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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-092From:Guhl, Meredith D (OGC)
To:Hobbs, Greg S; Taylor, Jenna; Conklin, Amy A
Cc:Loepp, Victoria T (OGC); Brooks, James S (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC)
Subject:Permits Expired: KRU
Date:Monday, April 1, 2024 3:03:00 PM
Hello Greg, Jenna, and Amy,
The following Permits to Drill, issued to ConocoPhillips Alaska, Inc, have expired under Regulation 20
AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database.
KRU 3G-24L1-01, PTD 221-091, Issued 5 November 2021
KRU 3G-24L1-02, PTD 221-092, Issued 5 November 2021
KRU 2T-22L1, PTD 221-113, Issued 20 December 2021
KRU 3G-02L1-01, PTD 222-017, Issued 15 February 2022
If you have any questions, please contact me.
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state
or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so
that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or
meredith.guhl@alaska.gov.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Ty Senden
CTD/RWO Engineering Director
ConocoPhillips Alaska, Inc.
PO Box 100360
Anchorage, AK 99510-0360
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3G-24L1-02
ConocoPhillips Alaska, inc.
Permit to Drill Number: 221-092
Surface Location: 2538' FNL, 270' FEL, SEC 23, T12N, R8E, UM
Bottomhole Location: 4095' FNL, 4175' FEL, SEC 14, T12N, R8E, UM
Dear Mr. Senden:
Enclosed is the approved application for the permit to drill the above referenced well.
The permit is for a new wellbore segment of existing well Permit 190-134, API 50-103-20145-00-
00. Production should continue to be reported as a function of the original API number stated
above.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs
run must be submitted to the AOGCCwithin 90 days after completion, suspension or abandonment
of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of November, 2021.
Jeremy Price
Digitally signed by
Jeremy Price
Date: 2021.11.05
10:43:41 -08'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11.Well Name and Number:
Bond No.
3. Address: 6.Proposed Depth:12. Field/Pool(s):
MD: 13500 TVD:5839'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8.DNR Approval Number: 13. Approximate Spud Date:
Total Depth:9. Acres in Property:14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 90' KB 15. Distance to Nearest Well Open
Surface: x- 498110 y- 5988560 Zone:4 53' GL to Same Pool:1910' (3H-01)
16. Deviated wells: Kickoff depth: 9,840 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 98 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
3" 2-3/8" 4.7# L-80
ST-L 3860' 9634 5850' 13500' 5839'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
NA
TVD
115'
3102'
--
6074'
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Ty Senden Contact Email:
CTD/RWO Engineering Director Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
907-263-4112
11/20/2021
1910 ft (KPA boundary)
115'
4573'
Effect. Depth TVD (ft):
KRU 3G-24L1-02
Kuparuk River Pool /
Kuparuk River Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
--
9931'
Jeff Connelly
Jeff.S.Connelly@ConocoPhillips.com
Total Depth MD (ft): Total Depth TVD (ft):
Casing
NA
5952180
Specifications
4545 psi
Cement Volume MDSize
Plugs (measured):
(including stage data)
Slottted w/ shorty deployment sleeve
9931 6074
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
3960 psi
1325' FNL, 3331' FEL, SEC 14, T12N, R8E, UM
4095' FNL, 4175' FEL, SEC 14, T12N, R8E, UM
LONS 85-098
P.O. Box 100360 Anchorage, AK 99510-0360
ConocoPhillips Alaska, Inc.
2538' FNL, 270' FEL, SEC 23, T12N, R8E, UM ADL 25547 ALK 2661
2560
18. Casing Program:Top - Setting Depth - Bottom
Authorized Title:
Authorized Signature:
--
274 SX Class G & 154 SX Class GProduction
--
9896'
Intermediate
Authorized Name:
10/29/2021
7"
--
9618' - 9658'5839' - 5868'
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
4538'
175 SX AS I
9-5/8" 970 SX AS III & 600 SX Class G
Effect. Depth MD (ft):
Conductor/Structural 16"80'
9940 6081
Length
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Samantha Carlisle at 9:49 am, Nov 02, 2021
Digitally signed by R. Tyler Senden
DN: CN=R. Tyler Senden, O=Intervention and Integrity, OU=AK Wells,
E=r.tyler.senden@conocophillips.com, C=US
Reason: I am the author of this document
Location: your signing location here
Date: 2021.11.01 15:29:15-08'00'
Foxit PDF Editor Version: 11.0.0
R. Tyler Senden
X
X
DLB
X
X
DLB 11/03/2021
A variance to 20 AAC 25.015(b)is granted to allow the kickoff point to be any point along the parent lateral.
