CO 605A to include the interval from 6,030 to 6,249 feet MD in CRU CD2-11. CPAI’s
informally named Narwhal reservoir within the boundaries of the CRU produces from, and
injects into, the Nanushuk Formation. Enhanced Recovery Injection Order (ERIO) No. 6,
which authorized a pilot injection project in the Narwhal reservoir defines the Narwhal as
correlating to the interval of 4,192 to 5,152 feet MD in the Qugruk 3 well. So, as shown
by Figure 2, CPAI’s Narwhal reservoir is correlative with a portion of OSA’s requested
NOP (between 3,829- and 5,166-feet MD).
According to ERIO 8, CPAI’s informally named Coyote reservoir in the KRU is another
Nanushuk Formation development that is overlain by the Seabee Formation, underlain by
the Torok Formation, and correlates to the interval in the Palm 1 well (API No. 50-103-
20361-00-00) from 4.270 to 5.115 feet MD.
7. Geology:
a. Stratigraphy:
OSA’s proposed NOP is part of a large-scale, constructional, siliciclastic clinoform system
that prograded from west to east. The top set shelfal sediments constitute the Nanushuk
Formation, and the contemporaneous, slope-dominated sediments deposited along the east-
facing foreset slopes are assigned to the Torok Formation. Reservoir quality is greatest in
the sand-rich top set beds that were influenced by wave action on a marine shelf. Porosity
ranges from 4 to 28 percent and averages 17.5 percent, with permeabilities ranging from
0.01 to 660 millidarcies (mD) and averaging 60 mD. Water saturation ranges from 9 to 78
percent and averages 41 percent.
b. Structure:
The NOP structure is a monocline that dips gently to the east and is cut by only a small
number of faults that have minor vertical offsets.
c. Trap Configuration and Seals:
The hydrocarbon accumulation is contained by a stratigraphic trap, with along strike and
updip facies changes providing lateral seals and the overlying Seabee Formation, which is
about 1,000 feet thick in the planned development area, provides a top seal. Lower
confinement is provided by interbedded claystones, silty shales, and shale of the Torok
Formation, which has an aggregate thickness of approximately 250 feet in this area.
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d. Permafrost Base:
The base of permafrost ranges between approximately -750 and -1,400 feet TVDss in the
planned development area.
8. Reservoir Fluid Contacts: Gas and water contacts have not been directly encountered
within the proposed NOP. Each oil accumulation region might have its own free water
level, which are currently estimated to lie to be between -4,950 and -5,280 feet TVDSS.
9. Reservoir Fluid Properties: OSA provided the following properties for samples from three
different accumulation regions within the planned development area.
Description Pikka B Qugruk 8 Pikka
C
Accumulation Region South Central North
Sample depth (feet TVDSS) -4,271 -4,185 -4,096
Reservoir Pressure (psia) 1,955 1,923 1,898
Reservoir Temperature (°F) 102 102 105
Stock tank oil API Gravity (°) 26.1 29.3 30.4
Gas oil ration (SCF/STB) 405 430 378
Bubble point pressure, Pb (psi) 1,609 1,561 1,631
Oil formation factor at Pb (RB/STB) 1.177 1.188 1.167
Oil viscosity at Pb (cP) 5.62 2.04 2.53
Oil Compressibility at Pb (1E-6/psi) 8.71 6.60 7.47
Gas gravity (multi-stage separator test) 0.842 0.829 0.768
Gas formation factor at Pb (RB/MSCF) 1.406 1.406 1.439
10. In-Place and Recoverable Reserves Volumes:
Nanushuk Reservoir Volume Range
(MMSTBO)
Original Oil in Place (OOIP) 2,297-2,814
Primary Recovery (<7% OOIP) 161-253
Primary + Waterflood (23% OOIP) 532-718
Primary + Water Alternating Gas (26-29% OOIP) 592-868
Predicted Recovery from NDB pad development only
(Primary + WAG ~37% OOIP)
~383
11. Reservoir Development Drilling Plan: OSA plans to develop the NOP in a phased manner.
Initially, 41 wells will be drilled from the central Nanushuk Drill Site B (NDB) and future
development may occur from two additional drill sites, the northern Nanushuk Drill Site A
(NDA) and the southern Nanushuk Drill Site C (NDC). A horizontal line drive water-
alternating-gas (WAG) development has been chosen. Due to the highly laminated nature
of the reservoir, all wells will be fracture stimulated to enhance productivity and improve
vertical injection sweep.
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Most wells will trend northwest along the maximum principal stress direction of 330° to
improve waterflood performance. Wells will have horizontal sections of 3,000 to 8,000
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 1,800 feet between
producers and injectors will be optimal, but this is subject to change based on initial well
performance and the collection and analysis of addition geologic and engineering data.
Development drilling on the NDB will commence in Q2 or Q3 2023 and continue for
approximately 5 years. Extended-reach drilling (ERD) may occur later.
Existing and planned development wells that are used to develop the Nanushuk reservoirs
in the CRU and the PU are or will be truncated a minimum of 500 feet from the common
unit boundary in accordance with state spacing requirements.
12. Reservoir Management: OSA plans to develop the NOP WAG enhanced oil recovery
project with water initially coming from a new build seawater treatment plant and
eventually being supplemented with produced water when enough becomes available.
Produced gas will be reinjected. Production and injection voidage will be balanced to
maintain reservoir pressure at or near the original measured pressure. Development will
target a 1.0 voidage replacement ratio.
Due to the produced gas being reinjected, OSA expects the producing gas oil ratio (GOR)
will increase over time and eventually exceed twice the initial GOR, which is allowable
under 20 AAC 25.240(b) as, for development projects, the AOGCC may grant a waiver of
the GOR limit if a pool is being developed as an enhanced oil recovery (EOR) project or if
produced gas is being reinjected.
13. Reservoir Surveillance Plans: OSA proposes to meet bottom-hole pressure survey
requirements through the following reservoir pressure monitoring plan:
a. Static bottom-hole pressure surveys will be conducted in all new wells upon initial
completion.
b. For annual pressure surveillance, a minimum of one pressure survey will be conducted
annually from each drillsite, concentrating on injection wells.
c. Since lengthy horizontal wells require extended shut-in periods, often months long, to
achieve stabilized bottom-hole pressures, OSA proposes the following alternative
pressure survey methods below can be implemented.:
i. Producer pressure build-ups with bottom-hole pressure measurement,
ii. Injector pressure fall-off with bottom-hole or surface pressure measurement,
Pressures will be referenced to -4,100 feet TVDSS. All pressure surveys will be reported
annually.
14. Wellbore Construction: From the NDB, the NOP will be developed with wells that fall
into one of four tiers based primarily on the length of the well. Tier 1 and Tier 2 wells are
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three-casing-string design wells with a 13-3/8” surface casing set at about 2,200 feet true
vertical depth (TVD) and cemented to surface, and a 9-5/8” intermediate casing set within
the Nanushuk. Tier 1 wells will be fully cemented from the casing shoe to a liner-top
packer (LTP) in the surface casing, while Tier 2 wells will utilize a two-stage cementing
operation: initially cement will be pumped around the casing shoe and then a stage tool
placed shallower in the casing string will be opened to place cement across the known
shallow hydrocarbon bearing sands in the Tuluvak and continuing upward to an LTP in the
surface casing. Tier 1 and 2 wells will then be completed with a 4-1/2” solid liner with
hydraulic fracturing sleeves and swell packers that will be hung in the intermediate string
with a LTP.
Tier 3 wells are a slim hole, four-casing-string design with a 13-3/8” surface casing set at
about 2,200 feet TVD and cemented to surface. A 9-5/8” intermediate 1 liner will be set
along the tangent of the well and cemented using a one- or two-stage cementing operation
as described for the Tier 1 and Tier 2 wells. A 7” intermediate 2 liner will land in the
Nanushuk, cemented at the shoe, and tied into Intermediate 1 with an LTP. The wells will
then be completed with a solid 4-1/2” liner as described for Tier 1 and Tier 2 wells.
The very long Tier 4 wells will employ a large bore, four-casing-string design, and will
require a different rig of greater capacity to drill and complete. These wells would be
completed similarly to the Tier 3 wells except that the casing strings are enlarged to 18-
5/8” surface casing, 13-3/8” Intermediate 1 liner, and 9-5/8” Intermediate 2 liner. The
wells would be completed with the same 4-1/2” production liner that the Tier 1 to 3 wells
employ.
15. Metering and Measurement Processes: Well testing and production allocation will be
conducted with a multiphase meter. Custody transfer metering will occur after production
is processed to sales quality in the Nanushuk Production Facility.
16. Waivers: OSA requested the following waivers:
a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells
in the proposed NOP to accommodate horizontal, line-drive wells and maximize
ultimate recovery. Without prior approval, development wells will not be completed
any closer than 500 feet to an external boundary where ownership and/or
landownership changes.
b. Directional Wellbore Plans: In lieu of the requirements of 20 AAC 25.050(b), permit
to drill application(s) shall include: plan view, vertical section, close approach data,
and directional data.
c. Gas-Oil Ratio (GOR) Exemption: an exemption from the GOR limits of 20 AAC
25.240 to accommodate water-alternating-gas-injection for oil recovery.
d. Well Logging: In lieu of the requirements of 20 AAC 25.071(a), one well per drill site
is required to be logged for the portion of the well below the conductor pipe by an
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MWD log suite since additional logs won’t appreciably add to the geologic knowledge
of the area.
17. Interwell Spacing Requirements: Effective September 27, 2022, the statute governing
interwell spacing was changed and interwell spacing requirements were eliminated.
However, property line set back requirements were unchanged.
CONCLUSIONS:
1. The Nanushuk Formation across the CRU and PU comprises a single oil pool per AOGCC
statutes.
2. There are currently two operators spread across three units that are or will be producing
from the Nanushuk Formation, and these numbers may increase in the future.
3. Pool rules that are limited to a single pool and operator are appropriate to allow OSA and
CPAI to develop their portions of the Nanushuk Formation in the manner that they deem
appropriate.
4. Pool rules for the development of the proposed NOP within the PU are appropriate.
5. The Tuluvak Formation is a significant hydrocarbon bearing zone in the project area.
6. Unrestricted spacing between wells drilled to develop the NOP within the PU will allow
for optimal well placement and reduce the administrative burden on the operator and the
AOGCC. However, the property line set-back distances of 20 AAC 25.055 will not be
automatically waived.
7. Correlative rights of owners and landowners of offset acreage will be protected by a
500-foot set-back requirement from a property line where landowners and owners are not
the same. However, this may not ensure the maximum ultimate recovery due to potential
waste of resources along these property lines. Under certain circumstances getting a waiver
to allow a well to be drilled within 500’ of a property line may allow for an increase in
ultimate recovery while at the same time still protecting correlative rights.
8. Coordination of development along unit property lines between OSA and offset operators
is necessary to reduce the potential for waste of resources in these areas.
9. Water-alternating-gas injection into the NOP will preserve reservoir energy and increase
ultimate recovery.
10. There has been a significant amount of geological information collected in the project area
and as such requiring all wells to be logged in accordance with 20 AAC 25.071(a) would
not significantly add to the geologic understanding in the area. Logging and sampling in
accordance with this regulation for a single well on each drillsite will provide adequate
information. Additional logging may be required at AOGCC’s discretion to support future
modifications of these rules.
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11. Granting OSA’s requested Directional Wellbore Plan waiver in lieu of 20 AAC 25.050(b)
will ensure equally accurate surveillance of the wellbore to prevent well intersection,
compliance with spacing requirements, and protection of correlative rights.
12. A GOR limitation waiver is appropriate because the NOP will be developed as a water-
alternating--gas enhanced oil recovery project and produced gas will be reinjected.
13. OSA’s proposed Administrative Action rule is unnecessary as 20 AAC 25.556(d) already
provides the AOGCC with the authority to administratively amend, under certain
conditions, any order it issues.
NOW THEREFORE IT IS ORDERED:
Development and operation of the Nanushuk 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 10 North, Range 5 East Sections 2-4 – All
Section 5 – E1/2, SE1/4NW1/4, E1/2SW1/4,
and SW1/4SW1/4
Township 11 North, Range 5 East Section 1 – E1/2 and E1/2W1/4
Sections 12-13 – All
Section 14 – E1/2, E1/2NW1/4, SW1/4NW1/4
and SW1/4
Section 15 – SE1/4SE1/4
Section 22 – E1/2, E1/2SW1/4, and
SW1/4SW1/4
Sections 23-27 – All
Sections 34-36 – All
Township 11 North, Range 6 East Sections 1-12 – All
Sections 17-20 – All
Township 12 North, Range 5 East Sections 24-25 – All
Section 26 – NE1/4, NE1/4NW1/4, and
E1/2SE1/4
Section 36 – N1/2. N1/2SW1/4, SE1/4SW1/4,
and SE1/4
Township 12 North, Range 6 East All
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Township 13 North, Range 5 East Sections 1-3 - All
Sections 11-14 – All
Sections 23-25 - All
Township 13 North, Range 6 East Sections 1-2 – All
Sections 6-36 – All
Township 14 North, Range 5 East Sections 24-27 - All tide and submerged lands
lying shoreward of the line fixed by
coordinates found in Exhibit A of the Final
Decree in U.S. v. Alaska, No. 84 Original
Sections 34-36 - All
Township 14 North, Range 6 East Section 19 – All tide and submerged lands
lying shoreward of the line fixed by
coordinates found in Exhibit A of the Final
Decree in U.S. v. Alaska, No. 84 Original
Sections 30 & 31 - All
Rule 1 Field and Pool Name
The field is the Pikka Field. Hydrocarbons underlying the PU that are in communication with and
correlate to the interval identified in Rule 2, below, constitute the Nanushuk Oil Pool (NOP).
Rule 2 Pool Definition
The NOP is defined as the accumulation of oil and gas common to and correlating with the interval
between the measured depths of 3,829 and 5,166 feet in the Qugruk 3 well (API No. 50-103-
20664-00-00; see Figure 2, above.)
Rule 3 Well Spacing
There shall be no restrictions as to well spacing except that no pay shall be opened to a well within
500 feet of an external property line where the owners and landowners are not the same on both
sides of the line.
Rule 4 Drilling Waivers
All permit to drill applications for deviated wells within the NOP shall include a plat with a plan
view, vertical section, close approach data and a directional program description in lieu of the
requirements of 20 AAC 25.050(b).
Rule 5 Well Logging and Sampling Requirements
a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron
porosity, and density porosity logs shall be acquired across the NOP in one well from each
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drill site. Gamma ray and resistivity curves shall be recorded from base of conductor to
total depth in each well. The AOGCC may require additional wells to be logged using one
or more petrophysical logging tools.
b. A mud log and cutting samples shall be obtained from the base of the conductor through
the NOP in at least one well drilled from each drill site.
Rule 6 Casing and Cementing Practices
The Tuluvak formation will be isolated with cement to prevent movement of its significant
hydrocarbon accumulation.
Rule 7 Well Safety Valve Systems
All wells drilled within the NOP will abide by the regulations set forth in 20 AAC 25.265 with the
following modification to 20 AAC 25.265(d)(5) for all injection wells (except disposal).
Nipple profiles will be installed to allow for subsurface injection check valves in gas and Water-
Alternating-Gas (WAG) injection wells.
Rule 8 Injection Well Completion
a. Packers in injection wells may be located more than 200 feet measured depth above the top
of the injection zone; however, packers must not be located above the confining zone. In
cases where the distance is more than 200 feet, the production casing cement volume
should be sufficient to place cement a minimum 300 feet measured depth above the planned
packer depth.
b. An approved injection order is required prior to commencement of injection in this pool.
Rule 9 Reservoir Pressure Monitoring
a. A bottom-hole pressure survey shall be taken on each well prior to initial sustained
production or injection.
b. The operator shall obtain pressure surveys as needed to effectively manage hydrocarbon
recovery processes subject to an annual plan outline in paragraph (e) of this rule.
c. The reservoir pressure datum will be 4,100 feet TVDSS for the NOP.
d. Pressure surveys may consist of stabilized static bottom-hole pressure measurements,
pressure fall-off, pressure build-up, multi-rate tests and formation tests or other appropriate
technical pressure transient or static tests, or other methods approved by the AOGCC.
e. Data from all surveys conducted during a calendar year shall be filed with the AOGCC
along with the annual reservoir surveillance report required by Rule 11 below by April 1st
of the subsequent year. Along with the survey submittal, the operator will provide a
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proposed survey plan for the upcoming year. The proposed plan shall be deemed accepted
if the operator has not received written correspondence from the AOGCC stating otherwise
within 45 days.
f. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant
data shall be attached to the report. The data submitted shall include, at a minimum, rate,
pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a
complete analysis of each survey being conducted. The 10-412 shall be submitted by April
1st of each year.
g. The results and data from any special reservoir pressure monitoring tests or surveys shall
also be submitted in accordance with paragraph (e) of this rule.
Rule 10 Gas-Oil Ratio Exemption
Wells producing from the NOP are exempt from the GOR limits of 20 AAC 25.240(a) as long as
an enhanced oil recovery project is underway in the NOP and/or produced gas is reinjected.
Rule 11Annual Reservoir Surveillance Report
An annual reservoir surveillance report must be filed on or before April 1st of each year. The report
shall include an overview of reservoir performance, future development and reservoir depletion
plans, and surveillance information for the prior calendar year. Report details shall include the
following:
a. Reservoir pressure maps at datum.
b. Summary and analysis of reservoir pressure surveys.
c. Reservoir pressure estimates.
d. Results and, where appropriate, analysis of production, temperature, tracer surveys,
observation well surveys, and any other special monitoring surveys.
e. Estimates of yearly production and the reservoir voidage balance of injection and
withdrawals at standard and reservoir conditions.
f. Progress of plans and tests to expand the productive limits of the pool.
g. Progress towards sanctioning additional drillsites.
Rule 12 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.
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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
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 July 20, 2023.
Brett W. Huber, Sr. Jessie L. Chmielowski Gregory C. Wilson
Chair, Commissioner Commissioner Commissioner
Gregory
Wilson
Digitally signed by
Gregory Wilson
Date: 2023.07.20
14:09:29 -08'00'
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2023.07.20
14:47:57 -08'00'
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.20
19:06:11 -05'00'
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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.
From:Carlisle, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] Conservation Order 807 (OilSearch)
Date:Thursday, July 20, 2023 4:16:33 PM
Attachments:co 807.pdf
THE APPLICATION OF Oil Search (Alaska), LLC for an order for classification of a new oil
pool and to prescribe pool rules for development of the proposed Nanushuk Oil Pool
within the Pikka Unit
Samantha Carlisle
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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STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 W. 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF Oil
Search (Alaska), LLC for an order
for classification of a new oil pool
and to prescribe pool rules for
development of the proposed
Nanushuk Oil Pool within the
Pikka Unit
)
)
)
)
)
)
)
)
Conservation Order 807
Nanushuk Oil Pool
Pikka Unit
North Slope Borough, Alaska
August 21, 2024
ERRATA NOTICE
The Alaska Oil and Gas Conservation Commission (AOGCC) notes that Conservation Order No.
807 had a typo in the legal description of the affected area. Namely, in the legal description of
the affected area in Township 11 North, Range 5 East it states “Section 1 – E1/2 and
E1/2W1/4” when it should read “Section 1 – E1/2 and E1/2W1/2”. This correction will be
reflected in a Conservation Order No. 807 Errata to be issued by the AOGCC.
DONE at Anchorage, Alaska and dated August 21, 2024.
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.08.21 13:52:47 -08'00'Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.08.21 14:21:21 -08'00'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage, Alaska 99501
Re: THE APPLICATION OF Oil Search
(Alaska), LLC for an order for
classification of a new oil pool and to
prescribe pool rules for development of
the proposed Nanushuk Oil Pool within
the Pikka Unit
)
)
)
)
)
)
)
)
)
Docket Number: CO-23-003
Conservation Order 807 Errata
Nanushuk Oil Pool
Pikka Unit
North Slope Borough, Alaska
Nunc pro tunc July 20, 2023
August 21, 2024
IT APPEARING THAT:
1. By application received March 7, 2023, Oil Search (Alaska), LLC (OSA), a subsidiary of
Santos Ltd (Santos), as operator of the Pikka Unit (PU), requested an order defining a new
oil pool, the Nanushuk Oil Pool (NOP), within the PU 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 April 18, 2023. On March 14, 2023, 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 March 16, 2023, the notice was also published in
the Anchorage Daily News.
3. No public comments on the application were received.
4. The hearing commenced at 10:00 a.m. on April 18, 2023. Testimony was received from
representatives of OSA.
5. The record was closed at the end of the hearing.
FINDINGS:
1. Owners and Landowners: Surface owners in the proposed NOP area are Kuukpik
Corporation, the State of Alaska, heirs, devisees and/or assigns of Neil Allen, Katherine
Brown, Jim T. Allen, and the estate of Helen E. Tukle. Subsurface owners of the NOP are
Alaska Department of Natural Resources (DNR) and the Arctic Slope Regional
Corporation. OSA and Repsol E&P USA LLC (Repsol) are the working interest owners
of the leased acreage within the proposed Affected Area, as defined below.
2. Operator: OSA is operator of all the leased acreage in the proposed Affected Area.
3. Affected Area: OSA is proposing that the Affected Area encompass the entirety of the PU,
which lies between the Colville River Unit (CRU) to the west, the Kuparuk River,
Oooguruk, and Quokka Units to the east, the Beaufort Sea to the north and non-unitized
state lands to the south. The unit lies mostly onshore on the North Slope of Alaska but also
extends onto state submerged lands in the Beaufort Sea.
CO 807 Errata
August 21, 2024
Page 2 of 15
4. Exploration and Delineation History: OSA, along with predecessor operators Repsol and
Armstrong Energy, LLC., have conducted significant exploration activity in the project
area. More than 20 wells have penetrated the Nanushuk Formation in the area and 6 of
these had successful flow tests and 4 collected cores from the Nanushuk Formation. Key
wells used to define the NOP include the Qugruk-3, Qugruk-3A, Qugruk-7, Qugruk-301,
Qugruk-8, Qugruk-9, Qugruk-9A, Fiord-2, Fiord-3, Pikka B, and Pikka C.
CO 807 Errata
August 21, 2024
Page 3 of 15
Figure 1. Pikka Project Area Showing Unit Boundary, Leases, Exploratory Wells, and Development
Infrastructure (Source: Oil Search (Alaska), LLC)
CO 807 Errata
August 21, 2024
Page 4 of 15
5. Pool Identification: As proposed, the NOP encompasses a thick accumulation of deltaic
shelf deposits that were time-equivalent to shale-dominated Torok Formation sediments
that were deposited in deeper water. The proposed NOP is the accumulation of
hydrocarbons common to and correlating with that portion of the Nanushuk Formation
(Nanushuk) shown on the Qugruk 3 reference log between 3,892 and 5,166 feet measured
depth (MD), which is equivalent to 3,785 and 4,985 feet true vertical depth below mean
sea level (also termed true vertical feet sub-sea, or TVDSS). OSA’s informally named
“Nanushuk 3” sandstone interval will be OSA’s primary development target, but towards
the western edge of the proposed NOP the underlying Nanushuk 2 interval becomes more
developed, and it may also be a development target.
CO 807 Errata
August 21, 2024
Page 5 of 15
Figure 2. Qugruk 3 type log (Source: Oil Search (Alaska), LLC)
CO 807 Errata
August 21, 2024
Page 6 of 15
6. Relationship to Nanushuk Developments in the CRU and KRU: At the public hearing,
OSA testified that the Nanushuk is composed of several imbricated, sand-rich, eastward-
prograding, top-set intervals. The axes of these intervals strike north-northeast and they off
lap progressively toward the east across the boundary between the CRU and the PU.