221-092
DSR-11/2/21
BOP test pressure to 4500 psig
Annular test pressure to 2500 psig
VTL 11/4/21
X
50-103-20145-62-00
X
X
X
dts 11/4/2021
JLC 11/4/2021
11/5/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.11.05 10:44:21 -08'00'
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
If you have any questions or require additional information, please contact me at 907-263-4597.
Sincerely,
Jeff Connelly
Coiled Tubing Drilling Engineer
ConocoPhillips Alaska
October 29, 2021
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill three laterals out of the KRU 3G-24
(PTD# 190-134) using the coiled tubing drilling rig, Nabors CDR3-AC.
CTD operations are scheduled to begin in November 2021. The objective will be to drill three laterals, KRU 3G-
24L1, 3G-24L1-01 and 3G-24L1-02, targeting the Kuparuk A-sand interval.
A RWO is currently underway on 3G-24 (as of 10-29-21) to install Tandem Wedges to facilitate CTD operations.
To account for geological uncertainties,ConocoPhillips requests a variance from the requirements of 20
AAC 25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of
being limited to 500’ from the original point.
Attached to permit to drill applications are the following documents:
Permit to Drill Application Forms (10-401) for 3G-24L1-02
Detailed Summary of Operations
Directional Plans for 3G-24L1-02
Current Wellbore Schematic
Proposed CTD Schematic
1/4-Mile Injection Review
Digitally signed by Jeff Connelly
DN: C=US, OU=CTD, O=ConocoPhillips,
CN=Jeff Connelly,
E=jeff.s.connelly@conocophillips.com
Reason: I am the author of this document
Location: your signing location here
Date: 2021.11.01 10:09:00-08'00'
Foxit PDF Editor Version: 11.0.0
Jeff
Connelly
Kuparuk CTD Laterals
3G-24L1, 3G-24L1-01 & 3G-24L1-02
Application for Permit to Drill Document
Page 1 of 6 September 15, 2021
1. Well Name and Classification......................................................................................................... 2
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) .................................................................................................................. 2
2. Location Summary .......................................................................................................................... 2
(Requirements of 20 AAC 25.005(c)(2)) ................................................................................................................................................. 2
3. Blowout Prevention Equipment Information ................................................................................. 2
(Requirements of 20 AAC 25.005 (c)(3)) ................................................................................................................................................ 2
4. Drilling Hazards Information and Reservoir Pressure .................................................................. 2
(Requirements of 20 AAC 25.005 (c)(4)) ................................................................................................................................................ 2
5. Procedure for Conducting Formation Integrity tests .................................................................... 2
(Requirements of 20 AAC 25.005(c)(5)) ................................................................................................................................................. 2
6. Casing and Cementing Program .................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(6)) ................................................................................................................................................. 3
7. Diverter System Information .......................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(7)) ................................................................................................................................................. 3
8. Drilling Fluids Program................................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(8)) ................................................................................................................................................. 3
9. Abnormally Pressured Formation Information ............................................................................. 4
(Requirements of 20 AAC 25.005(c)(9)) ................................................................................................................................................. 4
10. Seismic Analysis ............................................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(10)) ............................................................................................................................................... 4
11. Seabed Condition Analysis ............................................................................................................ 4
(Requirements of 20 AAC 25.005(c)(11)) ............................................................................................................................................... 4
12. Evidence of Bonding ...................................................................................................................... 4
(Requirements of 20 AAC 25.005(c)(12)) ............................................................................................................................................... 4
13. Proposed Drilling Program ............................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(13)) ............................................................................................................................................... 4
Summary of Operations................................................................................................................................................... 4
Liner Running .................................................................................................................................................................. 6
14. Disposal of Drilling Mud and Cuttings ........................................................................................... 6
(Requirements of 20 AAC 25.005(c)(14)) ............................................................................................................................................... 6
15. Directional Plans for Intentionally Deviated Wells ........................................................................ 6
(Requirements of 20 AAC 25.050(b)) ..................................................................................................................................................... 6
16. Attachments .................................................................................................................................... 6
Attachment 1: Quarter Mile Injection review for 3G-24 ................................................................................................... 6
Attachment 2: Directional Plans for 3G-24L1, 3G-24L1-01 & 3G-24L1-02 laterals ........................................................ 6
Attachment 3: Current Well Schematic for 3G-24 ........................................................................................................... 6
Attachment 4: Proposed Well Schematic for 3G-24L1, 3G-24L1-01 & 3G-24L1-02 laterals .......................................... 6
PTD Application: 3G-24L1, 3G-24L1-01 & 3G-24L1-02
Page 2 of 6 September 15, 2021
1. Well Name and Classification
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))
The proposed laterals described in this document are 3G-24L1, 3G-24L1-01 & 3G-24L1-02. All laterals will be
classified as “Service” wells.