According to Conservation Order (CO) 605, CO 605A, and Area Injection Order (AIO)
No. 35, the Qannik Oil Pool (QOP) in ConocoPhillips Alaska, Inc.’s (CPAI) CRU
comprises sandstone intervals within the Nanushuk that are overlain and underlain by thick
shales and siltstones assigned to the Seabee and Torok Formations respectively. The QOP
was initially defined as the interval that correlates to 6,086 to 6,249 feet MD in the CRU
CD2-11 well (API 50-103-20515-00-00), and AIO 35 currently specifies this as the
approved injection interval. However, the QOP was subsequently expanded vertically by
CO 605A to include the interval from 6,030 to 6,249 feet MD in CRU CD2-11. CPAI’s
informally named Narwhal reservoir within the boundaries of the CRU produces from, and
injects into, the Nanushuk Formation. Enhanced Recovery Injection Order (ERIO) No. 6,
which authorized a pilot injection project in the Narwhal reservoir defines the Narwhal as
correlating to the interval of 4,192 to 5,152 feet MD in the Qugruk 3 well. So, as shown
by Figure 2, CPAI’s Narwhal reservoir is correlative with a portion of OSA’s requested
NOP (between 3,829- and 5,166-feet MD).
According to ERIO 8, CPAI’s informally named Coyote reservoir in the KRU is another
Nanushuk Formation development that is overlain by the Seabee Formation, underlain by
the Torok Formation, and correlates to the interval in the Palm 1 well (API No. 50-103-
20361-00-00) from 4.270 to 5.115 feet MD.
7. Geology:
a. Stratigraphy:
OSA’s proposed NOP is part of a large-scale, constructional, siliciclastic clinoform system
that prograded from west to east. The top set shelfal sediments constitute the Nanushuk
Formation, and the contemporaneous, slope-dominated sediments deposited along the east-
facing foreset slopes are assigned to the Torok Formation. Reservoir quality is greatest in
the sand-rich top set beds that were influenced by wave action on a marine shelf. Porosity
ranges from 4 to 28 percent and averages 17.5 percent, with permeabilities ranging from
0.01 to 660 millidarcies (mD) and averaging 60 mD. Water saturation ranges from 9 to 78
percent and averages 41 percent.
b. Structure:
The NOP structure is a monocline that dips gently to the east and is cut by only a small
number of faults that have minor vertical offsets.
c. Trap Configuration and Seals:
The hydrocarbon accumulation is contained by a stratigraphic trap, with along strike and
updip facies changes providing lateral seals and the overlying Seabee Formation, which is
about 1,000 feet thick in the planned development area, provides a top seal. Lower
confinement is provided by interbedded claystones, silty shales, and shale of the Torok
Formation, which has an aggregate thickness of approximately 250 feet in this area.
d. Permafrost Base:
The base of permafrost ranges between approximately -750 and -1,400 feet TVDss in the
planned development area.
CO 807 Errata
August 21, 2024
Page 7 of 15
8. Reservoir Fluid Contacts: Gas and water contacts have not been directly encountered
within the proposed NOP. Each oil accumulation region might have its own free water
level, which are currently estimated to lie to be between -4,950 and -5,280 feet TVDSS.
9. Reservoir Fluid Properties: OSA provided the following properties for samples from three
different accumulation regions within the planned development area.
Description Pikka B Qugruk 8 Pikka
C
Accumulation Region South Central North
Sample depth (feet TVDSS) -4,271 -4,185 -4,096
Reservoir Pressure (psia) 1,955 1,923 1,898
Reservoir Temperature (°F) 102 102 105
Stock tank oil API Gravity (°) 26.1 29.3 30.4
Gas oil ration (SCF/STB) 405 430 378
Bubble point pressure, Pb (psi) 1,609 1,561 1,631
Oil formation factor at Pb (RB/STB) 1.177 1.188 1.167
Oil viscosity at Pb (cP) 5.62 2.04 2.53
Oil Compressibility at Pb (1E-6/psi) 8.71 6.60 7.47
Gas gravity (multi-stage separator test) 0.842 0.829 0.768
Gas formation factor at Pb (RB/MSCF) 1.406 1.406 1.439
10. In-Place and Recoverable Reserves Volumes:
Nanushuk Reservoir Volume Range
(MMSTBO)
Original Oil in Place (OOIP) 2,297-2,814
Primary Recovery (<7% OOIP) 161-253
Primary + Waterflood (23% OOIP) 532-718
Primary + Water Alternating Gas (26-29% OOIP) 592-868
Predicted Recovery from NDB pad development only
(Primary + WAG ~37% OOIP)
~383
11. Reservoir Development Drilling Plan: OSA plans to develop the NOP in a phased manner.
Initially, 41 wells will be drilled from the central Nanushuk Drill Site B (NDB) and future
development may occur from two additional drill sites, the northern Nanushuk Drill Site A
(NDA) and the southern Nanushuk Drill Site C (NDC). A horizontal line drive water-
alternating-gas (WAG) development has been chosen. Due to the highly laminated nature
of the reservoir, all wells will be fracture stimulated to enhance productivity and improve
vertical injection sweep.
Most wells will trend northwest along the maximum principal stress direction of 330° to
improve waterflood performance. Wells will have horizontal sections of 3,000 to 8,000
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 1,800 feet between
producers and injectors will be optimal, but this is subject to change based on initial well
performance and the collection and analysis of addition geologic and engineering data.
Development drilling on the NDB will commence in Q2 or Q3 2023 and continue for
approximately 5 years. Extended-reach drilling (ERD) may occur later.
CO 807 Errata
August 21, 2024
Page 8 of 15
Existing and planned development wells that are used to develop the Nanushuk reservoirs
in the CRU and the PU are or will be truncated a minimum of 500 feet from the common
unit boundary in accordance with state spacing requirements.
12. Reservoir Management: OSA plans to develop the NOP WAG enhanced oil recovery
project with water initially coming from a new build seawater treatment plant and
eventually being supplemented with produced water when enough becomes available.
Produced gas will be reinjected. Production and injection voidage will be balanced to
maintain reservoir pressure at or near the original measured pressure. Development will
target a 1.0 voidage replacement ratio.
Due to the produced gas being reinjected, OSA expects the producing gas oil ratio (GOR)
will increase over time and eventually exceed twice the initial GOR, which is allowable
under 20 AAC 25.240(b) as, for development projects, the AOGCC may grant a waiver of
the GOR limit if a pool is being developed as an enhanced oil recovery (EOR) project or if
produced gas is being reinjected.
13. Reservoir Surveillance Plans: OSA proposes to meet bottom-hole pressure survey
requirements through the following reservoir pressure monitoring plan:
a. Static bottom-hole pressure surveys will be conducted in all new wells upon initial
completion.
b. For annual pressure surveillance, a minimum of one pressure survey will be conducted
annually from each drillsite, concentrating on injection wells.
c. Since lengthy horizontal wells require extended shut-in periods, often months long, to
achieve stabilized bottom-hole pressures, OSA proposes the following alternative
pressure survey methods below can be implemented.:
i. Producer pressure build-ups with bottom-hole pressure measurement,
ii. Injector pressure fall-off with bottom-hole or surface pressure measurement,
Pressures will be referenced to -4,100 feet TVDSS. All pressure surveys will be reported
annually.
14. Wellbore Construction: From the NDB, the NOP will be developed with wells that fall
into one of four tiers based primarily on the length of the well. Tier 1 and Tier 2 wells are
three-casing-string design wells with a 13-3/8” surface casing set at about 2,200 feet true
vertical depth (TVD) and cemented to surface, and a 9-5/8” intermediate casing set within
the Nanushuk. Tier 1 wells will be fully cemented from the casing shoe to a liner-top
packer (LTP) in the surface casing, while Tier 2 wells will utilize a two-stage cementing
operation: initially cement will be pumped around the casing shoe and then a stage tool
placed shallower in the casing string will be opened to place cement across the known
shallow hydrocarbon bearing sands in the Tuluvak and continuing upward to an LTP in the
surface casing. Tier 1 and 2 wells will then be completed with a 4-1/2” solid liner with
hydraulic fracturing sleeves and swell packers that will be hung in the intermediate string
with a LTP.
Tier 3 wells are a slim hole, four-casing-string design with a 13-3/8” surface casing set at
about 2,200 feet TVD and cemented to surface. A 9-5/8” intermediate 1 liner will be set
along the tangent of the well and cemented using a one- or two-stage cementing operation
as described for the Tier 1 and Tier 2 wells. A 7” intermediate 2 liner will land in the
CO 807 Errata
August 21, 2024
Page 9 of 15
Nanushuk, cemented at the shoe, and tied into Intermediate 1 with an LTP. The wells will
then be completed with a solid 4-1/2” liner as described for Tier 1 and Tier 2 wells.
The very long Tier 4 wells will employ a large bore, four-casing-string design, and will
require a different rig of greater capacity to drill and complete. These wells would be
completed similarly to the Tier 3 wells except that the casing strings are enlarged to 18-
5/8” surface casing, 13-3/8” Intermediate 1 liner, and 9-5/8” Intermediate 2 liner. The
wells would be completed with the same 4-1/2” production liner that the Tier 1 to 3 wells
employ.
15. Metering and Measurement Processes: Well testing and production allocation will be
conducted with a multiphase meter. Custody transfer metering will occur after production
is processed to sales quality in the Nanushuk Production Facility.
16. Waivers: OSA requested the following waivers:
a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells
in the proposed NOP to accommodate horizontal, line-drive wells and maximize
ultimate recovery. Without prior approval, development wells will not be completed
any closer than 500 feet to an external boundary where ownership and/or
landownership changes.
b. Directional Wellbore Plans: In lieu of the requirements of 20 AAC 25.050(b), permit
to drill application(s) shall include: plan view, vertical section, close approach data,
and directional data.
c. Gas-Oil Ratio (GOR) Exemption: an exemption from the GOR limits of 20 AAC
25.240 to accommodate water-alternating-gas-injection for oil recovery.
d. Well Logging: In lieu of the requirements of 20 AAC 25.071(a), one well per drill site
is required to be logged for the portion of the well below the conductor pipe by an
MWD log suite since additional logs won’t appreciably add to the geologic knowledge
of the area.
17. Interwell Spacing Requirements: Effective September 27, 2022, the statute governing
interwell spacing was changed and interwell spacing requirements were eliminated.
However, property line set back requirements were unchanged.
CONCLUSIONS:
1. The Nanushuk Formation across the CRU and PU comprises a single oil pool per AOGCC
statutes.
2. There are currently two operators spread across three units that are or will be producing
from the Nanushuk Formation, and these numbers may increase in the future.
3. Pool rules that are limited to a single pool and operator are appropriate to allow OSA and
CPAI to develop their portions of the Nanushuk Formation in the manner that they deem
appropriate.
4. Pool rules for the development of the proposed NOP within the PU are appropriate.
5. The Tuluvak Formation is a significant hydrocarbon bearing zone in the project area.
6. Unrestricted spacing between wells drilled to develop the NOP within the PU will allow
for optimal well placement and reduce the administrative burden on the operator and the
CO 807 Errata
August 21, 2024
Page 10 of 15
AOGCC. However, the property line set-back distances of 20 AAC 25.055 will not be
automatically waived.
7. Correlative rights of owners and landowners of offset acreage will be protected by a
500-foot set-back requirement from a property line where landowners and owners are not
the same. However, this may not ensure the maximum ultimate recovery due to potential
waste of resources along these property lines. Under certain circumstances getting a waiver
to allow a well to be drilled within 500’ of a property line may allow for an increase in
ultimate recovery while at the same time still protecting correlative rights.
8. Coordination of development along unit property lines between OSA and offset operators
is necessary to reduce the potential for waste of resources in these areas.
9. Water-alternating-gas injection into the NOP will preserve reservoir energy and increase
ultimate recovery.
10. There has been a significant amount of geological information collected in the project area
and as such requiring all wells to be logged in accordance with 20 AAC 25.071(a) would
not significantly add to the geologic understanding in the area. Logging and sampling in
accordance with this regulation for a single well on each drillsite will provide adequate
information. Additional logging may be required at AOGCC’s discretion to support future
modifications of these rules.
11. Granting OSA’s requested Directional Wellbore Plan waiver in lieu of 20 AAC 25.050(b)
will ensure equally accurate surveillance of the wellbore to prevent well intersection,
compliance with spacing requirements, and protection of correlative rights.
12. A GOR limitation waiver is appropriate because the NOP will be developed as a water-
alternating--gas enhanced oil recovery project and produced gas will be reinjected.
13. OSA’s proposed Administrative Action rule is unnecessary as 20 AAC 25.556(d) already
provides the AOGCC with the authority to administratively amend, under certain
conditions, any order it issues.
NOW THEREFORE IT IS ORDERED:
Development and operation of the Nanushuk Oil Pool is subject to the following rules and the
statewide requirements under 20 AAC 25 to the extent not superseded by these rules:
CO 807 Errata
August 21, 2024
Page 11 of 15
Affected Area: Umiat Meridian (See Figure 1)
Township 10 North, Range 5 East Sections 2-4 – All
Section 5 – E1/2, SE1/4NW1/4, E1/2SW1/4,
and SW1/4SW1/4
Township 11 North, Range 5 East Section 1 – E1/2 and E1/2W1/2
Sections 12-13 – All
Section 14 – E1/2, E1/2NW1/4, SW1/4NW1/4
and SW1/4
Section 15 – SE1/4SE1/4
Section 22 – E1/2, E1/2SW1/4, and
SW1/4SW1/4
Sections 23-27 – All
Sections 34-36 – All
Township 11 North, Range 6 East Sections 1-12 – All
Sections 17-20 – All
Township 12 North, Range 5 East Sections 24-25 – All
Section 26 – NE1/4, NE1/4NW1/4, and
E1/2SE1/4
Section 36 – N1/2. N1/2SW1/4, SE1/4SW1/4,
and SE1/4
Township 12 North, Range 6 East All
Township 13 North, Range 5 East Sections 1-3 - All
Sections 11-14 – All
Sections 23-25 - All
Township 13 North, Range 6 East Sections 1-2 – All
Sections 6-36 – All
Township 14 North, Range 5 East Sections 24-27 - All tide and submerged lands
lying shoreward of the line fixed by
coordinates found in Exhibit A of the Final
Decree in U.S. v. Alaska, No. 84 Original
Sections 34-36 - All
Township 14 North, Range 6 East Section 19 – All tide and submerged lands
lying shoreward of the line fixed by
coordinates found in Exhibit A of the Final
Decree in U.S. v. Alaska, No. 84 Original
Sections 30 & 31 - All
CO 807 Errata
August 21, 2024
Page 12 of 15
Rule 1 Field and Pool Name
The field is the Pikka Field. Hydrocarbons underlying the PU that are in communication with and
correlate to the interval identified in Rule 2, below, constitute the Nanushuk Oil Pool (NOP).
Rule 2 Pool Definition
The NOP is defined as the accumulation of oil and gas common to and correlating with the interval
between the measured depths of 3,829 and 5,166 feet in the Qugruk 3 well (API No. 50-103-
20664-00-00; see Figure 2, above.)
Rule 3 Well Spacing
There shall be no restrictions as to well spacing except that no pay shall be opened to a well within
500 feet of an external property line where the owners and landowners are not the same on both
sides of the line.
Rule 4 Drilling Waivers
All permit to drill applications for deviated wells within the NOP shall include a plat with a plan
view, vertical section, close approach data and a directional program description in lieu of the
requirements of 20 AAC 25.050(b).
Rule 5 Well Logging and Sampling Requirements
a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron
porosity, and density porosity logs shall be acquired across the NOP in one well from each
drill site. Gamma ray and resistivity curves shall be recorded from base of conductor to
total depth in each well. The AOGCC may require additional wells to be logged using one
or more petrophysical logging tools.
b. A mud log and cutting samples shall be obtained from the base of the conductor through
the NOP in at least one well drilled from each drill site.
Rule 6 Casing and Cementing Practices
The Tuluvak formation will be isolated with cement to prevent movement of its significant
hydrocarbon accumulation.
Rule 7 Well Safety Valve Systems
All wells drilled within the NOP will abide by the regulations set forth in 20 AAC 25.265 with the
following modification to 20 AAC 25.265(d)(5) for all injection wells (except disposal).
Nipple profiles will be installed to allow for subsurface injection check valves in gas and Water-
Alternating-Gas (WAG) injection wells.
Rule 8 Injection Well Completion
a. Packers in injection wells may be located more than 200 feet measured depth above the top
of the injection zone; however, packers must not be located above the confining zone. In
cases where the distance is more than 200 feet, the production casing cement volume
should be sufficient to place cement a minimum 300 feet measured depth above the planned
packer depth.
b. An approved injection order is required prior to commencement of injection in this pool.
CO 807 Errata
August 21, 2024
Page 13 of 15
Rule 9 Reservoir Pressure Monitoring
a. A bottom-hole pressure survey shall be taken on each well prior to initial sustained
production or injection.
b. The operator shall obtain pressure surveys as needed to effectively manage hydrocarbon
recovery processes subject to an annual plan outline in paragraph (e) of this rule.
c. The reservoir pressure datum will be 4,100 feet TVDSS for the NOP.
d. Pressure surveys may consist of stabilized static bottom-hole pressure measurements,
pressure fall-off, pressure build-up, multi-rate tests and formation tests or other appropriate
technical pressure transient or static tests, or other methods approved by the AOGCC.
e. Data from all surveys conducted during a calendar year shall be filed with the AOGCC
along with the annual reservoir surveillance report required by Rule 11 below by April 1st
of the subsequent year. Along with the survey submittal, the operator will provide a
proposed survey plan for the upcoming year. The proposed plan shall be deemed accepted
if the operator has not received written correspondence from the AOGCC stating otherwise
within 45 days.
f. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant
data shall be attached to the report. The data submitted shall include, at a minimum, rate,
pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a
complete analysis of each survey being conducted. The 10-412 shall be submitted by April
1st of each year.
g. The results and data from any special reservoir pressure monitoring tests or surveys shall
also be submitted in accordance with paragraph (e) of this rule.
Rule 10 Gas-Oil Ratio Exemption
Wells producing from the NOP are exempt from the GOR limits of 20 AAC 25.240(a) as long as
an enhanced oil recovery project is underway in the NOP and/or produced gas is reinjected.
Rule 11Annual Reservoir Surveillance Report
An annual reservoir surveillance report must be filed on or before April 1st of each year. The report
shall include an overview of reservoir performance, future development and reservoir depletion
plans, and surveillance information for the prior calendar year. Report details shall include the
following:
a. Reservoir pressure maps at datum.
b. Summary and analysis of reservoir pressure surveys.
c. Reservoir pressure estimates.
d. Results and, where appropriate, analysis of production, temperature, tracer surveys,
observation well surveys, and any other special monitoring surveys.
e. Estimates of yearly production and the reservoir voidage balance of injection and
withdrawals at standard and reservoir conditions.
f. Progress of plans and tests to expand the productive limits of the pool.
g. Progress towards sanctioning additional drillsites.
CO 807 Errata
August 21, 2024
Page 14 of 15
Rule 12 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
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 August 21, 2024.
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.08.21
13:53:20 -08'00'
Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.08.21 14:20:30 -08'00'
CO 807 Errata
August 21, 2024
Page 15 of 15
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.
3
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ALASKA OIL AND GAS CONSERVATION COMMISSION
In the Matter of Oil Search Alaska, LLC.,)
Application to Establish Pool Rules for )
Nanushuk Oil Pool )
_________________________________________)
Docket No.: CO-23-003
PUBLIC HEARING
April 18, 2023
10:00 o'clock a.m.
BEFORE: Jessie Chmielowski, Commissioner
Greg Wilson, Commissioner
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1 TABLE OF CONTENTS
2 Opening remarks by Commissioner Chmielowski 03
3 Mr. Bond 06
4 Mr. Jones 07
5 Mr. Noll 08
6 Mr. Tirpack 42
7 Mr. Cook 56
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
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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: It's approximately
4 10:00 a.m., on Tuesday April 18th, 2023. This is a
5 public hearing on Docket Number CO-23-003 to consider
6 Oil Search Alaska LLC's Application to Establish Pool
7 Rules for Nanushuk Oil Pool.
8 I am Commissioner Chmielowski and with me is
9 Commissioner Greg Wilson. Today's hearing is being
10 held in person and via Microsoft Teams. The in person
11 location is the Alaska Oil and Gas Conservation
12 Commission Office at 333 West 7th Avenue, Anchorage,
13 Alaska. For those on Teams please be mindful of any
14 background noise and make sure you are muted when you
15 are not testifying or addressing the Commission.
16 If you require any special accommodation,
17 please contact Samantha Carlisle. She can be reached
18 at 907-793-1223 or send her a message through the
19 Microsoft Teams chat icon and she will do her best to
20 accommodate you. Samantha Carlisle will be recording
21 the hearing. Upon completion and preparation of the
22 transcript, persons desiring a copy will be able to
23 obtain it by contacting Computer Matrix.
24 This hearing is being held in accordance with
25 Alaska Statute 44.62 and 20 AAC 25.540 of the
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1 Administration Code.
2 The notice for today's hearing was published on
3 the State of Alaska Online Notices website as well as
4 the AOGCC website and was sent through the AOGCC Email
5 List Serv on March 14th, 2023. The AOGCC also
6 published the notice in the Anchorage Daily News on
7 March 16th, 2023.
8 Pool rules are applied for under 20 AAC 25.520
9 for the purpose of prescribing rules that differ from
10 the normal statewide rules found in 20 AAC 25 for the
11 development of a defined pool. The rules are
12 established to streamline the development of the pools
13 while still protecting correlative rights and ensuring
14 maximum recovery. A pool is an underground reservoirs
15 containing or appearing to contain a common
16 accumulation of oil and/or gas. Absent an order to the
17 contrary the statewide rules found in 20 ACC 25 govern
18 development of oil and gas pools. However, sometimes
19 an operator will apply to the AOGCC for an order to
20 establish pool rules to govern a specific pool. Pool
21 rules typically define a vertical and map extent of a
22 particular pool and establish rules that modify the
23 statewide regulations to enable more efficient
24 operations while providing an equally effective means
25 of protecting underground fresh water, protecting
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1 correlative* rights and conducting safe and
2 environmentally sound operations. Oil Search Alaska is
3 applying for rules related to well construction, safety
4 valves and reservoir operations.
5 To date the AOGCC has not received any public
6 comments on this matter.
7 Before asking Oil Search to begin their
8 presentation, Commissioner Wilson, do you have any
9 questions or comments?
10 COMMISSIONER WILSON: Nothing additional.
11 COMMISSIONER CHMIELOWSKI: All right. The
12 Commissioners will ask questions during the testimony.
13 We may also take a recess to consult with Staff to
14 determine whether additional information or clarifying
15 questions are needed. Representatives from Oil Search,
16 are you ready to make your presentation?
17 (No audible response)
18 COMMISSIONER CHMIELOWSKI: Great. So it looks
19 like there are five of you planning to testify so I
20 will swear you in, all of you at once. So if you
21 could, please, all raise your right hands.
22 (Oath administered)
23 (No audible response - no microphone)
24 COMMISSIONER CHMIELOWSKI: Okay. Let the
25 record reflect that witnesses all responded in the
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1 affirmative. Now, do any of you wish to be recognized
2 as experts. Okay, it's up to you, at your discretion,
3 not necessary.
4 (No audible response - no microphone)
5 COMMISSIONER CHMIELOWSKI: Okay. Yeah, sorry,
6 I didn't get to this yet, but the microphones, the
7 green button should be bright bright green and you have
8 to speak kind of close to the microphone and it's going
9 to sound kind of like I am, a little bit almost too
10 loud, that's so the people online can hear you.
11 MR. BOND: Okay.
12 COMMISSIONER CHMIELOWSKI: Okay. So for those
13 testifying please keep in mind that you must speak into
14 the microphone. Also remember to reference your slides
15 so that someone reading the public record can follow
16 along. For example, refer to slides by their numbers,
17 if numbered, or by their titles, if not numbered. And
18 as you speak and as you change speakers, please state
19 your names and job titles clearly for the record.
20 So if you're all set then please begin.
21 MR. BOND: Great. All right, thank you very
22 much. My name is Andy Bond. I'm a subsurface
23 engineering manager for Santos.
24 COMMISSIONER CHMIELOWSKI: Is your -- let's
25 check your microphone, is there enough volume there,
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1 you're okay -- okay, great. Thank you.
2 MR. BOND: Okay. Great. We want to thank you
3 for the time this morning. We have about an hour's
4 worth of prepared materials in support of our pool
5 rules application.