2. Location Summary
(Requirements of 20 AAC 25.005(c)(2))
These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 form for surface
and subsurface coordinates of the 3G-24L1, 3G-24L1-01 & 3G-24L1-02.
3. Blowout Prevention Equipment Information
(Requirements of 20 AAC 25.005 (c)(3))
Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC.
BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations.
Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4,500 psi. Using the
maximum formation pressure in the area of 4548 psi in 3G-15 (i.e. 14.94 ppg EMW), the maximum
potential surface pressure in 3G-24, assuming a gas gradient of 0.1 psi/ft, would be 3960 psi. See the
“Drilling Hazards Information and Reservoir Pressure” section for more details.
The annular preventer will be tested to 250 psi and 2,500 psi.
4. Drilling Hazards Information and Reservoir Pressure
(Requirements of 20 AAC 25.005 (c)(4))
Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a))
The formation pressure in KRU 3G-24 was measured to be 3484 psi at 5854 TVD (11.45 ppg EMW) on
8/9/2021. The maximum downhole pressure in the 3G-24 vicinity is to the southwest in the 3G-15. Pressure
was measured to be 4548 psi at the 5855 TVD, (14.94 ppg EMW) on 3/12/2019.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
There is a possibility of encountering free gas while drilling the 3G-24 laterals due to previous gas injection in
the area. If gas is detected in the returns, the contaminated mud can be diverted to a storage tank away from
the rig.
Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c))
The major expected risk of hole problems in the 3G-24 laterals will be shale instability across faults. Managed
pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings.
5. Procedure for Conducting Formation Integrity tests
(Requirements of 20 AAC 25.005(c)(5))
The 3G-24 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity
test is not required.
PTD Application: 3G-24L1, 3G-24L1-01 & 3G-24L1-02
Page 3 of 6 September 15, 2021
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral Name Liner Top
MD
Liner Btm
MD
Liner Top
TVDSS
Liner Btm
TVDSS Liner Details
3G-24L1 12,100’13,700’5852’5879’2-3/8", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3G-24L1-01 9840’13,700’5796’5870 2-3/8", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3G-24L1-02 9634’13,500’5754’5749’2-3/8", 4.7#, L-80, ST-L slotted liner
with shorty deployment sleeve on top
Existing Casing/Liner Information
Category OD Weight
(ppf) Grade Connection Top MD Btm MD Top
TVD
Btm
TVD
Burst
psi
Collapse
psi
Conductor 16”62.5 H-40 Welded 35’115’35’115’1640 670
Surface 9-5/8”36.0 J-55 BTC 35’4573’35’3102’3520 2020
Production 7”26.0 J-55 AB-MOD 35’9931’35’6074’4980 4330
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR3-AC mud system is on file with the Commission.
Description of Drilling Fluid System
Window milling operations: Water-Based PowerVis milling fluid (8.6 ppg)
Drilling operations: Water-based PowerVis mud (8.6 ppg). This mud weight will not hydrostatically
overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices
described below.
Completion operations: The well will be loaded with ~11.8 ppg NaBr completion fluid in order to
provide formation over-balance and well bore stability while running completions.
Managed Pressure Drilling Practice
Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on
the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud
weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 psi rated coiled
tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3
“Blowout Prevention Equipment Information”.
In the 3G-24 laterals we will target a constant BHP of ~11.8 ppg EMW at the window. The constant BHP target
will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if
increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be
employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates
or change in depth of circulation will be offset with back pressure adjustments.
Managed Pressure Drilling Practice
Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure ongp g( ) q pyp
the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process.