6 So I'm going to move to Slide No. 2 here, which
7 is our presentation outline. We'll hand off first to
8 Tim Jones, who will go through the ownership and
9 development area. And then Christian will go through
10 our geoscience overview. I'll come back and give a
11 description of the reservoir and production and also
12 the surface facilities and then we'll wrap up with
13 drilling completions with Rob and Mark.
14 All right, so I'm going to hand off to Tim
15 here.
16 MR. JONES: Thank you, very much Andy. My name
17 is Tim Jones. I am the land manager for Oil Search
18 Alaska, also known as Santos.
19 I'm going to go to Slide No. 4, and briefly
20 describe the ownership of the proposed Nanushuk Oil
21 Pool area as well as the area itself. So the proposed
22 Nanushuk Oil Pool is coincident with the current Pikka
23 Unit, which is a DNR/ASRC oil and gas unit that was
24 formed initially in June of 2015 and expanded to its
25 current outline in late 2016. Santos, through its
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1 subsidiary Oil Search Alaska, LLC., is operator of the
2 unit and is also 51 percent working interest owner of
3 each of the leases within the unit. Repsol E&P USA
4 LLC., is a working interest owner who owns the
5 remaining 49 percent of each of the leases within the
6 unit area as well as in the proposed Nanushuk Oil Pool
7 area. The surface owners of the proposed oil pool area
8 include the Kuupik Corporation, also the State of
9 Alaska, the heirs devisees and/or assigns of Neil
10 Allen, Katherine Brown, Jim T. Allen, and the estate of
11 Helen E. Tukle. And as I stated previously the
12 proposed Nanushuk Oil Pool is the blue outline on the
13 slide as shown which coincides with the outline of the
14 Pikka Unit.
15 Unless there are any questions I'm going to go
16 ahead and turn it over to Christian Noll.
17 Thank you.
18 MR. NOLL: Thank you, Tim. My name is
19 Christian Noll, I'm the geoscience manager of Santos
20 and Oil Search Alaska LLC., so Andy if you could pass
21 to Slide No. 6. Thank you.
22 So Tim just walked you through, on the prior
23 slide, the aerial extent of the Nanushuk Oil Pool. To
24 the right-hand side of the slide you'll see the Qugruk-
25 3 type log in the Pikka Unit and we're defining there,
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1 the vertical extent of the Nanushuk Oil Pool, we
2 consider the vertical extent from the top of the
3 Nanushuk through to the Top Torok formation and so that
4 brings us to the upper confining layer which is the --
5 the top of the Nanushuk is the -- the marker that
6 defines the top of the -- of the pool, the confining
7 layer is the lower seabee formation, that's the shale-
8 dominated marine flooding surface comprising condensed
9 mudstone facies and overlying shale that is around a
10 thousand feet thick that defines that confining layer
11 to the Nanushuk Oil Pool. The base of the pool is
12 defined by that Top Torok formation marker that you can
13 see in red on the right-hand side, that is effectively
14 the base of the target management formation comprising
15 shale-dominated sequences that are around 250 feet TVT
16 thick. And that's the vertical extent of the Nanushuk
17 Oil Pool.
18 Moving ahead to Slide No. 7.....
19 COMMISSIONER CHMIELOWSKI: Excuse me, I had a
20 quick question on that previous slide.
21 MR. NOLL: Sure.
22 COMMISSIONER CHMIELOWSKI: You identify the top
23 of the NT3, what do you -- what do you call between the
24 NT3 and the Top Nanushuk there?
25 MR. NOLL: The top of the Nanushuk 3 and the
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1 top of the Nanushuk is what we regard as the upper
2 Nanushuk. It's the -- it's the thin shelf equivalent
3 of -- of the section that expands into the Nanushuk 4,
4 5, 6 and 7 on the eastern side of the Pikka unit.
5 COMMISSIONER CHMIELOWSKI: Okay, thank you.
6 MR. NOLL: Yep.
7 COMMISSIONER WILSON: I guess I do have a
8 question, regarding your Top Torok pic, just curious,
9 is that sequence just below the red marker, is that
10 seismically defined then?
11 MR. NOLL: It is. It's seismically defined,
12 the top of the Torok, we also define.....
13 (Background disturbance)
14 MR. NOLL: .....it by (indiscernible) sequences
15 not only from seismic by, it's by well control also.
16 So the Torok we regard as sort of the bottom set shale
17 equivalent of the top set shelf or sandstone of the --
18 of the Nanushuk so in.....
19 (Background disturbance)
20 MR. NOLL: .....in -- it is defined from
21 (indiscernible). And I'll expand on that, just that --
22 that same question here on moving ahead to Slide No. 7.
23 So this is just an expanded view of the
24 stratigraphy through the.....
25 (Background disturbance)
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1 MR. NOLL: .....unit in a little more of its
2 entirety through the cretaceous section (indiscernible)
3 bottoms up and work through the stratigraphy, if I can
4 find the map there, the HRZ, above the HRZ stepping
5 through the Torok formation, which is dominated by
6 mostly slope deposits and bottom set equivalence of the
7 -- of the management formation which is embedded,
8 embedded sandstones, soapstones and shale, top of the
9 Nanushuk is -- is here, this is the -- again, the Q-3
10 type section, the upper confining layer to the Nanushuk
11 Oil Pool is the -- the claystone dominated Seabee
12 formation, which does have intermittent volcanic tuff
13 throughout that section and is, as I mentioned, around
14 a thousand feet thick.
15 Stepping up into the Tuluvak formation, which
16 we regard as the -- as the shale equivalent, all the --
17 the down dip, shale-dominated Seabee formation
18 interbedded sandstone, siltstone dominated and
19 interbedded clays within the Tuluvak formation,
20 stepping through the MCU into the slightly coarser
21 grain middle schrader, and upper schrader bluff
22 formation which is dominated by unconsolidated sand and
23 -- and gravels with minor clays in the -- in the upper
24 schrader bluff and into the Prince Creek formation. So
25 in.....
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1 COMMISSIONER WILSON: I -- I have just a quick
2 geology question. But based on the thickness,
3 essentially of your top set face, your Nanushuk
4 reservoir in comparison to the slope faces of the
5 Torok, I mean would you say that this is the shelf
6 margin environment and that you're spilling down the
7 slope?
8 MR. NOLL: That's exactly right. I think
9 that's a great characterization. So we regard the
10 Nanushuk as the -- as the shelfal equivalent, it's
11 effectively the -- Nanushuk/Torok system is -- is one
12 system, part of the one formation, the Nanushuk is the
13 sandstone dominated shale equivalent (indiscernible) as
14 you spill out beyond the shelf margin on to the slope
15 and to the bottom of the slope you're in that shale-
16 dominated formation.
17 COMMISSIONER WILSON: Okay. Thank you.
18 MR. NOLL: And this -- so moving ahead to Slide
19 No. 8, so that -- this -- this slide sort of
20 illustrates that a little bit more. So we regard the
21 Nanushuk as the deltaic shelfal equivalent of that down
22 deeper water Torok equivalent that's dominated by -- by
23 claystones and shales. Deposition of that overall
24 Nanushuk/Torok system is overall west to east in a
25 large prograding clinoform system, it is reworked to
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1 some extent along that shelf. I've -- the shelf margin
2 is roughly coincident with -- with the structural
3 contour of 4250 on the structure map to the right-hand
4 side. So that -- that shelf margin is roughly north,
5 northeast.....
6 (Background interruption)
7 MR. NOLL: .....and that defines the overall
8 elongate reservoir geometry that you can see within the
9 Nanushuk 3 accumulation. That's as shallow as 3,900
10 feet subsurface TVD and as the structure map indicates
11 plunges off to the east. For all intents and purposes
12 that's sort of the development area of 3900 to 4250
13 feet of surface TVD at the top of the Nanushuk 3. The
14 trap we regard is an overall combined structural and
15 stratigraphic trap. It's stratigraphic component is
16 updip thinning to the west and shelfal termination of
17 those Nanushuk sands coincident with that shelf margin
18 downdip to the east setting up that stratigraphic trap.
19 And of course we do have a robust topseal with the
20 overlying Seabee formation that I indicated earlier,
21 the claystone and dominated Seabee. Lithology is fine
22 to very fine grained interbedded sandstone, silts and
23 clays. Oil quality ranges from roughly 24 to 30 API
24 oil gravities. Overall within the Nanushuk 3 we see
25 from -- from well control on average around 140 feet
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1 thick, pay averages across the NDB particularly,
2 sandstone porosity's are on the order of 22 percent,
3 permeability are quite good.....
4 (Background interruption)
5 MR. NOLL: .....on average around 60 mD, and
6 water saturation is fairly low at about 41 percent on
7 average within -- within the (indiscernible).
8 COMMISSIONER CHMIELOWSKI: Give us a quick
9 second here.
10 MR. NOLL: Sure.
11 COMMISSIONER CHMIELOWSKI: Go back to that --
12 great. So I think you're going to go into this later
13 but how do you interpret the API variability?
14 MR. NOLL: Yeah, that's a good question. So we
15 do see variability from the existing well control of 24
16 to 30 degree API. For all intents and purposes, and
17 I'll defer to Andy to fill with commentary also, we
18 regard the entire sort of map area that you see on the
19 right-hand side as including two main PVT (ph) so that
20 southern area is dominated by sort of monages, somewhat
21 amalgamated sands, as we step towards the north the --
22 it -- the character, the geology of that reservoir
23 varies slightly, reservoir quality diminishes northward
24 compared to say the Q-3 top section area that we
25 indicated on the prior side so it becomes a little,
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1 (indiscernible) decreases becomes a little more
2 (indiscernible) and we believe that may be
3 contributing, to some extent, to what you're seeing on
4 the API variability. It is all a shublik source, so it
5 is all sourced by that one shublik source.
6 COMMISSIONER CHMIELOWSKI: Great. And possibly
7 this is easier to understand on a 3D map, but when you
8 look at your well designs, it looks like there's almost
9 like half circles there towards the southern tip.
10 Could you just sort of describe what we're looking at.
11 MR. NOLL: Yeah. And -- and I can defer to Rob
12 here, I'll take a -- the trajectories you can see are
13 in plain view so that the -- the wells to the southern
14 most end of the NDB fan you can see each of the
15 development wells shown in -- shown in black with those
16 trajectories, you can see the appraisal wells on the
17 same map but the development wells, as you can see, the
18 wells to the southern most end, the well
19 (indiscernible) south, southwest and then the turns in
20 -- in half of those wells are to the east and you can
21 see the well turns to the northwest, so it's the --
22 you're superimposing two trajectories there that gives
23 you that impression into that.
24 COMMISSIONER CHMIELOWSKI: Right. Yeah, that's
25 what I thought but it's -- I just thought I'd clarify.
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1 MR. NOLL: Absolutely.
2 COMMISSIONER CHMIELOWSKI: Thank you.
3 MR. BOND: And I do have an API gravity versus
4 depth slide coming up later that we can discuss more.
5 COMMISSIONER CHMIELOWSKI: Okay, thanks.
6 MR. NOLL: Okay. Next Slide No. 9. Just a
7 quick overview of the petrophysical model when using
8 the Qugruk 8 well log here to indicate the
9 petrophysical evaluation of the Nanushuk. It is
10 overall a fairly thinly interbedded reservoir. What
11 you can see on the Q8 log display on the gamma-ray on
12 the left-hand side, you see a very striking upward
13 cleaning, upward coarsening motif associated with that
14 overall prograding clinoform succession. So that's
15 fairly characteristic of that type of deposition
16 environment so in essence we're seeing improved
17 reservoir quality towards the top of the Nanushuk 3
18 formation, which you can see there on the gamma ray.
19 We do invoke a thin bed petrophysical model in order to
20 handle the thinbed nature of the reservoir. That is
21 the (indiscernible) model that effectively strives to
22 remove the laminaclay volume from the reservoir. What
23 that does is it gives us a far better handle on not
24 only net to gross, an improved view of the shale, but
25 it gives us a better handle on the reservoir quality
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1 within the sandstone themselves by taking out that
2 extra clay volume. In this instance for Q8 we're
3 looking at -- on this well log we're looking at roughly
4 350 feet of section, as you can see net pay from that
5 petrophysical model is around 100 feet -- 105 feet,
6 excuse me. Sandstone porosities average, they're very
7 good in Q8 at 24 percent, average permeability is also
8 very good at -- on average 109 mD with low water
9 saturations as a result. And from a -- this is a well
10 that is hole (ph) cored, you can see the -- from that
11 hole (ph) core sampling we can look at the four prone
12 characteristics on the bottom right-hand side of the
13 slide, one mD equates to around 16.5 percent porosity,
14 that average porosity of 24 percent which is just a
15 little north of 100 mD on that same plot that indicates
16 a pretty good linear relationship on the
17 (indiscernible) characteristics.
18 COMMISSIONER WILSON: I'm just curious, how
19 does your vertical permeability compare to the
20 horizontal?
21 MR. NOLL: Yeah, that's a great question. So
22 vertical permeability can be very low in the
23 interbedded portions of the reservoir, so when we're in
24 the -- what we regard as the lower shale face, the
25 better quality rock within Q3, what was in Pikka B, for
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1 example, the reservoir is effectively homogenized by
2 fire (indiscernible) and wave reworking, so, therefore,
3 the KVs(ph) are quite good. It's strikingly different
4 to a Q8, which is a little more laminated and as we
5 step northward in the reservoir the thin interbeds
6 obviously break down that KV and it's very, very low as
7 a result.
8 So, thanks, Andy, moving ahead to Slide No.10.
9 This slide effectively characterizes the available
10 appraisal well dataset that we have at our disposal to
11 characterize the reservoir here on the Pikka unit and
12 we have 20 plus well penetrations, very good rock
13 sampling across three plus wells, greater than a
14 thousand feet of hole core to help classify the
15 depositional architecture, the faces architecture and,
16 of course the (indiscernible) saturation and scale
17 characteristics. 10 of those wells have RSCWs across
18 the structure, nine of those wells have high definition
19 image logs, those nine logs are important to help
20 constrain that thin bed petrophysical evaluation that I
21 alluded to earlier. And successful flow test data from
22 five plus wells across that structure. And if we look
23 at the map to the right-hand side, that's a map of net
24 reservoir. Yellows to reds are roughly greater than
25 100 feet of net reservoir within the Nanushuk 3 so you
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1 can see the development area as shown by trajectories
2 in that purple trajectory color, has not only very good
3 well control it is delineated by a combination of hole
4 core flow test information and high definition in logs,
5 including image logs to help (indiscernible) our
6 petrophysical models.
7 COMMISSIONER WILSON: How well would you say
8 your seismic correlation is to that net pay map?
9 MR. NOLL: So that's an excellent question and
10 there's a lot of detail behind that -- behind that --
11 behind the answer that I could give.
12 We -- so the seismic amplitudes are a guide for
13 reservoir quality, they're not -- we don't use the
14 seismic amplitudes -- we don't hardwire our geologic
15 models with amplitudes for example, we use that as a
16 very loose guide. Effectively what we're -- what we're
17 -- the methodology to define the reservoir
18 characteristics are a combination of geometry and
19 amplitude and of course well control. The seismic
20 geometries indicate the shelf margin positions, for
21 example, very well, so that is a clear tool in the way
22 we characterize the reservoir, inboard you're in the
23 shelfal position have better quality sands, outboard
24 you're.....
25 (Background interruption)
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1 MR. NOLL: .....shale-dominated portions of the
2 reservoir, so that geometry is -- is really key. To a
3 lesser extent amplitudes quite often support the shelf
4 margin determination. The linear nature of the
5 amplitude support, not only the shelf margin position
6 but give us a sense of where that -- where the linear
7 geometries on the amplitude exist, it gives us a hint
8 of wavery working in the -- in the tank system. So
9 that is just a loose guide. So 3D reservoir models are
10 concept based and well controlled based and defined by
11 that shelf margin and (indiscernible) structural
12 geometry.
13 COMMISSIONER CHMIELOWSKI: So looking at this
14 map, the one you have here in the right, is it true
15 that some of the developal oils is on the Colville
16 River unit leases owned by Conoco?
17 MR. NOLL: So this is a -- this map is a
18 combination net reservoir of both the Nanushuk 2 and
19 the Nanushuk 3 so we're combining both of those two
20 reservoirs within this map, and this net map is also
21 constrained to the uppermost 240 feet of the reservoir
22 itself, which is what we're -- which is the developed
23 layer -- developal area within the -- within the NDB
24 area that we're looking to develop. So it does include
25 the Nanushuk 2 which is the Conoco (ph) equivalent on
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1 the Colville River area.
2 COMMISSIONER CHMIELOWSKI: Okay.
3 MR. BOND: All right, any additional questions
4 on geology.
5 COMMISSIONER CHMIELOWSKI: I'm sure we will but
6 please move on.
7 MR. BOND: Okay. All right. So here's our
8 development well considerations.
9 COMMISSIONER CHMIELOWSKI: Please identify
10 yourself again please.
11 MR. BOND: I'm sorry, Andy Bond, again,
12 subsurface manager for Santos.
13 So our initial development from the NDB pad has
14 a total of 43 wells, 41 of which are Nanushuk wells and
15 two of which will be Alpine C wells. We'll be coming
16 back to you probably in about a year's time for pool
17 rules on the Alpine as those wells will be drilled
18 later in our drilling sequence. So, again, we have 41
19 wells, alternating rows of injectors and producers
20 here. And if you look at this cross section through AA
21 Prime here you could see a cross section through the
22 reservoir, in this particular position you can see we
23 have three wells that go across the entire structure so
24 we label these as a Bench 1, Bench 2 and a Bench 3 well
25 so that gives you an idea of how we're covering the
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1 entire section across there with the number of wells.
2 It ranges from two to three depending on how wide the
3 area is. Our well orientation is at 330 degrees and
4 this is based on some geomechanical work that we've
5 done. What we're trying to achieve is to have the well
6 bores aligned with the frac orientations so that we
7 achieve longitudinal fracs, that'll maximize the
8 distance between the injectors and producers to
9 maximize sweep efficiency.
10 Typically our Bench 1 and Bench 2 wells are
11 6,000 foot horizontal sections and we'll typically have
12 approximately 12 frac stages spaced about 500 feet
13 apart, in those laterals and then some of the Bench 3
14 wells do get a little bit longer and some of the
15 longer, Bench 2 wells, where we only have two wells,
16 those can be up to eight, up to 8,000 plus feet long.
17 Our interwell spacing is currently at 1,800 feet.
18 We've done a bunch of optimizations, simulation work to
19 arrive at that number. Potentially as we move our
20 development further to the southern end of this well
21 fan, these wells that are highlighted in this orange
22 cross hatch, we could potentially consider increasing
23 well spacing there and then we have another drill site
24 planned further south, which we call NDC, where we may
25 consider increased well spacing as the reservoir
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1 quality and permeability increase in that direction.
2 We plan to land our wells approximately 60 feet
3 below the top of the NT3, so you could see that again
4 on this cross sectional area and the goal there is we
5 want to land these wells near the base of that
6 amalgamated sand body that Christian talked about, that
7 gives us the best chance for good fracture initiation
8 as well as longterm connection between the reservoir
9 and the well bore if we can initiate those fractures in
10 a sandy interval versus a shaley interval.
11 We took into account a lot of factors on
12 determining our first years drilling order, it's a
13 giant Rubiks cube of about 19 different factors. One
14 of the key things is early data gathering, we want to
15 be able to determine reservoir quality and extent and
16 really validate our development plan as early as
17 possible. So we've got extra LDW and open hole logging
18 planned on our early wells. On one of our early wells
19 we also have a micro-seismic test planned to help us
20 identify the frac orientation as well as some
21 information on frac geometry because frac height is
22 very important for us as far as how much we can develop
23 with a single well. And we also plan interwell pulse
24 testing between a single well spacing distance and a
25 double well spacing distance and, again, this will help
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1 us determine reservoir connectivity as well as
2 permeability and help us to calibrate our reservoir
3 models.
4 COMMISSIONER WILSON: A couple of questions.
5 MR. BOND: Certainly.
6 COMMISSIONER WILSON: Under drill order you see
7 extra LWD and open hole logs -- logging. In your
8 application you request a waiver of 20 AAC 25.071(a) on
9 logging sweeps, instead proposing to use petrophysical
10 logs from nearby exploration wells, so do you want to
11 expand on that a little bit and kind of the -- why one
12 is suggesting more logs and the other is suggesting a
13 waiver?
14 MR. BOND: So the reason we're collecting more
15 early on is in the first handful of wells, maybe five
16 or six wells we want to collect as much information as
17 we can to get a better understanding of the reservoir,
18 make sure that our models are accurate and that our
19 development plan is sound, but then as we move forward
20 we'd like to be able to pare back that logging program
21 to, you know, more minimal levels once we have a better
22 understanding of the reservoir.
23 COMMISSIONER WILSON: And would that -- the
24 more logging be for the entirety for the B pad or would
25 there be lesser logs like with future development at C,
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1 that kind of thing, if you could elaborate there, just
2 a little bit.
3 MR. BOND: So I think once we move to new drill
4 sites, I suspect the first couple wells, again, we
5 would do some additional expanded logging programs, but
6 then try to, you know, pare back to more minimal
7 logging once we get a good understanding of those new
8 areas.
9 COMMISSIONER WILSON: So you're suggesting you
10 would pare back on the initial development at B?
11 MR. BOND: Oh, yes. Yeah. So right now this
12 expanded logging typically is going to be maybe in our
13 first six wells or so.
14 COMMISSIONER WILSON: And would you be
15 confident that you would be staying in reservoir, I
16 guess, with the offset wells then?
17 MR. BOND: Do you want to comment on that
18 Christian.
19 MR. NOLL: Yeah, that's a great question. So
20 we -- as you saw on the prior map we have pretty good
21 well control, the appraisal dataset is outstanding so
22 it gives us good control in -- across the NDB area so
23 we're confident of landing within reservoir, within the
24 -- within the development wells. Part of the early
25 data gathering is helping constrain the extent of sand
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1 towards that shelf margin, so on the eastern side of
2 the development towards the heels of our initial wells
3 in particular, that's where we're targeting some
4 additional expanding logging programs to better
5 understand the sand distribution in that eastern most
6 area but for the most part we have excellent well
7 control across the full NDB coverage.
8 COMMISSIONER WILSON: But are you suggesting
9 you would drill a development well with -- potentially
10 with no logs?
11 MR. NOLL: We are not. So later in the program
12 we pare it back to LWD, the initially wells are LWD but
13 you'll see a fairly standard LWD suite across all
14 wells.
15 COMMISSIONER WILSON: Okay. That's --
16 okay.....
17 COMMISSIONER CHMIELOWSKI: But just to be
18 clear, to include gamma-ray (indiscernible).....
19 MR. NOLL: Yeah, at the minimum we'd have is
20 gamma-rays, yes.
21 COMMISSIONER WILSON: That wasn't clear from
22 what I had read previous.
23 MR. NOLL: Yes.
24 MR. BOND: Okay, so here's the API gravity
25 story again. So on the lower left-hand corner we've
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1 got a plot here of -- oh, sorry, yeah, Slide No. 13.
2 This is the API gravity here on the X axis and depth on
3 the Y axis, so you can see we've got a pretty strong
4 correlation between API gravity and depth and I've seen
5 this at other reservoirs, Qugruk had the same API
6 gravity versus depth correlation and the Kuparuk River
7 field has the same API versus depth correlation. So
8 it's pretty common to see that in these reservoirs in
9 this particular area. What we see is, as Christian
10 mentioned, we've got two kind of API gravity areas that
11 we've built under our reservoir model, one to the north
12 and one to the south. Samples from the northern area
13 tend to have a little bit higher C8 through C10
14 fractions versus the ones to the south have a little
15 bit higher C30 compositions. You can see that on the
16 pc traces down here in the lower right-hand corner.
17 But in general they behave very similarly, we've got
18 very good correlations for our API gravity in our
19 reservoir models and what you're looking at in the
20 upper portion of this slide is the fluid sample from
21 the Qugruk 8 well, which is a good average
22 representative sample at 29 degrees, API.
23 So any questions on the API.
24 COMMISSIONER WILSON: No, I'm good.
25 COMMISSIONER CHMIELOWSKI: Unh-unh.
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1 MR. BOND: All right. Slide 14. This is the
2 pressure plot in our Nanushuk Oil Pool. These are
3 pressure points that we've gathered on various
4 delineation wells that have been drilled over time and
5 you can see we've got a pretty good correlation for all
6 of them, maybe just a slight variation on one of the
7 wells there. So we'd say potentially there's subtle
8 baffles that might be seen across the entire field but
9 we don't expect those to be within our interwell 1,800
10 foot spacing type distance, it'd be over much greater
11 distances.
12 We're requesting a datum of 4,100 feet of pbd
13 subsea and the average pressure there is 1,895 psi.
14 COMMISSIONER WILSON: Are you aware if any
15 wells within the Colville River Unit plot on that
16 gradient?
17 MR. BOND: I'm not aware. Christian.
18 MR. NOLL: We do see a general overall trend.
19 So the wells, offset wells are broadly aligned however
20 we do see variability in psi, variability of 8 to 10
21 psi, but we do recognize that not only heading west of
22 us but south towards Stirbury(ph) and east towards
23 Mitkup(ph)* we see deviations from that trend so
24 hopefully that answers your questions. So slightly
25 over pressured relative to what we're seeing here
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1 within the NDB area for example.
2 COMMISSIONER WILSON: Okay, thanks.
3 MR. BOND: Okay. Slide 15. This shows all of
4 our proposed production profiles based on our reservoir
5 modeling. And what you're seeing here are the actual
6 profiles for the 43 wells, this does include the two
7 Alpine wells which is actually one producer and one
8 injector. And so if you look at the upper left-hand
9 plot here we've got a plot of all the various liquid
10 rates and you could see in green, that's our oil rate,
11 we've got a plateau rate with our facility at 80,000
12 barrels a day and depending on what geologic scenario
13 we end up with we'll stay on plateau from three to
14 seven years. You're looking at our mid-case right
15 here. And then the blue lines are water injection
16 rate. So we start out water injection rate here about
17 50,000 barrels a day and climb up to, you know, 90-plus
18 thousand barrels a day of water injection. I'll talk
19 about our seawater treatment plant in some upcoming
20 slides. And then the light blue is the total water
21 injection and then you can see that the seawater drops
22 off as we have produced water coming online. So we'll
23 talk about our produced water handling scheme also a
24 little bit later. And then on the lower right- -- or
25 lower left-hand side we've got all the gas rates here.
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1 We have a total gas handling capacity of 90 million
2 cubic feet a day with our facility and we also plan to
3 have capacity to inject approximately 40 million cubic
4 feet a day of gas into a WAG program. We do plan to
5 import fuel gas from another location at startup and
6 this allows us to preserve our indigenous gas and NGLs,
7 which is really nice high quality sweep gas to enhance
8 our WAG program.
9 So, again, our nameplate oil capacity is 80,000
10 barrels a day and our nameplate gas compression
11 capacity is 90,000 cubic feet a day and our seawater
12 treatment plant has a capacity of 100,000 barrels a
13 day.
14 As far as reserves. Our official 2P reserves
15 number for this Phase I NDB area is 397 Million, again,
16 that includes the two Alpine wells. If you separate
17 out just to the Nanushuk only, the number's
18 approximately.....
19 (Background interruption)
20 MR. BOND: .....318 Million and this is on
21 Slide 16. We've got a range from 211 to 476, again,
22 depending on which geologic scenario we end up with.
23 Our base case recovery factor with water flood and WAG
24 EOR is estimated to be about 37 percent and, again, our
25 annual ma -- peak rate will be 80,000 barrels a day.
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1 And as a note we are currently progressing two
2 additional drill sites in the NDC to the south, and the
3 NDA to the north to be able to develop the remaining
4 resources in the unit.
5 Slide 17. So this is our produced water
6 disposal plan. We plan to drill a disposal well at our
7 NPF location where our production facilities will be.
8 This will be a Class 1 well permitted with the EPA and
9 we need to have capacity to dispose of 10,000 barrels a
10 day of produced water initially. Once we reach 10,000
11 barrels a day then we can commission a produced water
12 line that goes from our NPF facility out to NDB and
13 begin converting wells from seawater injection to
14 produced water injection. We don't plan to mix
15 produced water, seawater at all, we want to keep those
16 systems separated. So we'll drill the initial well at
17 NPF and we'll test its capacity. We've got three wells
18 potentially that we could drill if we need additional
19 capacity to reach that 10,000 barrels a day in the
20 Ivishak.
21 COMMISSIONER CHMIELOWSKI: Do you foresee
22 better recovery with produced water or seawater or the
23 same?
24 MR. BOND: Probably the same. We'll talk about
25 our seawater quality. We also plan to process our
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1 produced water to be, you know, very -- very good
2 quality water as well or produc -- produced -- excuse
3 me -- remove as many particulates and the oil
4 carryover, so we shouldn't see a substantial difference
5 on produced water but typically seawater is cleaner so
6 probably have slightly better injectivity over time.
7 COMMISSIONER CHMIELOWSKI: And you mentioned
8 not wanting to mix -- produce water with seawater on
9 the surface, but I imagine those waters will mix in the
10 reservoir, is there compatibility concerns?
11 MR. BOND: No, we've done quite a bit of
12 testing on that and then we don't have too much as far
13 as scaling problems, we actually are going to put scale
14 (indiscernible) into our fracs to help with scale
15 inhibition and we'll also have scale inhibitor and
16 various other chemicals in our water systems to prevent
17 any kind of issues but we don't see that as being a
18 problem.
19 COMMISSIONER CHMIELOWSKI: And I think I may be
20 getting ahead but is it barium sulfate scales that's an
21 issue for you?
22 MR. BOND: We'll have barium sulfate, our
23 tendencies for that are very, very low initially and
24 then with the additional scale inhibition that we plan
25 we should have very, very little barium sulfate, we
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1 will have some calcium carbonate as well but, again,
2 the scale inhibitor will address that problem.
3 COMMISSIONER CHMIELOWSKI: Great, thank you.
4 MR. BOND: As far as reservoir management,
5 again, Slide 18. We plan to line drive waterflood/WAG
6 injection scenario with our horizontal wells. Every
7 well, both producers and injectors will have multi-
8 stage frac treatments. We plan to maintain our average
9 reservoir pressure, you know, plus or minus 200 PSI of
10 initial conditions, and our VRR ratio long term just
11 slight are greater than 1. I think at the end of our
12 simulation we were at 1.02 on the VRR. And then I'll
13 talk a little bit more about seawater but, again, we
14 plan to do some ultra filtration and sulphite removal
15 for the seawater, that'll help us maximize long-term
16 injectivity in those wells.
17 As far as surveillance, we'll be doing regular
18 well testing. I've got a slide on our multi-phased
19 meter testing coming up as well. We'll do regular
20 pressure testing and surveys, both static and pressure
21 transient analysis. And then surveillance logging, as
22 needed, likely this will be mainly in injection wells.
23 They're a little bit easier to access. Logging tool
24 strings in these long horizontal wells and producers
25 can be difficult.
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1 All right.
2 And then as far as any specialized rule waivers
3 here on Slide 19. I didn't need this one but there are
4 no well spacing restrictions other than no closer than
5 500 feet to the unit boundary, and then we're also
6 asking for the GOR exemption as we'll have a water
7 flood going into place.
8 Any questions on production or reservoir
9 issues?
10 COMMISSIONER WILSON: I'm good, thanks.
11 MR. BOND: Okay. All right, I'm going to move
12 to surface facilities. So I'm now on Slide 21. So if
13 you look at the right-hand side we've got kind of a
14 cartoon schematic of our plant facilities. I'll walk
15 you through here. Out at (Indiscernible) Point we're
16 planning a new build, STP, I've got a slide coming up
17 on that next. And we'll have pipelines for our
18 seawater back through the Kuparuk River Unit out to our
19 NPF processing facility where the water pressure will
20 be boosted and then sent out to NDB for injection. Our
21 production modules are all modular in design and
22 truckable. They're being built in Canada and they can
23 be brought up either on roads or down the MacKenzie
24 River and across the Beaufort Sea. So that's kind of a
25 unique build for the Slope. It allows us also to have
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1 modular expansions for future drill sites. Once we
2 increase the well pad we can also increase our facility
3 size in various portions. That new build seawater
4 treatment plant, again, with a 100,000 barrels a day
5 capacity it can also be expanded up to 165,000 barrels
6 a day with sulphate removal and 200,000 barrels a day
7 without sulphate removal. We have the standard kind of
8 support infrastructure. We'll be drilling our first
9 well on the pad, it'll be a grind and inject disposal
10 well and we'll have a grind and inject plant on that
11 pad to dispose of the fuel cuttings, and we'll have an
12 NOP pad here which will have our support facilities
13 camp, control room, et cetera. I'll talk about our
14 multi-phase meters for testing here in the next couple
15 of slides.
16 With that I'll move on.
17 COMMISSIONER CHMIELOWSKI: So you're just going
18 to start with two of these modules for a total of,
19 what, 80.....
20 MR. BOND: 80,000.....
21 COMMISSIONER CHMIELOWSKI: .....80,000 barrels
22 of oil a day.
23 MR. BOND: Exactly.
24 COMMISSIONER CHMIELOWSKI: And future modules
25 depends on what, future drill sites expansion and
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1 drilling?
2 MR. BOND: Correct.
3 COMMISSIONER CHMIELOWSKI: Okay.
4 MR. BOND: Yeah, so we're looking at 40,000 or
5 80,000 barrel a day increments for additional
6 expansion. As you say it depends on how quickly we add
7 additional drill sites in.
8 All right, so here's a slide on our seawater
9 treatment plant. Again, it'll have nominal capacity
10 initially of 100,000 barrels a day of water and we plan
11 to do ultra-filtration and sulphate removal and this is
12 really key because it'll significantly reduce pipeline
13 and tubular corrosion, rates and products, it should
14 significantly reduce SRBs and H2S in both the reservoir
15 and the facility and, again, further reduce any barium
16 sulphate scaling tendencies. We've done a number of
17 third-party flow assurance studies that confirm these
18 benefits. And our Nanushuk reservoir generally has
19 small pore throats so it is suspectible to damage and
20 blocking for particulates. We've done quite a bit of
21 core studies with that and that's one of the big
22 reasons why we're going to the ultra-filtrations to try
23 to reduce any particulate matter and maintain long-term
24 high injectivity into the reservoir. Also the multi-
25 stage fracs will help overcome some of the injection
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1 issues, we'll open up a huge surface area, communicate
2 the well bore to the reservoir. And then we also have
3 a gas EOR WAG program planned. Again, we have capacity
4 of about 40 million cubic feet a day of gas injection.
5 This will provide incremental oil recovery over the
6 life of the field. We're estimating anywhere from
7 three to seven percent additional recovery, and as I
8 mentioned earlier we plan to import fuel gas initially
9 so we can use our indigenous gas and NGLs for that WAG
10 flood.
11 COMMISSIONER CHMIELOWSKI: Could you please
12 remind me what SRB stands for?
13 MR. BOND: Sulphate reducing bacteria.
14 COMMISSIONER CHMIELOWSKI: Okay.
15 MR. BOND: So if you don't have any sulphate in
16 the system those guys don't have anything to eat
17 so.....
18 COMMISSIONER CHMIELOWSKI: Right. Right. So,
19 you know, way back when I worked at Point McIntyre
20 Field and that's the only other field I'm aware of that
21 has this barium sulfate scale issue but they did just
22 -- they did, when I was there, just start using an
23 inhibitor for that and seemed pretty successful but
24 that's basically what you're planning to do also.
25 MR. BOND: Yes, some -- what I've seen is lots
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1 of reservoirs have the barium in place and then the
2 sulphate comes from the seawater so that's typically
3 what the problem that occurs.....
4 COMMISSIONER CHMIELOWSKI: Okay.
5 MR. BOND: .....so if you remove that sulphate
6 then the barium has nothing to attach to in the
7 reservoir.
8 COMMISSIONER CHMIELOWSKI: So, you know, about
9 your seawater treatment plant, I've just read in the
10 Petroleum News there's been a little bit of back and
11 forth on plans for Oil Search, you know, whether to
12 share Conoco seawater treatment plant or build your own
13 and getting permitting and all that, it's been, sounds
14 like quite a -- quite a lot of work. But it sounds
15 like what you're saying is by having your own plant
16 you're really going to reduce solids and some of these
17 things that are important for the Nanushuk?
18 MR. BOND: Correct.
19 COMMISSIONER CHMIELOWSKI: Okay.
20 MR. BOND: Exactly. Yeah, all our permits are
21 in place for our seawater treatment plant so we're full
22 speed ahead with that plan.
23 COMMISSIONER CHMIELOWSKI: Okay.
24 MR. BOND: And we definitely want that extra
25 clean water. We want to be able to control the volume
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1 we can get and the quality of the water.
2 COMMISSIONER CHMIELOWSKI: Thanks.
3 MR. BOND: All right, as far as -- okay, I'm on
4 Slide 23 here. And as far as metering at NDB pad. So
5 every well will -- that's on gas lift will have a
6 continuous gas lift meter. Those wells that are on
7 injection will have continuous water or gas injection
8 metering. And then as far as well testing for the
9 producing wells we'll have a separate test header and
10 we'll use multi-phased meters to do that testing.
11 We'll do the usual calibration on those to make sure
12 that we have the best possible information in the
13 computers. Each well will have its own profile and as
14 the water flood and as the EOR flood progress, you
15 know, the fluid densities can change over time so we'll
16 make sure that we're constantly updating those profiles
17 to make sure that we're getting the most accurate well
18 tests that we can on each of the wells going forward.
19 And then on Slide 24, this is our allocation
20 scheme. So, again, we'll have well tests on every well
21 and so we'll calculate the raw daily oil water and gas
22 from the well testing information based on each wells
23 up time percentage. And then, of course, we'll have
24 our LACT meter at the NPF facility and that's a
25 separate approval, I believe, that you guys have seen
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1 on our using a Coriolis meter for that. So that will
2 be used to come up with an oil rate, and then we'll
3 have our gas and water rates coming out of there and
4 then we'll calculate allocation factors for each of
5 those and apply those allocation factors back to our
6 raw numbers to come up with production rates from each
7 individual well.
8 COMMISSIONER CHMIELOWSKI: So here's -- the NPF
9 is outside the unit boundary, is that true?
10 MR. BOND: That's correct.
11 COMMISSIONER CHMIELOWSKI: And I think you're
12 aware that AOGCC regulations require that LACT meter
13 occur within the unit.
14 MR. BOND: Okay.
15 COMMISSIONER CHMIELOWSKI: So why is the meter
16 outside of the unit?
17 MR. BOND: It's -- that's a good question.
18 We're talking about expanding our unit to include that
19 area, we just haven't gotten to that yet, that's
20 something that will be coming down the road. So I
21 guess the question is, would we need to expand that
22 unit to inclu -- for that NPF area before we could
23 start production; is that what you're saying?
24 COMMISSIONER CHMIELOWSKI: Our regulations
25 require that the metering occur before it leaves the
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1 unit so you.....
2 MR. BOND: Okay.
3 COMMISSIONER CHMIELOWSKI: .....will need
4 approval from AOGCC before you can use a meter outside
5 of the unit, yeah.
6 MR. BOND: Do you want to comment, Tim.
7 MR. JONES: Yeah, we'll -- we'll either be
8 requesting a waiver or the facility will be located
9 within the unit prior to first production.
10 COMMISSIONER CHMIELOWSKI: Great.
11 COMMISSIONER WILSON: Just an additional
12 question on a potential unit expansion to include the
13 facility. Maybe it's more of a comment, but, I mean
14 would it be based on geology within the unit that
15 wouldn't get contracted out by the DNR?
16 MR. BOND: Yeah, that would certainly be our
17 goal. I mean we think we have additional potential to
18 the east of our initial development area that would
19 cover those leases that we could add back in, in
20 separate -- you know, different accumulations, NT4
21 through 8.
22 COMMISSIONER WILSON: Okay, yeah, it would
23 require production over time to remain in the unit,
24 yeah.
25 MR. BOND: Okay, that's it. I'm going to hand
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1 it over to Rob.
2 COMMISSIONER WILSON: I guess just one
3 additional question. Is there something that
4 constrains you from locating the facility inside the
5 current unit?
6 MR. BOND: Well, it's where we've got it
7 permitted right now, I guess that'd be the constraint.
8 I'm not sure what the process would be to repermit and
9 move that location.
10 MR. JONES: Yeah, the facility is located where
11 it's located, primarily due to the surface
12 considerations, you know, distance from the river,
13 distance from the closest population center and so that
14 was chosen as the optimum location considering those
15 factors.
16 MR. TIRPACK: All right, good morning. Rob
17 Tirpack, drilling manager for Santos. Next slide
18 please.
19 Today I'll be giving an overview of well
20 construction. Our first slide, Slide 26, upper left-
21 hand corner is a picture of the pad as it was last
22 summer during gravel farming. You can -- today it
23 looks quite different. We have thermal siphons in, a
24 whole bunch of construction activities going on in
25 preparation for a June Spud.
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1 Lower left-hand corner is our, you know,
2 general drilling schedule without the individual well
3 names. Andy touched on the different benches. We also
4 have different tier levels of the wells based on their
5 difficulty. So the right-hand picture shows our wells
6 laid over Google Earth. You can see the majority of
7 the reservoirs is located underneath the Colville
8 River, we also have a one mile standoff to the river
9 bank for the local indigenous peoples up there to give
10 them -- gives them room to industry. So that makes our
11 wells quite long. All of them are ERD by nature or
12 ultra-ERD. The difficulty is driven by our
13 intermediate casing point so depending on how far out
14 we can put our immediate casing, the wells in green are
15 the least difficult, and moving up through difficulty
16 are the yellow, orange and then the red. So through
17 the well sequencing, lots of competing factors there.
18 You know we made an attempt to drill the easiest wells
19 first so you can see on the lower left-hand chart start
20 with mostly green for the first year, year and a half,
21 move into a couple yellows and then the orange ones
22 start coming in are Tier 3s and then we have a very
23 long Tier 3 drilling timeframe there.
24 COMMISSIONER CHMIELOWSKI: So Mr. Tirpack, when
25 you're talking about the difficulty in the tiers, the
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1 Tier 1 and 2 is what, the three casing string design
2 and then you move into the, what you call the four
3 casing string design; is that right?
4 MR. TIRPACK: Yes -- well, I'll get into that
5 in the.....
6 COMMISSIONER CHMIELOWSKI: Okay.
7 MR. TIRPACK: .....in the -- in the next
8 slides. But, yes, we start off with the, you know, 13
9 and 3/8ths, 9 and 5/8ths and then the -- the production
10 lateral and then we add a seven inch string in there,
11 in the Tier 3s, and then the Tier 4s, then we upsize
12 and add an additional string.
13 COMMISSIONER CHMIELOWSKI: Uh-huh.
14 MR. TIRPACK: Yes. Some mile points on the
15 chart, Spud June of this year, grind and inject
16 facility would come on approximately a year later in
17 June of '24 -- 2024, and then targeting first oil there
18 in 2Q of '26.
19 COMMISSIONER CHMIELOWSKI: Do you know which
20 rig you're going to use or more than one?
21 MR. TIRPACK: We have Parker 272 contracted,
22 rig -- as an additional note, rig camp moves this
23 weekend and the actual rig moves next weekend to NDB.
24 Also on the chart you can see the two blue
25 lines, one off -- coming off NDB is the well trace for
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1 the G&I well and off NPF is the well trace for the PWDW
2 well. And off -- off to the -- kind of the two
3 outliers there are the two Alpine wells.
4 COMMISSIONER CHMIELOWSKI: And what's the
5 timing for Alpine wells?
6 MR. TIRPACK: Boy, I think they're out.....
7 COMMISSIONER CHMIELOWSKI: A couple years out?
8 MR. TIRPACK: .....2027.....
9 COMMISSIONER CHMIELOWSKI: Okay.
10 MR. TIRPACK: .....2026.....
11 COMMISSIONER CHMIELOWSKI: Yeah.
12 MR. TIRPACK: .....way out there. All right,
13 now I'll start walking through our different well
14 designs. First we'll cover Tier 1 and Tier 2. These
15 wells all get a 20 inch insulated conductor, 13 and
16 3/8ths casing in a 16 inch hole and we kick off all the
17 wells around 300 foot. We're planning on 3 degree dog
18 legs and we'll start building out from there. All
19 these wells are high angle. Our two shortest, closest
20 wells are 45 degrees, after that we're in the 60, 70s,
21 and 80s for tangent angles. Surface casing fully
22 cemented and then we move into Intermediate 1, 12-1/4
23 hole with a 9 and 5/8ths liner. This is unique in that
24 our 9 and 5/8ths, all of them will be liners so we'll
25 set that as a liner and then as mentioned before the
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1 Tuluvak sand, we've had quite a bit of communication
2 with the State on the Tuluvak but this is how we handle
3 the fully cementing Tuluvak in the Tier 1 and 2. Tier
4 1, it'll be one large cement job up to the liner top
5 packer. Tier 2 we'll actually have to do a two stage
6 with the 9 and 5/8ths liner.
7 COMMISSIONER WILSON: Do you see any difficulty
8 in lifting cement to the Tuluvak in Tier 1?
9 MR. TIRPACK: All of our mod -- yes, it -- it
10 becomes difficult fairly quickly because of the -- the
11 large MDs but all of our modeling shows that there is a
12 crossover point there in the Tier 1 and then we'll have
13 to do a two stage. It'll all depend on -- all depend
14 on actual frac grading that we see as we drill our
15 first couple wells.
16 We will have equipment ready and on location in
17 case we have to go to the two stage early.
18 Moving to the production hole, Tier 1 and 2's
19 will be 8.5 inch open hole with a 4.5 inch lower
20 completion. The mud program is a water based fluid on
21 the -- for the Spud Mud and then we'll have oil based
22 mud -- inter-oil based mud for intermediate and
23 production holes, two different systems, the
24 intermediate will be -- will be quite a bit heavier and
25 have lots of -- quite a bit of solids in there for --
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1 to bridge off the shales and well cont -- or excuse me,
2 formation control and then the production hole will be
3 about thinner clearer fluid for production, ultimately.
4 COMMISSIONER CHMIELOWSKI: So Mr. Tirpack I do
5 have some questions about the Tuluvak and the logging
6 identification, would you prefer to go through your
7 slides and then we talk about those at the end or what
8 would be best?
9 MR. TIRPACK: We can go through it now.
10 COMMISSIONER CHMIELOWSKI: Okay. So I see on
11 these slides you -- you sort of shaded out where you
12 think the Tuluvak would be, you know, versus the
13 application, it wasn't -- wasn't as clear but the
14 application states that Oil Search does not -- it says
15 gas is present in the Tuluvak but not considered
16 significant enough to warrant commercial development.
17 Why is commercial development considered important in
18 this instance, why is commercial development considered
19 at all since there's no gas -- major gas sale?
20 MR. TIRPACK: In the beginning of the project
21 we were looking at it commercially to see if we could
22 use it for fuel gas. Andy, anything else to add on
23 that?
24 MR. BOND: Exactly. If it was a viable fuel
25 gas source it'd be great we wouldn't have to buy fuel
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1 gas from outside the unit so that's -- that's where
2 that statement comes from.
3 COMMISSIONER CHMIELOWSKI: Okay. AOGCC is not
4 considering, you know, economics of commercial
5 development in our evaluation, right -- okay. Do you
6 have an estimate on the recoverable reserves, oil
7 and/or gas in the Tuluvak? It appears to be
8 significant, although your application states that you
9 do not consider it significant, so I'm trying to
10 understand what -- what is there.
11 MR. TIRPACK: I'll have to defer to Andy or
12 Christian on the volumes.
13 MR. NOLL: Yeah, I -- I don't have the in place
14 gas volume off the top of my head but we can provide
15 that to you. One of the issues is we've got pretty
16 good well control. The Tuluvak formation is very high
17 water saturation so it's at or just slightly above a
18 typical water saturation thresholds but defining net
19 pay, however, we do see across the NDB area somewhere
20 in the order of 40 to 60 feet net pay thickness in the
21 Tuluvak so it's relatively thick but it's obviously
22 distributed broadly across the Pikka Unit area.