In the 3G-24 laterals we will target a constant BHP of ~11.8 ppg EMW at the window. f
DLB
DLB
PTD Application: 3G-24L1, 3G-24L1-01 & 3G-24L1-02
Page 4 of 6 September 15, 2021
Pressure at the 3G-24 Window (9634’’ MD, 5850’ TVD) Using MPD
Pumps On (1.9 bpm) Pumps Off
A-sand Formation Pressure (11.45 ppg) 3484 psi 3484 psi
Mud Hydrostatic (8.6 ppg) 2616 psi 2616 psi
Annular friction (i.e. ECD, 0.080 psi/ft) 771 psi 0 psi
Mud + ECD Combined
(no choke pressure)
3387 psi
(underbalanced ~97 psi)
2616 psi
(Underbalanced ~868 psi)
Target BHP at Window (11.8 ppg) 3590 psi 3590 psi
Choke Pressure Required to Maintain
Target BHP 203 psi 974 psi
9. Abnormally Pressured Formation Information
(Requirements of 20 AAC 25.005(c)(9))
N/A - Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
(Requirements of 20 AAC 25.005(c)(10))
N/A - Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
(Requirements of 20 AAC 25.005(c)(11))
N/A - Application is for a land based well.
12. Evidence of Bonding
(Requirements of 20 AAC 25.005(c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
13. Proposed Drilling Program
(Requirements of 20 AAC 25.005(c)(13))
Summary of Operations
KRU well 3G-24 is a Kuparuk A-Sand producer equipped with 3-1/2” tubing and 7” production casing. 3G-24 is
currently being worked-over (10/29/21) to install a Tandem Wedge for facilitate CTD operations. The CTD
sidetrack will utilize three laterals to target the A-sands to the north and south of 3G-24. The 3G-24 CTD laterals
will provide injection support to the 3H-01 & 3G-25X wells, increasing A-sand resource recovery and throughput.
Note: a ¼-Mile Injection Review is included as an attachment to this documentation.
Prior to CTD rig up, E-Line will set a mechanical whipstock (inner-wedge) inside the 3-1/2” tubing at the planned
kick off point of 9634’ MD. The 3G-24L1 lateral will exit through the 3-1/2” tubing and 7” casing at 9634’’ MD and
drill to a planned TD at 13,700’ MD, targeting the A sand to the north. The lateral will be completed with 2-3/8”
slotted liner from TD up to 12,100’ MD with an aluminum billet for kicking off.
The 3G-24L1-01 lateral will kick off at 12,100’ MD and drill to a planned TD of 13,700’ MD targeting the A sand to
the north. It will be completed with 2-3/8” slotted liner from TD up to 9840’ MD with an aluminum billet for kicking
off.
The 3G-24L1-02 lateral will kick off at 9840’ MD and drill to a planned TD of 13,500’ MD targeting the A sand to
the south. It will be completed with 2-3/8” slotted liner from TD up to top-of-whipstock.
Note: DLB
PTD Application: 3G-24L1, 3G-24L1-01 & 3G-24L1-02
Page 5 of 6 September 15, 2021
CTD Drill and Complete 3G-24 Laterals:
Pre-CTD Work (post current RWO installing Tandem Wedge)
1.Slickline: Brush and flush nipple profiles, dummy whipstock drift, set lock mandrel & check-set for
inner wedge.
2.E-Line: Log GR & CCL, set inner wedge
3.Prep site for Nabors CDR3-AC.
Rig Work
1.MIRU Nabors CDR3-AC rig using 2” coil tubing. NU 7-1/16” BOPE, test.
2.3G-24L1 Lateral (A sand - North)
a.Mill 2.80” window at 9634’ MD.
b.Drill 3” bi-center lateral to TD of 13,700’ MD.
c.Run 2-3/8” slotted liner with an aluminum billet from TD up to 12,100’ MD.
3.3G-24L1-01 Lateral (A sand - North)
a.Kick off of the aluminum billet at 12,100’ MD.
b.Drill 3” bi-center lateral to TD of 13,700’ MD.
c.Run 2-3/8” slotted liner with an aluminum billet from TD up to 9840’ MD.
4.3G-24L1-02 Lateral (A sand - South)
a. Kick off of the aluminum billet at 9840’ MD.
b.Drill 3” bi-center lateral to TD of 13,500’ MD.
c. Run 2-3/8” slotted liner with deployment sleeve from TD up to 9634’ MD
5.Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CRD3-AC.