23 Reservoir quality is very poor. So we typically see,
24 on average, one mD or so permeabilities associated with
25 the Tuluvak sands and those very high water
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1 saturations; that reservoir quality is what impacts our
2 ability to develop the Tuluvak gas end (ph).
3 COMMISSIONER CHMIELOWSKI: So before Oil Search
4 came to Alaska, Repsol was drilling in this area and
5 had a blowout so how does that reconcile with what you
6 just said? It was a significant blowout on the
7 Tuluvak?
8 MR. BOND: So I can comment on the drilling of
9 Q2. Their surface hole penetrated the Tuluvak and they
10 were on diverter. Our well design has a setting
11 surface casing above the Tuluvak and being on BOP we've
12 had a number of studies, quite a bit of well control
13 and we have what we believe is a good understanding of
14 pore(indiscernible) pressure in the Tuluvak.
15 COMMISSIONER CHMIELOWSKI: Has Oil Search
16 reviewed or listened to the recent hearing that we had
17 with ConocoPhillips on the CD1 gas release?
18 MR. BOND: Yes, I was here for that. In that
19 situation it appears that, you know, Conoco used the
20 methodology that was not -- that they believed to be
21 accurate but was actually not accurate in predicting
22 the potential of the Halo gas zone. So what makes you
23 think that your system will be accurate in predicting
24 the potential of the Tuluvak?
25 MR. TIRPACK: I can comment on the pore
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1 pressure of direct readings we have on the offsets as
2 far as the geology -- Christian.
3 MR. NOLL: You could (whispering, away from
4 mic)
5 MR. TIRPACK: Yeah, so many penetrations of the
6 Tuluvak and based on mud weights and background gas and
7 mud gas that we've seen we have a very good
8 understanding of the pore pressure in the area.
9 MR. NOLL: In terms of reservoir quality, as
10 Rob mentioned, we have -- we feel that we have very
11 good well control across the Pikka Unit on the Tuluvak,
12 the Tuluvak's encountered within -- within each of
13 those wells across the Pikka Unit. Our evaluations are
14 -- thin bed evaluations, we have -- we deploy a thin
15 bed petrophysical model so the Tuluvak, in order to
16 understand that very thinly interbedded Tuluvak
17 sequence, so we feel that gives us a good control. As
18 I mentioned earlier, we do interpret some variability
19 in thickness, net pay.....
20 (Background interruption)
21 MR. NOLL: .....within the Tuluvak on the Pikka
22 Unit in the order of 40 to 60 feet so we recognize that
23 the Tuluvak is present, it's gas charged. We've
24 sampled permeabilities within the Tuluvak within the
25 Pikka Unit and we also plan to run logs in our initial
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1 development wells to better understand the Tuluvak
2 reservoir quality within the NDB area.
3 COMMISSIONER WILSON: So to followup, I guess
4 on that discussion and also follow up on Jessie's
5 question, if we assume.....
6 (Background interruption)
7 COMMISSIONER WILSON: .....that the Tuluvak is
8 not commercial and also assume that we have
9 (indiscernible - garbled) across the interpol then
10 there shouldn't be an issue, but in your application,
11 in the text of the application you propose to isolate
12 the Tuluvak with a packer and be waived to not cement
13 across the Tuluvak as required by 20 AAC 20.030(d)(5),
14 do you have any comments regarding that?
15 MR. TIRPACK: No, I don't. If that is stated
16 in there that we won't -- that we will not be cementing
17 the Tuluvak then that's an error. We will fully cover
18 the Tuluvak with cement is the plan.
19 MR. BOND: I guess let me comment, I mean we
20 may have a residual typo in the application because
21 that was our initial plan was to not have to cement the
22 Tuluvak and then after meetings with staff we changed
23 the wording to have require cement across the Tuluvak,
24 so there may be a residual comment there about the
25 packer being the only isolation so.....
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1 MR. TIRPACK: We'll doublecheck that too, yeah,
2 because that would alleviate the -- the gas release
3 that occurred at ConocoPhillips then, even in the case
4 where you're not detecting it as a pay sand.
5 COMMISSIONER CHMIELOWSKI: So maybe I
6 misunderstood. Is Oil Search saying that you plan to
7 cement the Tuluvak and all wells?
8 MR. BOND: That is the base plan, yes.
9 COMMISSIONER CHMIELOWSKI: To cement the
10 Tuluvak and every well -- okay, that was a misund --
11 big misunderstanding, I think, between what we read in
12 the application so that's good to clarify. Because the
13 way it reads is you would only cement it if you deemed
14 it significant and then it also says we don't deem it
15 significant -- so, okay, so plan to put cement across
16 the Tuluvak and all wells.
17 MR. BOND: I think if we drill a number of
18 wells and we find that it is even lower quality that
19 what we're talking about, maybe we'll come back to you
20 and ask you for a waiver at that point but.....
21 COMMISSIONER CHMIELOWSKI: Will you be running
22 logs across this area, I guess, initially, maybe the
23 first, what you say, a half a dozen wells or?
24 MR. NOLL: That's exactly right.
25 COMMISSIONER CHMIELOWSKI: Okay.
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1 MR. NOLL: We do plan to -- attempt to
2 formation pressures within that formation also so -- so
3 that's part of the early data gathering plan within the
4 first couple wells.
5 COMMISSIONER CHMIELOWSKI: Okay, great.
6 COMMISSIONER WILSON: But then in all cases
7 you're running an LTBE sweep?
8 MR. NOLL: That's correct.
9 COMMISSIONER CHMIELOWSKI: And then anoth --
10 one more question on this slide. When you say you're
11 cementing across the Tuluvak, are you going to run a
12 log across it to ensure good cement?
13 MR. TIRPACK: The way we interpret the inter --
14 interpret the regulations that that log is not required
15 to -- for verification, we'll go off of displacement
16 and returns.
17 COMMISSIONER CHMIELOWSKI: Okay. I'm ready to
18 move on Greg if -- it's up to you.
19 COMMISSIONER WILSON: Yeah, I'm good.
20 MR. TIRPACK: All right, next slide, please,
21 Andy. So we are on Slide -- I can't read it from here.
22 MR. BOND: Yeah, it's covered up.
23 MR. TIRPACK: Slide 28. Again, another
24 depiction of our well construction. Surface and
25 conductors are same as Tier 1 and 2 as we move into the
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1 Tier 3s. Here we have a 13 and 3/8th -- excuse me, 13
2 and 3/8th surface casing and we add a 9 and 5/8ths
3 liner and then a 7 inch liner for the Tier 3s. Again,
4 with the 9 and 5/8ths liner it's going part way down to
5 the Nanushuk, again, Tuluvak fully cemented, either in
6 a single stage or a two stage job depending on well
7 length of the first intermediate. We then run a 7 inch
8 liner down to the top of the Nanushuk and drill 6 and
9 1/8th hole and a half lower completion.
10 Next slide.
11 In addition to the Tier 1, 2s and 3s we have a
12 couple of our -- three different well designs for the
13 different -- for the different non-producing wells.
14 The first one -- I won't go into too much detail here,
15 but the first one is for the G&I well, much shorter,
16 much less hole angle so we reduce casing size, it's
17 only two string design with the completion going in for
18 the G&I well. The produced water disposal well, we
19 move back up to a 3 string design, again, because we're
20 going down to the Ivishak, we have to get through some
21 of the different formations there. Again, all of these
22 are cemented up for the G&I through the Tuluvak and
23 then on PWD -- PWDW also Tuluvak cemented.
24 COMMISSIONER CHMIELOWSKI: And those are both
25 located at the projection facility pad?
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1 MR. TIRPACK: G&I's located on NDB on the
2 drilling.....
3 COMMISSIONER CHMIELOWSKI: Oh, on the drill
4 site.
5 MR. TIRPACK: Yep.
6 COMMISSIONER CHMIELOWSKI: Okay.
7 MR. TIRPACK: Yep. And then PWDW on -- on NPF.
8 COMMISSIONER CHMIELOWSKI: Okay.
9 MR. TIRPACK: And then finally Tier 4s, we
10 won't dig into the Tier 4s but it -- it up sizes once
11 again to 18 -- excuse me, 18 and 5/8ths surface casing
12 and then we go 13 and 3/8 and 9 and 5/8th, 7 and four
13 and a half.
14 COMMISSIONER CHMIELOWSKI: Just in the event
15 you need to go bigger for the longer wells?
16 MR. TIRPACK: For the longer wells we will need
17 to go bigger. That would require a different rig with
18 a larger BOP stack.
19 COMMISSIONER CHMIELOWSKI: Okay.
20 MR. TIRPACK: Yep.
21 MR. BOND: Our ultimate plan is to put the NDC
22 pad in place and these Tier 4 wells can move to that
23 location and it'd be much shorter.....
24 COMMISSIONER CHMIELOWSKI: Right.
25 MR. BOND: .....and easier to.....
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1 COMMISSIONER CHMIELOWSKI: Then you won't need
2 to do them.
3 MR. BOND: Correct.
4 COMMISSIONER CHMIELOWSKI: Yeah, got it.
5 MR. TIRPACK: There's a half a dozen wells to
6 the south there on the diagram where they become much
7 easier to drill from NDC and the difficulty goes down
8 so if our Phase 2 goes forward we'll be drilling those
9 wells from the other pad.
10 COMMISSIONER CHMIELOWSKI: And there's, I
11 guess, a decision within Oil Search about when to
12 sanction going forward, so do you have any idea, your
13 timeline on that?
14 MR. TIRPACK: We're entering into discussions
15 on what -- what timing looks like, I don't -- I don't
16 have a definitive answer.
17 COMMISSIONER CHMIELOWSKI: Okay.
18 MR. BOND: Yeah, we're hopefully going to enter
19 into a feed process later this year but as far as final
20 approval timing I don't have that.
21 COMMISSIONER CHMIELOWSKI: Yeah.
22 MR. COOK: Okay, my name is Mark Cook and (not
23 by a microphone).....
24 COMMISSIONER CHMIELOWSKI: Make sure your
25 microphone's bright green, is it?
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1 MR. COOK: Oh, yeah.....
2 COMMISSIONER CHMIELOWSKI: There we go.
3 MR. COOK: .....okay. So, hi, my name is Mark
4 Cook. I'm the completions manager for Santos here in
5 Anchorage. So I'm going to talk through the
6 completions a little bit here, high level, so we're
7 starting with Slide 30 for the completions outlook.
8 So the first comment here, the pictures on the
9 right we have the producer concept and to the lower
10 right is the injector concept. Very similar well as
11 far as the horizontal section completion goes. The
12 upper completion will change slightly between injectors
13 and producers. But both of these are based on a 4 and
14 a half inch 12.6 pound 110S Monobore completion so
15 tubing and lining, Monobore system. The -- starting
16 from the bottom up going through the well, like I
17 mentioned before the production liner completion will
18 be the same for both well types, so just kind of
19 walking through it from the bottom up it's going to be
20 an eccentric no shoe shutoff collar, we'll have a toe
21 sleeve in there and then we'll go into our frac sleeve
22 and into some hydraulic shut/open hole packers which
23 isolate each of the frac zones. So this will be an
24 open hole, multi-stage frac completion. And then when
25 we get up to the top that'll be isolated up to the
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1 liner hanger so the shoe, you know, will be isolating
2 the intermediate shoe from the reservoir with the lower
3 liner completion from the liner hanger. And so with
4 that, the next piece of this is the upper completion.
5 This is going to be tied back into a seal bore through
6 the liner hanger system so in this system the packer on
7 the liner hanger system from the liner is your
8 production packer so what this allows for is some
9 tubing movement and future workovers in the futu -- you
10 know future workovers down there at these high angles
11 trying to pull and remove completions that have control
12 lines and some surface controlled equipment down there
13 allows for the tubing movement for the frac operations
14 so it's a -- really helps with the operations and the
15 future of the well, maintenance. So the tieback seal
16 assembly will be working with that. We'll have
17 multiple landing nipples in there so we can do tubing
18 tests for the completion. We'll have some up high
19 where we can use those to isolate the wells and to do
20 some suspension. The -- all the wells initially will
21 have down hole temperature and pressure gauges, even in
22 the injection wells. And what that is for is primarily
23 we can get that data when we're doing the frac and be
24 able to get a lot more -- have a lot more control of
25 our frac operations if we have some down hole pressure
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1 and temperature gauges on there.
2 COMMISSIONER CHMIELOWSKI: Okay.
3 MR. COOK: And so those -- that'll be there on
4 the production side. We're planning to run a surface
5 controlled gaslift system down hole. That's primarily
6 for the reason that reaching these -- reaching the toes
7 of these wells at the intermediate set depth is very
8 challenging, typical means for gaslift equipment,
9 gaslift mandrels is a flick(ph) line which isn't
10 reachable, so what we did is we tried to eliminate the
11 need for those challenges and we did a.....
12 (Background interruption)
13 MR. COOK: .....controlled system there.
14 COMMISSIONER CHMIELOWSKI: Hum.
15 MR. COOK: So it's some newer technology that's
16 coming to the state and there's some other people
17 looking at this technology (indiscernible - garbled)
18 also we're looking forward to that.
19 Again, we'll have the nipples placed through
20 here. We'll have an upper mandrel placed below
21 permafrost so we can do our protect and fluid swap
22 there. Nipples in there again at predetermined points
23 for integrity checks and also on the injection wells
24 we'll have a nipple in there set up where we can do an
25 injection valve if and when we go to the WAG operations
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1 that Andy had spoken about earlier. So I think that
2 kind of walks through an overall view of the completion
3 mechanics.
4 If there's no questions there we can move to
5 the next slide.
6 COMMISSIONER CHMIELOWSKI: Well, you know
7 you're going to frac all these wells, so do you
8 anticipate problems with, you know, flow backs and
9 cleaning up your wells? How do you clean them out?
10 MR. COOK: Yeah, that's kind of -- I'm going to
11 touch on that.....
12 COMMISSIONER CHMIELOWSKI: Okay.
13 MR. COOK: .....in these next wells a little
14 bit, I can talk about -- I was going to talk to the
15 frac a little bit, but I can touch on that real quick.
16 COMMISSIONER CHMIELOWSKI: Oh, go ahead, move
17 on, yeah, and then talk about it more is right.
18 MR. COOK: Okay. So, again, like you had
19 mentioned, on Slide 31 we're talking about the
20 stimulations of the wells, so, again, multi-stage open
21 hole frac'ing. These are some specialized cross-link
22 fluids. This is primarily due to the low temp of the
23 reservoir compared to what most fluids like this are
24 designed for so we have to do some special things
25 there. Ceramic proppant planned is the proppant --
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1 Andy had mentioned earlier we have a longitudinal
2 fracture orientation we're targeting, this is partly
3 why we're going to be verified this is our 330
4 (indiscernible) where are wells are designed right now.
5 We think that's where it is, there's some plus or minus
6 in there. We do have some room on that but that's
7 partly why we're going to do some of the early learning
8 programs and try some micro-seismic and hopefully we
9 can define that a little bit closer.
10 COMMISSIONER CHMIELOWSKI: It's -- it's not
11 typical to frac injectors so -- but by doing these
12 longitudinal fracs you're able to get the verti.....
13 MR. COOK: Yeah, the lo.....
14 COMMISSIONER CHMIELOWSKI: .....vertical
15 without going.....
16 MR. COOK: .....yeah, the longitudinal.....
17 COMMISSIONER CHMIELOWSKI: .....you know, short
18 circuiting your injections?
19 MR. COOK: .....versus the transfer
20 (indiscernible - simultaneous talk).....
21 COMMISSIONER CHMIELOWSKI: Right.
22 MR. COOK: And what that does is optimize our
23 water flood system.....
24 COMMISSIONER CHMIELOWSKI: Uh-huh.
25 (Affirmative)
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1 MR. COOK: .....we don't want to create a
2 transferase frac which is a conduit into.....
3 COMMISSIONER CHMIELOWSKI: Right.
4 MR. COOK: .....injector (indiscernible -
5 simultaneous talk).....
6 COMMISSIONER CHMIELOWSKI: Yeah.
7 MR. COOK: .....producers. We want to keep it
8 good near well bore conductivity in the injectors and
9 producers for that reason. So average jobs that we
10 were talking about 6,000 foot wells, probably 2.5
11 million pounds of frac per well, you know, that will
12 adjust depending on the -- the lateral length we do.
13 So the pictures on the right, that's just an example of
14 one of our frac designs coming out of our frac models
15 to kind of show a -- the height half length, and the
16 middle picture there is just kind of showing just a
17 quick pictorial.....
18 COMMISSIONER CHMIELOWSKI: Uh-huh.
19 (Affirmative)
20 MR. COOK: .....of a transverse frac versus a
21 longitudinal frac.
22 So with that being a general description of the
23 simulation, the next thing we will do is the well
24 cleanup, flowback. So we will move -- pretty much
25 directly our plan is after we drill and complete on the
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1 rig we'll move to this fracture simulation and then go
2 straight to the well cleanup and that way we can use
3 the pressure left from the frac to kick the water off
4 and get a good cleanup and get the water off early, we
5 don't want to leave that sitting on the well bore. So
6 we'll do the cleanup directly after. Our plan is to
7 dispose of the fluids from the flowback onsite directly
8 at our Class 1 well, so we'll just come up with a
9 system where we can pump this across the pad and
10 eliminate a large volume of trucking and things out
11 there and traffic and fluid transfers and risks and all
12 that so we'd come up with a system to really optimize
13 that.
14 So after that, we get the well cleaned up, it's
15 ready to go, while we're building up our well stock for
16 our first oil we will temporary suspend the wells,
17 that'll be the last thing we do. During this period we
18 will take some build up data. We're going to take some
19 tracer data on some of the fracs as part of our early
20 -- early learning but we want to do is optimize our
21 designs from the sand (indiscernible) from the frac to
22 how we clean the wells up to the data we get out of
23 this so that can inform us on how we frac for the next
24 wells early on, we want to turn this around
25 quickly.....
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1 COMMISSIONER CHMIELOWSKI: Uh-huh.
2 (Affirmative)
3 MR. COOK: .....what we don't want to do is go
4 through the entire program of 26 wells done the same
5 way, put it on production and realize we could have
6 optimized a lot more through there, so you've probably
7 heard as we've been through the presentation about this
8 early learning, early data gathering, that's what it's
9 really about, we want to optimize from our models, from
10 our operations and how we treat the sand phase, we want
11 to optimize that early on in the -- in the process.
12 So at that point, that's kind of the -- the
13 last bullet on here was that 62 percent of the wells
14 completed prior to first oil, that equates to 26 of our
15 43 wells.
16 COMMISSIONER CHMIELOWSKI: Okay.
17 MR. COOK: So this is why -- again, why the
18 early learning is so important too.
19 COMMISSIONER CHMIELOWSKI: Right.
20 MR. COOK: So I think that wraps up the
21 completion side if there's no more questions.
22 COMMISSIONER CHMIELOWSKI: Okay. Nope. Thank
23 you.
24 MR. COOK: Thanks.
25 MR. BOND: And then the last four slides are
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1 just a copy and paste from our application with the
2 various rules so I don't think we need to go through
3 that in any detail unless you would like to.
4 COMMISSIONER CHMIELOWSKI: I don't think so
5 unless you had some questions specific there Greg.
6 COMMISSIONER WILSON: I -- I do actually.....
7 COMMISSIONER CHMIELOWSKI: Okay.
8 COMMISSIONER WILSON: .....yeah, wanted to
9 explore something just a little bit on your pool
10 definition and, in part, we might have to flip back to,
11 I think it was Page 12. But I think we -- we did agree
12 that the neighborhood's a little bit crowded there,
13 that you've got spillover of potential reservoir, you
14 know, into the Colville River Unit. And as we look at
15 the well bores, depending on where that spillover is
16 happening, like for instance along the roughly
17 north/south border between Pikka Unit and Colville
18 River Unit, I mean obviously you don't want to drill
19 within 500 feet of the unit boundary but then, you
20 know, we will have a concern about conservation of
21 resource overall at the end of the day, potentially,
22 you know, if there's expected reservoir on the other
23 side of that boundary. And then also, you know, down
24 to the south, so then the boundary on the southern
25 extent of the Pikka Unit, you know, there's been wells
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1 drilled down there just across the border and, you
2 know, again, a concern about how both operators
3 approach that border and we'll have to carefully
4 consider conservation of resource down there too. I'm
5 sure you're aware of all that. I mean do you have any
6 comments, in particular, about that? I don't have a
7 specific question there.
8 MR. BOND: So we have had discussions with the
9 offset operator and to the extent we can we are going
10 to try to coordinate drilling across the lease line.
11 Right now the wells that they've drilled a little
12 further south of our area are on 1,800 foot spacing as
13 well with a similar 330 degree orientation. There
14 could be issues if we decide to expand our well spacing
15 to a higher number than 1,800 feet as we move south and
16 there may not be direct alignment of the wells, but,
17 again, primarily they're developing the NT2 versus
18 we're developing the NT3 so there's not a lot of direct
19 communication there in the flood aspect. We have.....
20 COMMISSIONER CHMIELOWSKI: When you do frac,
21 won't they be in communication?
22 MR. BOND: We don't -- we don't typically frac
23 into the NT2 so.....
24 COMMISSIONER CHMIELOWSKI: Uh-huh.
25 (Affirmative)
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1 MR. BOND: .....I don't think it's going to be
2 an issue. I mean there's certain locations where it
3 could be an issue but it's just -- it'll be site
4 specific, I think.
5 COMMISSIONER WILSON: And how about along the
6 north/south boundary where you limit the extent of the
7 wells, is -- is that -- the first shingle I'm looking
8 at on the north/west end of that cross section, would
9 you call that Conoco there.
10 MR. BOND: Comment on that Christian.
11 MR. NOLL: Basically where the laser pointer is
12 at NDB-039, is that where you.....
13 COMMISSIONER WILSON: Yeah, right.
14 MR. NOLL: .....is that where your question is?
15 COMMISSIONER WILSON: Right. Uh-huh.
16 MR. NOLL: It looks like the upper most portion
17 of that where you can see yellows and oranges, that
18 would be the very thin shelf equivalent of the
19 Nanushuk-3, the brown below, I believe is the Nanushuk-
20 2 equivalent which would be the Conoco equivalent on to
21 the Pikka Unit so. That's -- that's my guess. It's
22 not labeled on this sketch so I'm not comp -- not 100
23 percent certain.
24 COMMISSIONER WILSON: Has there been any
25 discussion with ConocoPhillips on -- along that
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1 north/south border?
2 MR. BOND: So we primarily have been discussing
3 down in their CD4Narwhal area. We haven't had
4 discussions this far north.
5 COMMISSIONER WILSON: Uh-huh. It's -- it's a
6 long reach for ConocoPhillips. And then, I guess I
7 will ask this question, but given how you would
8 geologically define the pool as opposed to unit
9 boundaries, is there any reason this would be a
10 different pool from that defined by ConocoPhillips in
11 the Colville River Unit?
12 MR. NOLL: So as Andy mentioned, the focus west
13 of the pool, the unit boundary is Nanushuk-2, we are
14 focused on the Nanushuk-3 so there is -- there is a
15 division, somewhat subtle division between Nanushuk-2
16 and 3, there's a max flood surface, there's an expected
17 degree of compartment minimalization across those two
18 reservoirs, so we're very focused on the Nanushuk-3 in
19 particular. So I think that's where the -- that's
20 where the division may -- may exist. The Nanushuk-3 is
21 very thin in that up westernmost shelfal area, west of
22 the Pikka Unit boundary, so that has been penetrated
23 within the pool but we are focused on that expanded
24 Nanushuk-3 section on the Pikka Unit itself, Nanushuk-2
25 far less certainly not at NDB.
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1 COMMISSIONER WILSON: Okay.
2 MR. NOLL: I guess if I was to say at the NDB
3 area, the Nanushuk-2 equivalent is that outboard of the
4 shelf margin, shale dominated sort of bottom set
5 equivalent at that -- in the Nanushuk-2, so I think
6 there's a -- there's a significant change in geologic
7 character between the two reservoirs, that NDB area.
8 COMMISSIONER WILSON: Okay. And then if we
9 could flip back to Page 32, the one we were on
10 previous. At the bottom there, e) and I know we've
11 touched on this but here where you're -- you know you
12 say: In lieu of requirements of 20 AAC 25.071(a), but
13 you are saying that you will have LWD logs in all the
14 wells, gamma-rays resistivity.
15 MR. BOND: Yeah, as a minimum we have gamma-
16 rays planned for every well.
17 COMMISSIONER WILSON: I'm good.
18 COMMISSIONER CHMIELOWSKI: So I just wanted to
19 touch back on the pool definition a little bit. And,
20 you know, part of our mission is to encourage greater
21 ultimate recovery of resources and prevent waste of
22 resources. So I guess my concern is, is where there's
23 these boundaries at the unit edge, where both parties
24 are maintaining an offset or one party can reach it and
25 the other party can't, but because of this unit
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1 boundary, the wells are being truncated maybe too soon,
2 or they're not going to drain effectively in this area,
3 can you please comment on the potential for wasting of
4 resource in this no-man's land in between the two --
5 you know, in the middle of these units?
6 MR. BOND: I think you described it well. I
7 mean there's certain areas where we can reach past the
8 edge and there's certain areas where the offset
9 operator can't reach to that spot, so, yeah, that --
10 that's certainly a potential issue. But as -- as the
11 regulations are right now we can only drill within 500
12 feet so that -- that's what we've been assuming.
13 COMMISSIONER CHMIELOWSKI: So the wells are,
14 you know, truncated, not based on the geology but based
15 on this off -- this 500 foot offset, if you had all
16 that land you would drill them further, is what you're
17 saying?
18 MR. BOND: Yeah, I -- I think there's certain
19 well locations we would drill further, yes.
20 COMMISSIONER CHMIELOWSKI: Yeah. And if I
21 understood correctly, I'm just going to restate, you're
22 saying that there is enough of a difference between the
23 -- what you're calling the Nanushuk-2 and the Nanushuk-
24 3, that they should be considered different pools, the
25 Conoc versus what you're calling the Nanushuk?
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1 MR. NOLL: We do regard them as geologically
2 similar, all part of the Nanushuk Q-system, two
3 separate parasequences separated by a max flood surface
4 between the two Nan-2 and Nan-3 reservoirs, but highly
5 comparable in terms of the overall sort of progradation
6 or Nanushuk system, we see a subtle pressure
7 compartmentalization across not only the Pikka Unit but
8 surrounds. As I mentioned we are very much focused on
9 the Nanushuk-3 for the NDB development.
10 COMMISSIONER CHMIELOWSKI: Are the 2 and the 3,
11 are they in pressure communication?
12 MR. NOLL: There is a subtle diff -- as I
13 mentioned earlier, the pressure data seems to -- across
14 the sub -- subregion dataset it does seem to indicate
15 an overall pressure trend, however, there is subtle
16 differences. I believe, off the top of my head, the --
17 the wells to the west of us, is slightly elevated
18 pressures relative to the oil gradient that we've seen
19 at the Pikka Unit so that would be -- that would
20 indicate subtle compartmentalization between the
21 Nanushuk-2 west of the Pikka Unit, and Nanushuk-3
22 within the Pikka Unit itself. And that's -- that's
23 consistent with other Nanushuk pressure information as
24 I mentioned heading eastward into the Mitkup and south
25 into the Stirbury.
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1 COMMISSIONER CHMIELOWSKI: Okay.
2 COMMISSIONER WILSON: I -- I guess I do have
3 one more question. South of the Pikka Unit with the
4 Putu2 and 2A, and I believe 2A was the eastern most
5 penetration, what -- what unit would you say that
6 penetrated, 2A?
7 MR. NOLL: Putu2 and 2A penetrated a
8 combination of both the Nanushuk-2 and Nanushuk-3 as we
9 -- according to our (indiscernible), the
10 (indiscernible) that we use.
11 COMMISSIONER WILSON: I'm good.
12 COMMISSIONER CHMIELOWSKI: All right. Is your
13 presentation concluded then -- great. I think we're
14 going to take a recess to talk with our staff and then
15 we'll come back and see if we have any more questions.
16 So this always a little longer than I expect, how about
17 20 minutes, so 11:50 or 10 'til noon, sound good -- all
18 right, we'll adjourn until then. Thanks.
19 (Off record)
20 (On record)
21 COMMISSIONER CHMIELOWSKI: .....considering
22 this Nanushuk Oil Pool will include NT-2, correct, are
23 you asking for your oil pool to be the NT-3, or
24 everything between the CB and the Torok?
25 MR. NOLL: The -- the -- everything between the
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1 CB and the Torok so.....
2 COMMISSIONER CHMIELOWSKI: Okay.
3 MR. NOLL: .....it's based on the top confining
4 layer and the lower confining layer.
5 COMMISSIONER CHMIELOWSKI: So depending on
6 where the well is it could include the NT-2?
7 MR. NOLL: That's correct.
8 COMMISSIONER CHMIELOWSKI: Okay. That's the
9 only question I had.
10 COMMISSIONER WILSON: Okay. And it just puts
11 it in the open right now that there's recognition that
12 we could have an issue down the road that will require
13 a hearing between both parties.
14 COMMISSIONER CHMIELOWSKI: So we'll go to the
15 section of the hearing where we provide the opportunity
16 for public comment. Is there anybody in the room
17 today, I'm just going to look around, who would like to
18 provide comment on today's hearing.
19 (No comments)
20 COMMISSIONER CHMIELOWSKI: Okay. Sam, do you
21 have anybody online who's indicated they wish to
22 comment or provide testimony -- you do not, okay.
23 So I'm just going to -- we're going to do --
24 take a little break here and allow people online to
25 unmute themselves, sometimes it takes longer for those
AOGCC 4/19/2023 ITMO: OIL SEARCH ALASKA
Docket No. C0-23-003
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
Page 74
1 who are remote. So for those who are participating
2 remotely, on Teams, the code to unmute is star, six.
3 If anyone has technical difficulties, Samantha Carlisle
4 can be reached at (907) 793-1223, or you can call the
5 AOGCC's main number at (907) 279-1433. We will pause
6 for 60 seconds to allow people time to unmute and
7 indicate whether or not they wish to provide comment or
8 testimony.
9 (Pause)
10 COMMISSIONER CHMIELOWSKI: Samantha, have you
11 heard from anybody who wishes to provide comment or
12 testimony -- okay.
13 Anything else from the presenters today before
14 we adjourn?
15 (No comments)
16 COMMISSIONER CHMIELOWSKI: Shaking their head
17 no. Commissioner Wilson, anything else?
18 COMMISSIONER WILSON: Nothing additional.
19 COMMISSIONER CHMIELOWSKI: All right. So
20 hearing no other business, the time is 12:05, and this
21 hearing is now adjourned, thank you very much.
22 (Hearing adjourned - 12:05)
23 (END OF PROCEEDINGS)
24
25
AOGCC 4/19/2023 ITMO: OIL SEARCH ALASKA
Docket No. C0-23-003
329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net
Computer Matrix, LLC Phone: 907-227-5312
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 02 through 75 are a true,
4 accurate, and complete transcript of proceedings in
5 Docket No.: CO-23-003, transcribed under my direction
6 from a copy of an electronic sound recording to the
7 best of our knowledge and ability.
8
9
_______________ _______________________________
10 DATE SALENA A. HILE, (Transcriber)
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Pool Rules ApplicationNanushuk Reservoir
18 April 2023
1NANUSHUK POOL RULES
2
Agenda
Pikka Unit Pool Rules Application
Subject Time Speaker
Presentation Introduction 5 min Andy Bond
1.Ownership & Development Area 5 min Tim Jones
2.Geoscience Overview
-Geology
-Exploration/Delineation History
-Reservoir Description
10 min Christian Noll
3.Reservoir & Production Overview
-Development Plan
-Production & Recovery Forecast
-Fluid Properties
-Reservoir Management
-Specialized Waivers
20 min Andy Bond
4. Surface Facilities 10 min Andy Bond
5.Pikka –Drilling & Completions
-Well Construction
-Completion Plans
10 min Rob Tirpack/Marc Kuck
NANUSHUK POOL RULES
PikkaOwnership & Development Area
Tim Jones
3
1
NANUSHUK POOL RULES
4
Nanushuk Oil Pool Defined Area
NANUSHUK POOL RULES
Ownership and Development Area
+Proposed Nanushuk Oil Pool is co-incident with Pikka Unit
+Santos, through its subsidiary Oil Search (Alaska), LLC, is
Operator and 51% working interest owner of the Pikka
Unit; Repsol E&P USA LLC owns the remaining 49%
working interest
+Surface owners of the proposed Nanushuk Oil Pool area
include:
─Kuukpik Corporation
─the State of Alaska
─Heirs, Devisees and/or Assigns of Neil Allen
─Katherine Brown
─Jim T. Allen
─Estate of Helen E. Tukle
Proposed
Nanushuk
Oil Pool
PikkaGeoscience Overview
Christian Noll
5
2
NANUSHUK POOL RULES
6
Nanushuk Oil Pool Definition (Qugruk-3 type log)
NANUSHUK POOL RULES Nanushuk Oil PoolTop Nanushuk
Top Torok Fm
Top NT3
Top of Pool (Upper Confining Interval) defined by the Top
Nanushuk Formation:
+Confining layer is the Lower Seabee Formation above the Top Nanushuk
reservoir
+The base of the Seabee Formation is shale-dominated marine flooding
surface comprising condensed mudstone facies and overlying shale
+~1000 ft TVT thick
Base of Pool (Lower Confining Interval) defined by the Top Torok
Formation (Bottomset shales down to Top Torok Fan)
+Underlies the target Nanushuk Formation
+Comprises interbedded claystone, silty shales and thick shale sequences
+~250 ft TVT thick
7
Pikka Unit Stratigraphy -Qugruk-3 type log
NANUSHUK POOL RULES
8
+Depositional Setting: deltaic shelfal deposits representing the
topset equivalent of deeper water shale-dominated Torok Fm
(deposition from overall west to east prograding clinoform system
with wave reworking along the shelf)
+Trend : Elongate reservoir geometry associated with NNE shelf
margin orientation
+Depth: 3900 –4250ft SSTVD
+Trap : combined structural & stratigraphic trap (updip thinning to
west and shelfal termination to shale downdip to east) Robust
topseal from overlying Seabee Formation
+Lithology: fine to very fine interbedded sandstone, siltstone and
claystone
+Oil quality: 24-30°API oil gravity
+Net pay: 140 ft average
+Porosity: 22% average
+Permeability: 60 mD average
+Water Saturation: 41% average
Geology Overview
NDB
NANUSHUK POOL RULES
9
Net Pay 105 ft
Ave Phi 24%
Ave Perm 109 mD
Ave Sw 36%
Nanushuk Log Model Overview –Qugruk 8
NANUSHUK POOL RULES
10
Pikka Exploration & Appraisal Data
NANUSHUK POOL RULES
Integrated Reservoir Characterization from TeraMerge 3D Seismic, Appraisal Well Logs & Whole Core tuned to Flow Test results
+Subsurface characterization is built upon
robust appraisal dataset across the Pikka
Unit and adjacent area:
─20+ well penetrations
─11 wells with rock samples
─3+ wells with continuous core: 1,084 ft
─10 wells with RSWCs (156 in total)
─9 wells with high-definition image logs
─5+ wells with successful flow test data
Overview Nanushuk Exploration & Appraisal Data
NDBPikka B / B ST1 8 (Oil Search 2019)
Logs High Res Wireline / LWD
Core 780’ Whole Core
Side wall cores
Test Single Frac Production Test
Peak Rate 2,800 BOPD
Pikka C / C ST1 (Oil Search 2019)
Logs High Res Wireline / LWD
Core Side wall cores
Test
Horizontal 6 stage Frac
Production Test
Peak Rate 2,000 BOPD
Fiord 2 & 3 (ARCO 1994 /1995)
Logs Low Res LWD/WL
Core Side wall cores
Qugruk 7 (Repsol 2014)
Logs Low Res LWD
Test
Production Test
Peak Rate: unstable
Average Rate 24 BOPD
Qugruk 3 (Repsol 2013)
Logs High Res Wireline
Core Side wall cores
Qugruk 8 (Repsol 2015)
Logs High Res Wireline
Core 240’ Whole Core
Side wall cores
Test Single Frac Production Test
Peak Rate 2,000 BOPD
Qugruk 9/9A (Repsol 2015)
Logs High Res Wireline
Core Side wall cores
Qugruk 1 (Repsol 2013)
Logs Low Res LWD/WL
Core Side wall cores
Qugruk 301 (Repsol 2015)
Logs Low Res LWD
Test
Horizontal 6 stage Frac
Production Test
Peak Rate 3,900BOPD
140’
0’
Net Reservoir
isochore
PikkaReservoir & Production Overview
Andy Bond
11
3
NANUSHUK POOL RULES
12
Nanushuk Well Layout Considerations
NANUSHUK POOL RULES
43 Development wells: 41 Nanushuk & 2 Alpine C wells
+Well Layout:
─Alternating injector/producer pairs in line drive patterns to maximize areal sweep efficiency
─Well orientation designed to achieve longitudinal fracs
─~6,000 foot horizontal lateral sections with ~12 fracs per lateral to maximize vertical sweep efficiency
+Well Spacing:
─1,800’ inter-well spacing is planned
+Depth Considerations:
─Well trajectories will be placed ~60' below the top of the Nanushuk surface
─Landing depth near base of amalgamated sand section to improve fracture initiation and long-term connection to wellbore
+Drill Order:
─Drill order optimized for 1st year of drilling, considering many factors
─Early data gathering planned to determine reservoir quality and validate development plan
─Extra LWD and open hole logging
─Frac micro-seismic testing
─Interwell pulse testing over single and double well spacing distances
Qugruk-3
NDB-039 NDB-051 NDB-011
5:1 VE
Alpine C
NDA
NDB
NPF
A
A’
A
A’
Producer
Injector
Potential
Wider
Spacing
13
Fluid Properties–Nanushuk 3 Reservoir
NANUSHUK POOL RULES
+Pikka Phase 1 Fluid Properties from Qugruk 8 well represent average for new development
+There is a compositional gradient in the vertical direction and some variability from North to South. (see API vs depth for north and south trends)
+Samples to the north have higher C8-10 and samples to the south have a higher C30+ but really look and behave very similarly
+Pikka Phase 1 will primarily produce from oil representative of samples from the North including wells Q3, Q301, Q8, Pikka C, Q9A
-4800
-4700
-4600
-4500
-4400
-4300
-4200
-4100
-4000
-3900
-3800
20 22 24 26 28 30 32 34
API gravity (contamination<5%, DL residual)
PIKKA C QUGRUK 7 PIKKA B
PIKKA B ST1 HORSESHOE 1 QUGRUK 8
QUGRUK 301 QUGRUK 3 QUGRUK 9A
QUGRUK 1 PIKKA C ST1 South trend BOT
North trend BOT
API GravityDepth, ftFluid Property –Well Qugruk 8
Reservoir Temperature (deg F)102
API Gravity (deg API)29.3
Saturation Pressure -BP (psia)1561
Fluid Viscosity (cp)2.04
Fluid Density (g/cc)0.88
Solution GOR (scf/bbl)430
Formation Volume Factor (rb/stb)1.177
Oil Compressibility (1/psi)6.60e-6
Sample composition
variation used in simulation
model
Fluid Samples Collected
14
Nanushuk Oil Pool Datum Pressure
NANUSHUK POOL RULES
+Pikka Nanushuk pressure show subtle baffles across the field
+Pikka Nanushuk oil is vertically graded ~31 –25 API
+Datum pressure 1895 psi at 4100 ft TVDSS
+Datum pressure gradient = 0.3504*TVDSS+459.59
Nanushuk Formation Oil Pressure Datum:
15
Pikka Phase 1 Profiles (Includes 41 Nanushuk & 2 Alpine Wells)
NANUSHUK POOL RULES
+Nanushuk Production Facility (NPF) startup in 2025/2026
+Waterflood initially driven by water supply from new-build seawater treatment
plant, with very clean water (nano-filtration and sulfate removal).
+Produced water initially disposed of, but later switched to injection into the
reservoirs after rate is high enough to avoid freezing issues in the line from the NPF
to NDB. Separate header to avoid mixing seawater with produced water in pipelines
and wells to avoid scale buildup
+Gas handling limited production to 90 MMSCFD (i.e., gas compressor capacity)
+Fuel gas requirement of 20 MMSCFD (3 MMSCF at the drill site from
indigenous gas, 10 MMSCFD at NPF, and 7 MMSCFD at STP).
+Lift gas rate ramps from 40 MMSCFD to nearly 90 MMSCFD later in life due to
increasing well stock and rising water cuts
+Reservoir gas injection for the MWAG EOR project limited by injection
compressors at just under 40 MMSCFD.Reservoir gas injection is a requirement to
avoid flaring and lack of gas sales
Full field rate streams –fuel gas import at start up
0
20
40
60
80
100
2020 2025 2030 2035 2040 2045 2050Liquid Rate (MBLPD)Liquid Rate (MBLPD)
Total Water Rate (MBWPD)
Water Injection rate (MBWPD)
Water import (MBWPD)
Total Oil Rate (MBOPD)
0
20
40
60
80
100
2020 2025 2030 2035 2040 2045 2050Gas Rate (MMSCFD)Formation Gas Production (MMSCFD)
Gas Injection Rate (MMSCFD)
Gas import (MMSCFD)
Gas Lift Rate (MMSCFD)
Total Gas (MMSCFD)
Phase 1 Modelled Facility Capacities NDB Pad
Oil (nameplate oil capacity)80,000 BOPD
Water Handling Produced water 90,000 BWPD
Seawater 100,000 BWPD
Injection 100,000 BWPD
Gas Compression Lift + Formation Gas 90 MMSCFD
Injection gas 40 MMSCFD
16
Production and Recovery Projections
NANUSHUK POOL RULES
+Initial Nanushuk 41 well development (from drill site “NDB”)
─Official 2P Reserves Booking for Phase 1 is 397 MMBO –including 2 Alpine wells
─Expected Ultimate Recovery (Nanushuk): ~383 MMSTB (211 –476 MMSTB)
─Expected Recovery Factor (Nanushuk -Combined WF & WAG EOR): ~37%
─Expected Peak Annual Rate: 80,000 BOPD
+Progressing 2 additional drill sites to develop remaining resources in Unit
17
Produced Water Disposal Plan
NANUSHUK POOL RULES
Dedicated disposal well until sufficient volume to inject into waterflood
+NPF Disposal Well Planned
─Injection into the Ivishak interval, 10,000 BWPD nominal
─Class 1 permit pending with EPA
─Three wells to be permitted, plan to begin with one and test capacity
─Produced water and NPF process fluids
+Injection Into Pikka Waterflood once Volumes Sufficient
─Dedicated PW injection system –no mixing with SW
─~10,000 BWPD needed to prevent freezing PW injection line to NDB
─Models suggest 5-6 years to reach this level
─Begin converting Pikka injection wells as volumes increase
─Begin with patterns of high injectivity and large SW injected volumes
─Plan to process PW to minimize particulates and oil carryover
18
Reservoir Management & Surveillance Plans
NANUSHUK POOL RULES
+Reservoir Management
─Line drive waterflood/WAG injection into horizontal wells with multi-stage frac treatments to maximize recovery
─Maintain average reservoir pressure +/-200 PSI of initial conditions
─VRR ratio long term of greater than 1.0
─Utilizing ultra filtered and sulfate removed seawater for injection to maximize long term injectivity
+Surveillance
─Regular well tests
─Regular pressure tests and surveys (static and pressure transient analysis)
─Surveillance logging (likely to be mainly in injection wells due to difficult tool access in producers)
19
Specialized Rule Waiver Requests
NANUSHUK POOL RULES
+Well Spacing (Rule 3)
─No well spacing restrictions other than no closer to 500’ from Unit boundary
+GOR Exemption (Rule 9)
─Wells producing from the Nanushuk Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC
25.240(a) in accordance with the provisions of 20 AAC 25.240(b)
PikkaSurface Facilities
Andy Bond
20
4
NANUSHUK POOL RULES
21
Pikka Phase 1 Development Concept
NANUSHUK POOL RULES
Phased development with modular facilities reduces initial capital requirements
+Pikka Phase 1 development builds out initial processing facility, drill site, sea water treatment
plant and operations pad
+Nanushuk Processing Facility (NPF) modular design approach with two 40 MBOPD processing
facility trains
–Expandable in 40 MBOPD standardized increments
–River lift and truckable modules from Canada
+Seawater Treatment Plant (STP)
–100 MBWPD capacity
–Expandable to 165/200 MBWPD
–Injection booster pumps at NPF
+Support Infrastructure
–Grind & Inject (G&I) and produced water disposal (NPF)
–Operations Pad (NOP)
–Drill Site and Tie-In Pad (NDB & TIP)
–MPM's planned for drill site well testing
–Pipelines
+Facility Details
–~180 PSI Inlet pressure, NDB to heat fluids to >100 F
–Gas Lift pressure ~1,400 psi, Gas Injection pressure ~3,200 psi
–Sales oil pumps and metering delivering oil to CPF-2 tie-in to KTC
Phase 1 NDB Pad
Oil (nameplate oil capacity)80 MBOPD
Water
Handling
Produced Water 90 MBWPD
Seawater Treatment Plant 100 MBWPD
Injection 100 MBWPD
Gas Compression Lift Gas 90 MMSCFD
Injection Gas 40 MMSCFD
Overview Development Schematic(1)
Capacities
Project Scope
(2)
(1)Kuparuk River Unit (KRU), operated by ConocoPhillips, and ENI facilities shown for reference only.
(2)May include KTC line.
22
Waterflood & Gas EOR Planned
NANUSHUK POOL RULES
New Build STP Planned with Ultra Filtration and Sulfate Removal to Optimize Ultimate Recovery
+OSA Seawater Treatment Plant (STP)
–100 MBWPD capacity
–Expandable to 165/200 MBWPD
+Ultra-Filtration and Sulfate Removal improve long term Nanushuk recovery
–Significant reduction in pipeline and tubular corrosion rates and products
–Significant reduction in SRB’s and H2S in the reservoir and facilities
–Further reduction of BaSO4 scaling tendencies
–Third party studies confirm these benefits
+Nanushuk reservoir has generally small pore throats
–Susceptible to damage and blocking from particulates
–Core studies completed which confirm this current understanding
–Multi-stage frac completions will help overcome injection issues
+Gas EOR WAG Program Planned
–40 MMSCFD Gas Injection capacity planned
–Provides incremental oil recovery over life of field
–Plan to import fuel gas and use indigenous gas and NGL’s for flood
Overview
STP
23
Well Metering at NDB Pad
NANUSHUK POOL RULES
Continuous gas-lift, water and gas-injection each well. Multi-phase flowmeter for well testing.
Test header, MPFM
+Empty Pipe reference (initially, bi-annually)
+Input oil, gas (separator S.G.), water densities
from PVT analysis; each well will have a different
oil density (sampled during flowback and during
offset gas-injection)
+Perform in-situ Mass Attenuation measurements
for gas & oil:
–Gas –route lift gas through meter, compare with
input gas calc MA’s and master GL meter
–After EOR Bleed gas from shut-in well through
meter for formation gas density
–Oil –use sample from flowback & route into meter
compare with input oil viscosity, sulfur & C6 fraction
calculated MA’s
24
Fluid Metering at NPF and Volume Allocations
NANUSHUK POOL RULES
+Raw daily oil/w/gas = calculated from test data (at least twice per month for each producer)
─Oil & Water from last well test x uptime%
─Formation gas = (Meter gas –Lift Gas )x uptime%
─Field Raw daily o/w/g =Σ well daily o/w/g
+Metered o/w/g at NPF Facility
─Oil : LACT (Coriolis) meter + slop oil tank gain(loss)
─Gas: Fuel + flare + Injected gas (master meter)
─Water: Injected water meter + water tank gain/(loss)
+Allocation factor = metered daily fluid (o/w/g)/Field Raw daily o/w/g
+Allocated daily oil/w/gas = Raw daily o/w/g * Allocation Factor
PikkaDrilling & Completions Overview
Rob Tirpack & Marc Kuck
25
5
NANUSHUK POOL RULES
26
Drilling Overview
NANUSHUK POOL RULES
Rev 12
27
Well Design Summary –Tier 1 & Tier 2
NANUSHUK POOL RULES
Conductor
+20” Insulated Conductor
Surface
+16” hole size, 13-3/8” Casing
+KOP @ 300’, Max 3°/100, set @ ~2,200’
TVD
Intermediate 1
+12-1/4” hole size, 9-5/8” Liner w/tieback
+Build to tangent, hold & build to land
horizontal in pay
+Single or 2-stage cement job –isolation of
Nanushuk sands and Tuluvak sand
Production / Lower Completion
+8-1/2” hole size, 4-1/2” Lower Completion
Mud Program (All Wells)
+Surface Hole: Water Based Mud
+INT & PROD Holes: MOBM
*Dog nose plot based on Rev11 well set
Tuluvak Sand
28
Well Design Summary –Tier 3
NANUSHUK POOL RULES
Conductor and Surface
+Same as Tier 1 & 2
Intermediate 1
+12-1/4” hole size, 9-5/8” Liner w/tieback
+Build to tangent and hold
+Setting depth used to break up long INT section
+Single or 2-stage cement job –isolation of
Tuluvak sand
Intermediate 2
+8-1/2” hole size, 7” Liner
+Hold tangent and build to land horizontal in pay
+MPD
+Cement job –isolation of Nanushuk sands
Production / Lower Completion
+6-1/8” hole size, 4-1/2” Lower Completion
+MPD
Tuluvak Sand
Nanushuk
29
Well Design Summary –Other Designs
NANUSHUK POOL RULES
G&I Well –2 string Ultra Slim Hole PWD Well –3 string Slim Hole Tier 4 –4 string Big Bore
30
Completions
NANUSHUK POOL RULES
+4-1/2” 12.6ppf P110S TSH563 Tubing/Liner
+Completion Liner
─Eccentric Shoe
─Shutoff Collar
─Toe Sleeves
─Frac Sleeves (Collet/Ball)
─Hydraulic Set Openhole Packers
─Liner Hanger/Packer
+Upper Completion
─Tieback Seal Assembly
─Landing Nipples
─Downhole Temp/Psi Gauge (Injector Wells)
─Surface Controlled Gaslift System & P/T Gauge
(Producer Wells)
─Shallow GLM –fluid swap
31
Completions
NANUSHUK POOL RULES
+Stimulation
─Multi-Stage Open Hole Fracturing
─Specialized Cross-Link Fluids
─Ceramic Proppant
─Longitudinal Fracture Orientation
─Average ~2.5mm lbs Prop Per Well
+Well Cleanup and Flowback
─Cleanup After Stimulation Operations
─Fluids Disposal Onsite, Class I Well
─Minimized Trucking / Transfers
+Well Suspension
─Prep Wells for Facilities Startup
─Approximately 62% wells completed
32
Proposed NOP Rules
The rules set forth apply to the following area referred to in this order:
Pikka Unit Boundary as defined by November 29, 2016 DNR approval.
Rule 1: Field and Pool Name
The field is the Pikka Field, and the pool is the Nanushuk Oil Pool
Rule 2: Pool Definitions
The Nanushuk Oil Pool is defined as the accumulation of oil and gas common to and correlating to the stratigraphic interval between 3,892 and 5,166 feet measured depth in the Qugruk-3 well and its lateral equivalents.
Rule 3: Well Spacing
There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line.
Rule 4: Casing and Cementing Practices
a) After drilling no more than 50 feet below a casing shoe set in the Nanushuk Oil Pool, a formation integrity test must be conducted. The test must indicate sufficient pressure exists before drilling operations can be continued.
b) Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based on sound engineering principles.
c) Production casing cement volumes will be sufficient to place cement a minimum of 500 feet measured and 250 feet vertical depth, whichever is greater, above the top of the Nanushuk Oil Pool in all wellbores.
d) Permit(s)to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b)
e) In lieu of the requirements of 20 AAC25.071(a), petrophysical logs obtained from nearby exploration wells or wells drilled to other oil pools from the drilling pad may be submitted to meet these requirements.
Proposed Rules Summary
NANUSHUK POOL RULES
33
Rule 5: Well Safety Valve Systems
Surface safety valves will be installed in all vertical trees. All wells drilled within the NOP will abide by the regulations set forth in 20 AAC 25.565 with the following modification to 20 AAC 25.565(d)(5) for
all injection wells (except disposal).
Safety valve systems must be maintained in good working order at all times and must be tested at six-month intervals or on a schedule prescribed by the Commission.Sufficient notice must be given so
that a representative of the Commission can witness tests, if desired.
Nipple profiles will be installed to allow for subsurface injection check valves if deemed necessary.
Rule 6: Injection Well Completion
Packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the
distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth.
An approved injection order is required prior to commencement of injection in this pool.
Rule 7: Common Production Facilities and Surface Commingling
a) Production from the Nanushuk Oil Pool may be commingled at the surface prior to custody transfer.
b) Allocation factors for produced fluids will be based on well tests, daily well allocation and total production as measured at the NPF.
c) Each producing well must be tested once per month.
d) The Commission may require more frequent or longer tests if allocation quality deteriorates.
e) The operator shall submit a monthly report and electronic files containing daily allocation data and daily test data for agency surveillance and evaluation.
f) The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report.
Proposed Rules Summary
NANUSHUK POOL RULES
34
Rule 8: Reservoir Pressure Monitoring
a) A bottom-hole pressure survey shall be taken on each well prior to initial sustained production or injection.
b) The Operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery processes subject to an annual plan outlined in paragraph (e) of this rule.
c) The reservoir datum will be 4,100’ SSTVD for the Nanushuk Oil Pool.
d) Pressure surveys may consist of stabilized static bottomhole pressure measurements, pressure fall-off, pressure build-up, multi-rate tests and formation tests or other appropriate technical pressure transient or static tests.
e) Data from the surveys required in this rule shall be filed with the Commission by April 1 of the subsequent year to the year in which the surveys are conducted. Along with the survey submittal, the operator will provide a proposed survey plan for the upcoming year. The proposed plan shall be deemed accepted if the operator has not received written correspondence from the Commission within 45 days.
f) Reservoir pressure report, Form 10-412, shall be utilized for all surveys with attachments for complete additional data. Data submitted shall include rate, pressure, depth, fluid gradient, temperature, and other well conditions necessary for complete analysis of each survey being conducted.
g) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule.
Rule 9: Gas Oil Ratio Exemption
Wells producing from the Nanushuk Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) in accordance with the provisions of 20 AAC 25.240(b).
Rule 10: Annual Reservoir Review
An annual report must be filed on or before April 1 of each year.The report shall include an overview of reservoir performance, future development and reservoir depletion plans, and surveillance information for the prior calendar year. Report details shall include the following:
a) Reservoir pressure maps at datum.
b) Summary and analysis of reservoir pressure surveys.
c) Reservoir pressure estimates.
d) Results and, where appropriate, analysis of production, temperature, tracer surveys, observation well surveys, and any other special monitoring surveys.
e) Estimates of yearly production and the reservoir voidage balance of injection and withdrawals at standard and reservoir conditions.
f) Progress of plans and tests to expand the productive limits of the pool.
g) Results of surface safety valve testing.
Proposed Rules Summary
NANUSHUK POOL RULES
35
Rule 11: Well Mechanical Integrity and Annulus Pressures
a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement 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 development well daily to check for sustained pressure, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection.
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 2000 psig or (ii) sustained outer annulus pressure that exceeds 1000 psig.
d) The Commission may require the operator to submit in an Application for Sundry Approvals (Form10-403), a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph "c" of this rule. The Commission may approve the operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests.
e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% 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% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall immediately notify the Commission and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form10-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests.
f) Except as otherwise approved by the AOGCC under paragraph "d" or "e" of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree that (i) the inner annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC prescribes a different limit.
Rule 12: Administrative Action
Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule if the change does not promote waste or jeopardize correlative rights, is based upon sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater.
Proposed Rules and summary
NANUSHUK POOL RULES
36NANUSHUK POOL RULES
QUESTIONS?
37NANUSHUK POOL RULES
2
Notice of Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Re: Docket Number: CO-23-003
Oil Search (Alaska), LLC (OSA), by letter dated March 6, 2023, requested the Alaska Oil and Gas
Conservation Commission (AOGCC) establish pool rules for the Nanushuk Oil Pool in the Pikka Unit.
Pool rules are applied for under 20 AAC 25.520 for the purpose of prescribing rules, that differ from
the normal statewide rules found in 20 AAC 25, for the development of a defined pool. The rules are
established to streamline the development of the pool while still protecting correlative rights and
ensuring maximum recovery.
A pool is an underground reservoir containing, or appearing to contain, a common accumulation of oil
or gas. Absent an order to the contrary, the statewide rules found in 20 AAC 25 govern development
of oil or gas pools. However, sometimes an operator will apply to the AOGCC for an order to establish
pool rules to govern a specific pool. Pool rules typically define the vertical and map extent of a
particular pool and establish rules that modify the statewide requirements to enable more efficient
operations while providing an equally effective means of protecting underground freshwater,
protecting correlative rights, and conducting safe and environmentally sound operations. OSA is
applying for rules related to well construction, safety valves, and reservoir operations.
This notice does not contain all the information filed by OSA. You may obtain more information about
this filing by contacting the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793-1223 or
samantha.carlisle@alaska.gov.
A public hearing on the matter has been scheduled for April 18, 2023, 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: 665 332 079#. Anyone who wishes to participate remotely using MS Teams video
conference should contact Ms. Carlisle at least two business days before the scheduled public hearing
to request an invitation for MS Teams.
In additions, written comments regarding this application may be submitted to the AOGCC at 333
West 7th Avenue, Anchorage, AK 99501 or samantha.carlisle@alaska.gov. Comments must be
received no later than the conclusion of the April 18, 2023, hearing
If, because of a disability, special accommodations may be needed to comment or attend the hearing,
contact Samantha Carlisle at (907) 793-1223, no later than April 13, 2023.
Brett W. Huber, Sr.
Chair, Commissioner
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.03.14 15:18:11
-08'00'
Bernie Karl
K&K Recycling Inc.
P.O. Box 58055
Fairbanks, AK 99711
mailed 3/14/23
From:Carlisle, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] CO-23-003 Public Hearing Notice OSA pool rules
Date:Tuesday, March 14, 2023 3:21:46 PM
Attachments:CO-23-003 Public Hearing Notice OSA pool rules.pdf
Re: Docket Number: CO-23-003
Oil Search (Alaska), LLC (OSA), by letter dated March 6, 2023, requested the Alaska Oil
and Gas Conservation Commission (AOGCC) establish pool rules for the Nanushuk Oil
Pool in the Pikka Unit.
Samantha Carlisle
AOGCC Special Assistant
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
(907) 793-1223
__________________________________
List Name: AOGCC_Public_Notices@list.state.ak.us
You subscribed as: samantha.carlisle@alaska.gov
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1
Page 1 of 1
Oil Search (Alaska), LLC a subsidiary of Santos Limited
900 E. Benson Blvd.
Anchorage, Alaska 99508
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
March 6, 2023
VIA EMAIL TO: SAMANTHA.CARLISLE@ALASKA.GOV
Brett Huber, Chair
Jesse Chmielowski, Commissioner
Greg Wilson, Commissioner
Alaska Oil and Gas Conservation Commission
333 W 7th Ave.
Anchorage, AK 99501
Re: Application to Establish Pool Rules for the Nanushuk Oil Pool
Dear Commissioners:
Oil Search (Alaska), LLC, a subsidiary of Santos Limited (Santos), as Operator of the Pikka Unit,
hereby submits the enclosed application requesting approval to establish Pool Rules for the
Nanushuk Oil Pool. This document will provide information to classify the Nanushuk reservoirs in
the Pikka Unit as an Oil Pool and to prescribe rules to govern development and management of the
proposed NOP in accordance with 20 AAC 25.520.
Santos requests that the hearing date for this application be scheduled as soon as possible after
the 30-day public notice period has concluded. If you have additional questions or concerns, please
contact me at 907-375-4624 or via email at Tim.Jones3@santos.com.
Thank you for your consideration.
Sincerely,
Tim Jones
Land Manager
Ecc: Dave Roby, Senior Petroleum Engineer (Dave.Roby@alaska.gov)
Derek Nottingham, Director, ADNR Division of Oil and Gas (Derek.Nottingham@alaska.gov)
Erik Kenning, Senior Director of Lands and Natural Resources, ASRC (EKenning@asrc.com)
Enclosure: Nanushuk Pool Rules Application
By Samantha Carlisle at 10:23 am, Mar 07, 2023
January 9, 2023
Nanushuk Pool Rules Application
Pikka Unit, North Slope of Alaska
Santos Ltd
This document will provide information to classify the Nanushuk reservoirs in the Pikka Unit as an Oil Pool
and to prescribe rules to govern development and management of the proposed NOP in accordance with 20
AAC 25.520.
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
2
Contents
Introduction ...................................................................................................................................................... 4
Document Scope ............................................................................................................................................ 4
Geographical Area ......................................................................................................................................... 4
Project Background ........................................................................................................................................ 6
Geology ............................................................................................................................................................. 7
Pool Identification ........................................................................................................................................... 7
Lower Confining Interval ............................................................................................................................. 8
Upper Confining Interval ............................................................................................................................. 8
Stratigraphy and Sedimentology .................................................................................................................... 8
Structure and Trap ......................................................................................................................................... 8
Reservoir Formation Evaluation .................................................................................................................... 9
Porosity, Permeability, and Water Saturation ................................................................................................ 9
Reservoir Fluids and Pressure, Volume and Temperatures (“PVT” Properties) ............................................ 9
OOIP and Volumetrics .................................................................................................................................... 9
Reservoir development plan ......................................................................................................................... 10
Base Development Plan ............................................................................................................................... 10
Recovery Mechanisms ................................................................................................................................. 10
Producing Gas-Oil Ratio expectations ......................................................................................................... 11
Well Conversion Strategy ............................................................................................................................. 11
Drilling and Completion ................................................................................................................................ 11
Drilling Strategy ............................................................................................................................................ 11
Completion Strategy ..................................................................................................................................... 12
Drilling Fluids ................................................................................................................................................ 17
Blowout Prevention ...................................................................................................................................... 17
Directional Drilling ........................................................................................................................................ 17
Well Spacing................................................................................................................................................. 17
Logging Operations ...................................................................................................................................... 17
Well operations .............................................................................................................................................. 17
Well design and completions........................................................................................................................ 17
Artificial Lift ................................................................................................................................................... 18
Side-tracks.................................................................................................................................................... 18
Reservoir Surveillance ................................................................................................................................. 18
Sustained Casing Pressure Rules ............................................................................................................... 18
Well Work Operations .................................................................................................................................. 18
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
3
Surface Safety Valves .................................................................................................................................. 19
Facilities .......................................................................................................................................................... 19
Introduction and Scope ................................................................................................................................ 19
Drill Site Facilities ......................................................................................................................................... 19
Nanushuk Processing Facility ...................................................................................................................... 19
Production Allocation .................................................................................................................................... 20
Proposed NOP Rules ..................................................................................................................................... 21
Rule 1: Field and Pool Name ....................................................................................................................... 21
Rule 2: Pool Definitions ................................................................................................................................ 21
Rule 3: Well Spacing .................................................................................................................................... 21
Rule 4: Casing and Cementing Practices .................................................................................................... 21
Rule 5: Well Safety Valve Systems .............................................................................................................. 21
Rule 6: Injection Well Completion ................................................................................................................ 21
Rule 7: Common Production Facilities and Surface Commingling .............................................................. 22
Rule 8: Reservoir Pressure Monitoring ........................................................................................................ 22
Rule 9: Gas Oil Ratio Exemption ................................................................................................................. 22
Rule 10: Annual Reservoir Review .............................................................................................................. 22
Rule 11: Well Mechanical Integrity and Annulus Pressures ........................................................................ 22
Rule 12: Administrative Action ..................................................................................................................... 23
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
4
Introduction
Document Scope
This application for Pool is submitted for approval by the Alaska Oil and Gas Conservation Commission
(“AOGCC”) to define the proposed NOP (“Nanushuk Oil Pool”) and establish Pool Rules for the oil pool
pursuant to 20 AAC 25.520.
Oil Search (Alaska), LLC, a subsidiary of Santos Ltd (Santos), in its capacity as operator of the Pikka Unit,
submits this document to the AOGCC on behalf of itself and other working interest owner (WIO) Repsol E&P
USA LLC (Repsol). The scope of this application includes a discussion of geological and reservoir properties of
the proposed NOP as they are currently understood, and Santos’s plans for reservoir development, reservoir
surveillance, well construction, and well operations. Prior to commencing injection, Santos, will obtain an Area
Injection Order by the Commission to authorize water-alternating-gas (WAG) operations for the proposed NOP.
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 Nanushuk Oil Pool.
Confidential data and interpretation concerning the Nanushuk Reservoir, as defined below in this application,
may be provided to the AOGCC by Santos as additional support for this application in accordance with the
provisions of AS 31.05.035 and 20 ACC 25.537.
The proposed area to be covered by the NOP Rules coincides with the Pikka Unit boundary as depicted in blue
on Figure 1. The Nanushuk Oil Reservoir does extend outside the unit boundary to the south and to the west of
the Pikka Unit into leases operated by ConocoPhillips Alaska, Inc (CPAI) as proven by recent delineation wells
drilled in those areas as well as recent seismic interpretations. While the Pikka WIOs plan to form a separate
participating area for Nanushuk oil within the unit, the intent of the pool rules and AIO application will be to align
development strategies and minimize waste across the Pikka Unit boundary and any future expansion acreage.
Geographical Area
Santos is pursuing a project for the development of hydrocarbon deposits from its unitized oil and gas leasehold
on the North Slope of Alaska. The Pikka Development Project (“Project”) targets oil deposits in the Nanushuk
and Alpine reservoirs. The Project area was unitized in 2015 and expanded to the current Pikka Unit on
November 29, 2016. Santos plans to drill wells, construct, and operate infrastructure to produce and transport
crude oil to the Trans-Alaska Pipeline System through the Kuparuk Pipeline Extension, operated by the
Kuparuk Transportation Company.
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
5
Figure 1: Pikka Unit Boundary and leases. Also labelled are the permitted drill sites NDA, NDB, and NDC as well as the
central processing facility NPF
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
6
Project Background
Santos, along with predecessor Unit Operators Repsol and Armstrong Energy, LLC, have conducted significant
reservoir evaluation consisting of seismic, geologic, and engineering studies; drilled exploration and appraisal
wells; and have completed civil works operations to construct the gravel infrastructure necessary for
development of the Unit area.
In total, there are 20+ known penetrations regionally into the Nanushuk, out of which 6 wells had successful
flow test data and 4 wells with Nanushuk core. Key wells and associated side-tracks, important to the
delineation of the Nanushuk within the Pikka Unit are Qugruk-3, Qugruk-3A, Qugruk-7, Qugruk-301, Qugruk-8,
Qugruk-9, Qugruk-9A, Fiord-2, Fiord-3, Pikka B, and Pikka C.
Under the current development plan, the Project consists of the Nanushuk Processing Facility (NPF); Nanushuk
phase 1 drill site “B,” and future drill sites “A” and “C” (ND-A, ND-B, and ND-C); the Nanushuk Operations Pad;
infield pipelines, import and export pipelines; infield and access roads; and a tie-in pad (TIP) at the CPAI
Central Processing Facility 2 (CPF2). A new build seawater treatment plant (STP) will be built at Oliktok Point to
supply filtered and desulphated seawater for secondary recovery injection. The Nanushuk Pipelines and
Cables consist of import and export pipelines and cables from and to the NPF and the TIP. They include an oil
export pipeline, a seawater pipeline, a fuel gas pipeline, and a fibre optic cable.
The multi-phase fluids from each drill site will be transported to the NPF. The fluids are processed at the NPF
and the sales oil is exported to the Kuparuk Transportation’s common carrier oil pipeline to deliver sales oil to
the Trans-Alaska Pipeline. The produced water separated at the NPF will initially be disposed into the Ivishak
disposal zone and then when sufficient volume is available, will be delivered to the drill sites and injected into
the producing formation. The produced gas is compressed and dehydrated at the NPF and used as fuel gas, lift
gas, and injection gas. Fuel gas may be imported from outside the Pikka Unit to preserve indigenous gas for
enhanced oil recovery injection. All Nanushuk injection wells will be Water Alternating Gas (WAG) injection
wells. All Nanushuk Reservoir production will be measured as described in Section: Reservoir Surveillance,
page 18 of this application, without any down-hole commingling with production from other pools prior to
measurement. At NPF, the NOP production may be commingled with Alpine reservoir oil from a pool to be
defined prior to development. Subject to AOGCC approval of the facilities and measurement program, no
separate approval for commingling is necessary under the standards of 20. AAC 25.215 and 20 AAC 25.245.
Key milestones and target dates for the Pikka development project include the following:
o Final Investment Decision 3Q’22
o Pool rules submission 1Q’23
o Drilling Operations Start 2Q’23
o Facilities installation begins 2023
o First Oil Production 2Q’26
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
7
Geology
Pool Identification
The Nanushuk reservoir is a thick accumulation of deltaic shelf deposits and represents the shelfal topset
equivalent of the deeper water, shale dominated Torok Formation. The NOP is defined as the accumulation of
hydrocarbons common to and correlating with the interval defined by the Nanushuk formation, between
Nanushuk and Torok formation tops from measured depths of 3,892 and 5,166 ft or 3,785 ft true vertical depth
subsea (TVDSS) to 4,985 ft TVDSS shown on the Qugruk-3 well type log (Figure 2).
Figure 2 Qugruk 3 Type log
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
8
Lower Confining Interval
Torok Formation
Lithologic Description: The Torok Formation underlies the target reservoir Nanushuk Formation and
comprises interbedded claystone, silty shales and thick shale sequences. The formation grades from silty
shales in the upper sections to shale at the base of the Torok Formation. The shales are described in offset
wells as very fine grained, medium dark grey to dark brownish and greyish black and soft to easily friable. The
succession is dominated by tabular to platy cuttings with very well-developed laminations, and high organic
content overall with layers of organic/carbonaceous material. The fracture gradient for this sealing shale is 16.0-
17.0ppg.
Depth & Thickness: 5200 MD/5135 TVDSS, ~250ft TVT
Upper Confining Interval
Seabee Formation
Lithologic Description: The Seabee Formation immediately overlies the Nanushuk Formation. The base of
the Seabee is a shale-dominated marine flooding surface comprising condensed mudstone facies deposited
during a maximum transgression which creates a good regional seal. Distant volcanism occurred during its
deposition resulting in numerous tuffaceous bentonite interbeds. The Seabee Formation is a thick
shale/claystone dominated unit which represents the distal deep-water slope and basinal deposits of the more
sand and siltstone dominated Tuluvak Formation. The claystones within the Seabee Formation are described
as medium grey to dark grey, weakly fissile with local partings along laminations, with common micas and
scattered very fine lithic grains. The fracture gradient for this sealing shale is 14.0-15.2ppg.
Depth & Thickness: 3175ft MD/2830ft TVDSS, ~1000ft TVT
Stratigraphy and Sedimentology
The Torok and Nanushuk Formations are the lower portion of the Brookian sequence and are Lower
Cretaceous in age. The Lower Cretaceous section is a large-scale constructional siliciclastic clinoform system,
where the topset shelfal unit is the Nanushuk Formation and the slope-dominated foreset unit is the Torok
Formation.
The internal architecture of the system is comprised of multiple clinoforms, deposited in an overall
progradational, siliciclastic system that prograded from west to east across the basin. The development of the
NOP in the Pikka Unit contemplates the drilling of long horizontal wells across a number of different clinoforms
or prograding parasequence sets within the Nanushuk Formation.
Hydrocarbon-bearing sandstones within the Nanushuk are often present at the topset of the clinoforms and
comprise amalgamated sands that gradationally change from deeper clay-siltstone with abundant thinly
laminated mudstones to sand-prone topsets that were influenced by wave action on the shelf (which ultimately
winnowed clays from the uppermost successions).
Structure and Trap
NOP is defined by Nanushuk formation top which is a regionally strong marker in seismic data. The structure is
a monoclinal surface with only a small number of faults with minor fault offset (such as the Fiord Fault System).
The hydrocarbon accumulation is contained by a stratigraphic trap, with along strike and updip facies changes
providing lateral seals and the upper Nanushuk to Seabee formation a robust top seal.
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
9
Reservoir Formation Evaluation
Porosity, Permeability, and Water Saturation
There is a robust data base of core analysis for Nanushuk reservoir within the Pikka Unit. The main property
values are the following:
Property Minimum Maximum Mean
Total Porosity (pu) 4 28 17.5
Permeability (mD) 0.01 660 60
Water Saturation (%) 9 78 41
Reservoir Fluids and Pressure, Volume and Temperatures (“PVT” Properties)
Within Pikka Unit (~15 miles long in north-south and ~3 miles wide), Nanushuk fluid samples were collected from
nine wellbores and Alpine fluid samples were collected from two wellbores, in the forms of downhole MDT
samples, downhole DST samples, and surface separator samples. Among the oil samples, 12 Nanushuk samples
and four Alpine samples were analysed with full PVT study
On 1/21/2019, water samples were collected at -4,637’ TVDss and at -4,694’ TVDss from Pikka B wellbore and
confirmed to be collected from transition zone(s). Nanushuk free water level (FWL) is estimated between -4,950’
TVDss and -5,280’ TVDss. Each oil accumulation region might have its own FWL or multiple FWLs.
Table 1: Reservoir fluid properties for Nanushuk (main development area)
Reservoir name Nanushuk
Well name Pikka B Q8 Pikka C
Sample ID 03 1.01 05
Accumulation South Central North
Sample depth (TVDss) -4271' -4185' -4096'
Reservoir pressure (psia) 1955 1923 1898
Reservoir temperature (°F) 102 102 105
Stock tank oil API gravity (°) 26.1 29.3 30.4
Gas oil ratio (scf/stb) 405 430 378
Bubble point pressure, Pb (psi) 1609 1561 1631
Oil formation factor at Pb (rb/stb) 1.177 1.177 1.167
Oil viscosity at Pb (cP) 5.62 2.04 2.53
Oil compressibility at Pb (1E-6 /psi) 8.71 6.60 7.47
Gas gravity (multi-stage separator test) 0.842 0.829 0.768
Gas formation factor at Pb (rb/mscf) 1.406 1.406 1.439
OOIP and Volumetrics
The stock tank OOIP volumetric estimates for the NOP range from 2,297 to 2,814 MMSTB for the development
planned from the NDB and additional drill sites. The volumetric estimates are based off log data, core data
analysis, which have been used to describe the expected net pay within the pool area, as well as 3D seismic.
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
10
Reservoir development plan
Base Development Plan
The NOP will be developed in a phased approach initiated from existing infrastructure. Development of the
Pool will be completed in discrete phases to apply knowledge gained from previous phases and improve
recovery. The initial targets will be accessed from the NDB drill site and future targets may be accessed via
NDA and NDC. The table below summarizes the potential resource associated with NOP development.
Table 2: Estimated Nanushuk oil in place with recoverable volumes associated with different recovery mechanisms.
Nanushuk Reservoir Range (MMSTBO)
Original Oil in Place (OOIP) 2,297 – 2,814
Primary Recovery 161 - 253
Primary + Waterflood 532 - 718
Primary + Waterflood + WAG 592 - 868
The NOP will employ a horizontal well line drive pattern with a Water Alternating Gas (“WAG”) or rich gas flood,
to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells
(including the injectors) are planned to be hydraulically fracture stimulated to enhance productivity and improve
vertical injection sweep.
Most wells will trend northwest along the maximum principal stress direction of 330 degrees to improve
waterflood performance, and range in length from 3,000 to 8000 ft within the reservoir. Wells will be arranged
end-to-end to form alternating rows of producers and injectors in a line-drive flood pattern. Initial studies
suggest 1800 foot inter-well spacing is optimal. Initial well performance at NDB may, in combination with
additional geologic and engineering studies, change the number of wells, well spacing, and well placement for
future NOP development.
Primary uncertainties in the development of the NOP are the lateral continuity of thin sand beds, fracture
heights within the reservoir section, and the effective displaceable pore volumes. However, extended
production test results of the Pikka B, Q8 and Q301 are consistent with lateral continuous productive sands
over development well spacing distances of 2000 feet. As a fluvial system, compartmentalization is possible,
but hydraulic fracture stimulation will aid in contacting individual sandstone beds.
Recovery Mechanisms
The crude oil viscosity and initial pressure requires adoption of a secondary recovery mechanism to obtain an
economic production profile. WAG injection will be implemented as the main improved recovery process as it
has been widely used on the North Slope with consistent success.
Santos estimates that primary recovery will recover under 7% of the OOIP and that waterflood recovery will
range from 16% incremental recovery OOIP, yielding a total recovery after waterflood of 23% (Table 2:
Estimated Nanushuk oil in place with recoverable volumes associated with different recovery mechanisms.).
Gas injection, whether miscible or immiscible, is expected to yield significant incremental recovery in the NOP
between 3% and 6%. Resource recovery for floods is heavily dependent on injection throughput, waterflood
recovery efficiency, and gas injection recovery efficiency.
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
11
Producing Gas-Oil Ratio expectations
Santos requests that the requirements described in 20 AAC 25.240 be waived for the proposed NOP since the
Pool plans are to implement enhanced recovery techniques. Since gas will be injected into the NOP during the
life of the Pool, the Gas-Oil-Ratio (GOR) is expected to rise above solution GOR in some wells. The
breakthrough of re-injected gas will cause GOR of some producing wells to exceed limits set forth in 20
AAC.25.240. The production wells will be gas-lifted with flowing bottom hole pressures below bubble-point.
However, the NOP average reservoir pressure will be maintained above the bubble-point pressure with WAG
injection for pressure maintenance.
Well Conversion Strategy
The NOP development will target a 1 to 1 voidage replacement ratio to maintain reservoir pressure above the
bubble point. The injection rates will be dictated by the voidage replacement performance. Dependant on initial
well performance and facility constraints, pre-production of injection wells may occur. After the pre-production
period, these wells will be converted to injection as necessary to manage reservoir pressure and producing
GOR.
Drilling and Completion
Drilling Strategy
The NOP will be accessed from wells drilled from gravel pads (Figure 3) utilizing drilling procedures, casing,
and cementing programs consistent with current practices in other North Slope fields.
For proper anchorage and to divert an uncontrolled flow, conductor casing will either be driven or drilled and
cemented at least 70 ft below the pad. Cement returns to surface will be verified by visual inspection.
Surface holes will be drilled and set above the Tuluvak formation for proper anchorage, prevention of
uncontrolled flow, and protection from permafrost thaw and freeze back. Within the planned development area,
the base of permafrost is interpreted to be between -750ft and -1400ft TVDSS. Surface casing strings will be
cemented in accordance with 20 AAC 25.030(d)(4). 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). Intermediate sections will be drilled utilizing the latest
directional techniques from surface casing, reaching tangent sail angles of 40-85 degrees inclination, which
then encounter the top of the Nanushuk reservoir. Casing will be set and cemented with the shoe just above, or
just into, the Nanushuk Reservoir and a minimum cement of 500 feet measured depth or 250 feet true vertical
depth (whichever is greater) above the shallowest hydrocarbon bearing formation in any over-laying formations
in the intermediate section. The intermediate cement jobs will be achieved with either a single or two stage
cement job based on well complexity and directional profiles.
In the area of the Pikka Development, the Tuluvak formation is gas bearing, and setting surface casing above
the Tuluvak allows blowout prevention equipment (“BOPE”) to be installed prior to penetrating. The planned
surface casing depth provides the required kick tolerance to drill the intermediate section. The section between
the proposed surface casing shoe and the top of the Nanushuk Reservoir consists primarily of mudstones and
siltstones with minor thin-bedded sandstone within the Tuluvak formation. There were gas shows in offset wells
Qugruk 3 and Qugruk 8 which were drilled with 10.4 ppg mud weight. Santos has thoroughly reviewed the
Tuluvak formation in this area and have concluded that while there is gas present, it is not significant enough to
warrant commercial development. The Tuluvak formation will be isolated with full cement across the zone if
significant hydrocarbons are deemed present. As an added mitigation to eliminate the potential for gas
migration to surface via the intermediate casing annulus, an isolation packer is proposed in the surface x
intermediate casing annulus above the Tuluvak formation. Additionally, with the isolation packer in place, this
NOP Rules Application Pikka Unit, North Slope of Alaska March 6, 2023
12
eliminates the need to inject freeze protect fluids into the intermediate casing annulus, thus ensuring surface
casing shoe cement integrity is maintained.
Depending on well length and inclination, one or more intermediate strings may be deployed between the
surface casing shoe and the top of the Nanushuk Reservoir, as determined by the required engineering design.
After drilling out the production casing, and prior to drilling ahead into the reservoir, a FIT will be performed in
accordance with 20 AAC 25.030(f).
Figure 3: The proposed well fan layout for the initial Nanushuk Oil Pool development. Depth structure map is of the
Nanushuk 3.2 Reservoir top.
Completion Strategy
Based on current knowledge of reservoir characteristics, Santos expects to develop the Nanushuk Oil Pool
using horizontal wells with solid liners including fracture sleeves and open hole packers to isolate successive
fracture stages. Both injection and production wells will be completed with 4-1/2” liner and tubing (upper and
lower completion) to facilitate hydraulic stimulation and future well work. The upper completion will consist of
landing nipples, a downhole pressure/temperature gauge, and gas lift mandrels. The general proposed
schematics for both a 3 string and 4 string design are shown in Figure 4 through 7.
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Figure 4: Proposed 3 String Casing Design with single stage cement job
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Figure 5: Proposed 3 String Casing Design with two stage cement job
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Figure 6: Proposed 4 String Casing Design with single stage cement job
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Figure 7: Proposed 4 String Casing Design with two stage cement job
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Drilling Fluids
The drilling fluid designed for wells within the NOP 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 Nanushuk Reservoir as well as on the existing appraisal wells which have
already penetrated with Nanushuk Oil pool.
Blowout Prevention
General well control for drilling and completion operations will be performed in accordance with 20 AAC.25.035.
Directional Drilling
Santos requests that the requirements described in 20 AAC 25.050(b) be waived for the proposed NOP to
relieve administrative burden. In lieu of the requirements under 20 AAC 25.050(b), Santos proposes that
permits(s) to drill shall include:
1. Plan view
2. Vertical section
3. Close approach data
4. Directional data
Well Spacing
Initial producer to injector spacing will be approximately 1800’ but may be adjusted based on long-term
production results of the initial drill wells. Consistent with the requirements under 20 AAC 25.055, development
wells will not be completed any closer than 500 feet to an external boundary (where working interest ownership
changes) without prior approval.
Logging Operations
Since facies interpretation will be the most critical data requirement, the log suite planned in the Nanushuk
Reservoir includes resistivity and gamma ray logs across the productive intervals. If log identification of
formation facies is not possible, rate of penetration (“ROP”) and cuttings will become the critical reservoir quality
determinants. At some point in the future, it is possible that Nanushuk wells could be drilled solely using ROP
as well as other drilling indicators to locate the pay zones.
Santos requests that the requirements described in 20 AAC 25.071(a) be waived for the proposed NOP since
these requirements will not significantly add to the geologic knowledge of the area considering the information
that is available from other wells in that area. In lieu of the requirements under 20 AAC 25.071(a), Santos
proposes that only one well per drill site is required to be logged for the portion of the well below the conductor
pipe by an MWD log suite.
As the first Nanushuk Reservoir targeted appraisal wells were drilled and successfully investigated with a suite
of gamma ray/resistivity/neutron/density logs, additional log investigation of the NOP will be performed at
Santos’s discretion.
Well operations
Well design and completions
Typical completions, for both injection and production wells, will be completed with 4-1/2” tubing to facilitate
hydraulic fracturing stimulation and to exploit the production potential of horizontal wells.
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Producing wells will be equipped with gas lift mandrels. Wells with liners placed in the horizontal sections will
utilize a combination liner hanger/packer assembly equipped with a polished bore receptacle capable of
accepting a tubing tail fitted with seals offering annular isolation.
All completions will target reserves in the NOP. Wellbore departure will reach laterally as far as 31,000’ from the
current drill site locations. Dependant on the location of any additional drill sites and technologies available,
high departure and extended horizontal completions may push measured depths even further.
Artificial Lift
The current development plan utilizes gas lift as the artificial lift mechanism to produce from the NOP as it is
best suited for the planned water-alternating-gas flood.
Side-tracks
In the event early waterflood breakthrough is encountered due to thief intervals, the initial completions may be
plugged back and side-tracked to improve enhanced recovery techniques. As such, side-tracks 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 NOP, as required by 20 AAC 25.270(a), was measured in the appraisal
wells. Santos requests that the AOGCC approves the proposed reservoir pressure monitoring plan:
1. Static bottom-hole pressure surveys will be conducted in all new wells upon initial completion.
2. For annual pressure surveillance, a minimum of (1) pressure survey per drill site will be
conducted annually in the Nanushuk Oil Pool, concentrating on injection wells.
3. 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:
a. Producer pressure build-ups with bottom-hole pressure measurement
b. Injector pressure fall-off with bottom-hole or surface pressure measurement
4. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to
the limited number of surveys.
While the pool extends between approximately -4100ft TVDSS and -4300FT TVDSS, a representative common
datum for reporting should be -4100ft TVDSS. The -4100FT TVDSS datum will be representative of the
targeted depth since the average top of the Nanushuk formation is between -4150 and -3900ft TVDSS.
Sustained Casing Pressure Rules
Santos proposes to operate NOP wells in compliance with previous Commission orders addressing sustained
casing pressures for active wells.
Well Work Operations
Unlike more typical multi-zone or multi-layer fields on the North Slope, the NOP represents a single
hydrocarbon accumulation. Production from a single pool minimizes profile modifications and well work will
focus on maintenance within an existing wellbore (paraffin/scale removal) that does not require a sundry.
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Surface Safety Valves
Wells abide by regulations set forth in accordance with 20 AAC 25.265 for surface safety valves. Subsurface
safety valves will not be required for planned wells which have a surface location beyond 660’ beyond
boundaries described in 20 AAC 25.265(d).
Facilities
Introduction and Scope
The NOP will be initially developed from the NDB drill site. The initial production from wells at NDB will be
transported via a pipeline to the NPF for processing and sales oil delivery to the Kuparuk Pipeline owned and
operated by the Kuparuk Transportation Company (KTC). The NDB onshore gravel drill site was selected for
the initial development due to the availability to target the NOP from that surface location and due to the ability
to use infrastructure already established to process and transport oil to Pump Station #1 (PS1)
Initial injection water will we be seawater from a new Seawater Treatment Plant (STP) located near the Kuparuk
River Unit STP. Seawater, produced water, and / or a combination of the two will be used throughout initial and
full development phases of the reservoir. For full field development injection of solution gas less fuel and flare
volumes will occur in one or more injection patterns. Fuel gas may be imported from outside the NOP to
preserve indigenous gas for injection.
Drill Site Facilities
The initial production single drill site and the full field development drill sites are unmanned and require minimal
operator presence for daily operations. All data gathering and routing operations are accomplished remotely
from the main field control room. The list below includes the facility components located at the NDB drill site:
1. Production, gas-lift, water injection, and gas injection lateral piping and headers
2. Multi-phase metering for well testing and allocation
3. Production heating and chemical injection equipment
4. Instrumentation, control, and communication equipment
The drill sites are designed to accommodate 40-50 wells on 20-foot centers to be used for producers, injectors,
and disposal wells. Initially a total of 44 wells are planned for the NDB drill site. The individual well lines
commingle into common headers that feed into cross-country pipelines for transport to NPF. Each production
well connects to the drill site test header which flows through the test module on the pad. Within the test module
is a multi-phase meter for monthly well testing and production allocation. Testing is executed remotely through
a divert valve system, which redirects the flow from the production header to the test header.
Nanushuk Processing Facility
The NPF takes the well production from Pikka drill sites and separates fluids into wet oil, gas, and water
streams. Gas is dehydrated and compressed for artificial lift, gas injection, and fuel gas to support the facility.
Seawater and / or produced water pressure is boosted and used for injection.
The separation train consists of three separators to remove gas and water from the oil, which is metered and
delivered to the KPL.
Gas separated from oil in the separation train is processed and compressed primarily for artificial lift and re-
injection. The first stage compressor boosts the gas in the plant up to approximately 500 psig for fuel gas
usage. The second stage boosts the gas to ~1500psig where it is used for gas lift. The third stage boosts any
gas not used for fuel or lost to flare to ~3000 psig to be used for gas injection. Produced water will be separated
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from the oil stream and will either be disposed or reinjected into the reservoir for pressure maintenance and
waterflood support. Seawater injection pumps are used for injecting seawater into the reservoir for pressure
maintenance and waterflood.
The NPF contains the utility systems required to operate a North Slope oil field. Electricity is generated using
gas turbines. 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 and 25.230. Production will be
allocated to producing wells based on metered oil sales, gas and produced water volume, and well tests on
individual producing wells.
To satisfy the requirements under 20 AAC 25.030(a), Santos proposes using a Schlumberger Vx multi-
phasemeter for well testing, which is compliant with API MPMS 20.3 by having less than +/-5% total uncertainty
for the range of flow conditions expected. Since the most rapid change in well performance is expected during
the first year, each producing well will be tested at least twice monthly for the first 12 months, and then at least
monthly thereafter. The Nanushuk project area is also subject to the Pikka Unit Agreement. Royalty interests
will be determined at intervals described in the Agreement.
The control system for the NOP wells will continuously gather operating data from the wells and test meters.
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Proposed NOP Rules
The rules set forth apply to the following area referred to in this order:
Pikka Unit Boundary as defined by November 29, 2016 DNR approval.
Rule 1: Field and Pool Name
The field is the Pikka Field, and the pool is the Nanushuk Oil Pool
Rule 2: Pool Definitions
The Nanushuk Oil Pool is defined as the accumulation of oil and gas common to and correlating to the
stratigraphic interval between 3,892 and 5,166 feet measured depth in the Qugruk-3 well and its lateral
equivalents.
Rule 3: Well Spacing
There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of
an external property line where the owners and landowners are not the same on both sides of the line.
Rule 4: Casing and Cementing Practices
a. After drilling no more than 50 feet below a casing shoe set in the Nanushuk Oil Pool, a formation
integrity test must be conducted. The test must indicate sufficient pressure exists before drilling
operations can be continued.
b. Casing and completion designs may be approved by the Commission upon application and
presentation of data that demonstrate the designs are appropriate and based on sound engineering
principles.
c. Production casing cement volumes will be sufficient to place cement a minimum of 500 feet measured
and 250 feet vertical depth, whichever is greater, above the top of the Nanushuk Oil Pool in all
wellbores.
d. Permit(s)to drill deviated wells shall include a plat with a plan view, vertical section, close approach
data and a directional program description in lieu of the requirements of 20 AAC 25.050(b)
e. In lieu of the requirements of 20 AAC25.071(a), petrophysical logs obtained from nearby exploration
wells or wells drilled to other oil pools from the drilling pad may be submitted to meet these
requirements.
Rule 5: Well Safety Valve Systems
Surface safety valves will be installed in all vertical trees. All wells drilled within the NOP will abide by the
regulations set forth in 20 AAC 25.565 with the following modification to 20 AAC 25.565(d)(5) for all injection
wells (except disposal).
Safety valve systems must be maintained in good working order at all times and must be tested at six-month
intervals or on a schedule prescribed by the Commission. Sufficient notice must be given so that a
representative of the Commission can witness tests, if desired.
Nipple profiles will be installed to allow for subsurface injection check valves if deemed necessary.
Rule 6: Injection Well Completion
(a.) Packers in injection wells may be located more than 200 feet measured depth above the top of the injection
zone; however, packers must not be located above the confining zone. In cases where the distance is more
than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300
feet measured depth above the planned packer depth.
(b.) An approved injection order is required prior to commencement of injection in this pool.
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Rule 7: Common Production Facilities and Surface Commingling
a. Production from the Nanushuk Oil Pool may be commingled at the surface prior to custody transfer.
b. Allocation factors for produced fluids will be based on well tests, daily well allocation and total
production as measured at the NPF.
c. Each producing well must be tested once per month.
d. The Commission may require more frequent or longer tests if allocation quality deteriorates.
e. The operator shall submit a monthly report and electronic files containing daily allocation data and daily
test data for agency surveillance and evaluation.
f. The operator shall provide the Commission with a well test and allocation review report in conjunction
with an annual reservoir surveillance report.
Rule 8: Reservoir Pressure Monitoring
a. A bottom-hole pressure survey shall be taken on each well prior to initial sustained production or
injection.
b. The Operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery
processes subject to an annual plan outlined in paragraph (e) of this rule.
c. The reservoir datum will be 4,100’ SSTVD for the Nanushuk Oil Pool.
d. Pressure surveys may consist of stabilized static bottomhole pressure measurements, pressure fall-off,
pressure build-up, multi-rate tests and formation tests or other appropriate technical pressure transient
or static tests.
e. Data from the surveys required in this rule shall be filed with the Commission by April 1 of the
subsequent year to the year in which the surveys are conducted. Along with the survey submittal, the
operator will provide a proposed survey plan for the upcoming year. The proposed plan shall be
deemed accepted if the operator has not received written correspondence from the Commission within
45 days.
f. Reservoir pressure report, Form 10-412, shall be utilized for all surveys with attachments for complete
additional data. Data submitted shall include rate, pressure, depth, fluid gradient, temperature, and
other well conditions necessary for complete analysis of each survey being conducted.
g. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in
accordance with paragraph (e) of this rule.
Rule 9: Gas Oil Ratio Exemption
Wells producing from the Nanushuk Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) in
accordance with the provisions of 20 AAC 25.240(b).
Rule 10: Annual Reservoir Review
An annual report must be filed on or before April 1 of each year. The report shall include an overview of
reservoir performance, future development and reservoir depletion plans, and surveillance information for the
prior calendar year. Report details shall include the following:
a. Reservoir pressure maps at datum.
b. Summary and analysis of reservoir pressure surveys.
c. Reservoir pressure estimates.
d. Results and, where appropriate, analysis of production, temperature, tracer surveys, observation well
surveys, and any other special monitoring surveys.
e. Estimates of yearly production and the reservoir voidage balance of injection and withdrawals at
standard and reservoir conditions.
f. Progress of plans and tests to expand the productive limits of the pool.
g. Results of surface safety valve testing.
Rule 11: Well Mechanical Integrity and Annulus Pressures
a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each
development well at the time of installation or replacement 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 development well daily to check for sustained pressure, unless
prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable
circumstances. Monitoring results shall be made available for AOGCC inspection.
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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 2000 psig or (ii) sustained outer annulus
pressure that exceeds 1000 psig.
d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form10-
403), a proposal for corrective action or increased surveillance for any development well having
sustained pressure that exceeds a limit set out in paragraph "c" of this rule. The Commission may
approve the operator's proposal or may require other corrective action or surveillance. The Commission
may require that corrective action be verified by mechanical integrity testing or other Commission
approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing
schedule to allow the Commission to witness the tests.
e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds
45% 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% of the burst pressure rating of the well's surface casing
for outer annulus pressure, the operator shall immediately notify the Commission and take corrective
action. Unless well conditions require the operator to take emergency corrective action before
Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals
(Form10-403) a proposal for corrective action. The Commission may approve the operator's proposal or
may require other corrective action. The Commission may also require that corrective action be verified
by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give
the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests.
f. Except as otherwise approved by the AOGCC under paragraph "d" or "e" of this rule, before a shut-in
well is placed in service, any annulus pressure must be relieved to a sufficient degree that (i) the inner
annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure
at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but
not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is
described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC
prescribes a different limit.
Rule 12: Administrative Action
Unless notice and public hearing are otherwise required, the Commission may administratively waive the
requirements of any rule stated above or administratively amend any rule if the change does not promote waste
or jeopardize correlative rights, is based upon sound engineering and geoscience principles, and will not result
in an increased risk of fluid movement into freshwater.