Post-Rig Work
1.Return to production
Pressure Deployment of BHA
The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on
the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double
swab valves on the Christmas tree, deployment rams (the annular preventer will serve as a secondary barrier
during BHA pressure deployment), double check valves and double ball valves in the BHA, and a slick-line
lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir
pressure, both internal and external to the BHA, during the deployment process.
During BHA deployment, the following steps are observed.
Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is
installed on the BOP riser with the BHA inside the lubricator.
Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and
the BHA is lowered in place via slick-line.
When the BHA is spaced out properly, the deployment rams are closed on the BHA to isolate reservoir
pressure via the annulus (the annular preventer will serve as a secondary barrier during BHA pressure
deployment). A closed set of double ball valves and double check valves isolate reservoir pressure
internal to the BHA. Slips on the deployment rams prevent the BHA from moving when differential
pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams.
The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the
closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the
double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized,
and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole.
PTD Application: 3G-24L1, 3G-24L1-01 & 3G-24L1-02
Page 6 of 6 September 15, 2021
During BHA undeployment, the steps listed above are observed, only in reverse.
Liner Running
The lateral will be displaced to an overbalancing fluid prior to running liner. See “Drilling Fluids” section
for more details.
While running 2-3/8” slotted liner, a joint of 2-3/8” non-slotted tubing will be standing by for
emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew
conducts a deployment drill with this emergency joint on every slotted liner run. The 2-3/8” rams will
provide secondary well control while running 2-3/8” liner.
14. Disposal of Drilling Mud and Cuttings
(Requirements of 20 AAC 25.005(c)(14))
x No annular injection on this well.
x All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
x Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1R-18
or 1B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
x All wastes and waste fluids hauled from the pad must be properly documented and manifested.
x Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
The Applicant is the only affected owner.
Please see Attachment 1: Directional Plans
Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
MWD directional, resistivity, and gamma ray will be run over the entire open hole section.
Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name Distance
3G-24L1 1900’
3G-24L1-01 2825’
3G-24L1-02 1095’
Distance to Nearest Well within Pool
Lateral Name Distance Well
3G-24L1 935’ 3H-05
3G-24L1-01 855’ 3H-05
3G-24L1-02 1910’ 3H-01
16. Attachments
Attachment 1: Quarter Mile Injection review for 3G-24
Attachment 2: Directional Plans for 3G-24L1, 3G-24L1-01 & 3G-24L1-02 laterals
Attachment 3: Current Well Schematic for 3G-24
Attachment 4: Proposed Well Schematic for 3G-24L1, 3G-24L1-01 & 3G-24L1-02 laterals
3G-24L, 3G-24L1-01, & 3G-24L1-02 Quarter Mile Injection ReviewWell NameStatusCasing SizeTop of C-Sand oil pool (MD)Top of C-Sand Oil Pool (TVDSS)Top of A-Sand oil pool (MD)Top of A-Sand Oil Pool (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir StatusZonal IsolationCement Operations SummaryMechanical Integrity3H-05 P&A 7" 6764 5796' 6836' 5855'Plug 1 = 3147'Plug 2 = 1032'Plug 3 = 52'Plug 1 = 2791'Plug 2 = 954'Plug 3 = 24'Log (original) Well is P&A'd with no communication with reservoirMotherbore perforations cement squeezed, and well P&A'd. Plugs 1, 2, & 3 pumped in 7" production casing. TOC's at 52', 1032', & 3147' RKBOrigninal 7" CMNT ('87): 500 sx Class GPlug 3: 41 bbl pumped, 15.7#, returns to surfacePlug 2: 70 bbl cement pumped to IA & tubingPlug 1: 158 bbl, 15.8 ppg cmnt P&A final site clearance received 5/16/19 from AOGCC Matt Herrara. Total of 13'-2" of wellhead removed , marker plate welded and buried >4 below original tundra.3G-24 1/4-Mile Review
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52005400560058006000True Vertical Depth (400 usft/in)1600
1800
2000
2200
2400
2600
2800
3000
3200
3400
3600
3800
4000
4200
4400
4600480050005200
Vertical Section at 25.00° (400 usft/in)3G-24L1-02 T2.13G-24L1-02 T2.43G-24L1-02 T2.3 Flt 63G-24L1-02 T2.53G-24L1-02 T2.7 Flt 73G-24L1-02 T2.63G-24L1-02 T2.9 Flt 83G-24L1-02 T2.8TD3G -24L1_wp023G-243G-2 4L1-02_wp02 Top of BilletTDSECTION DETAILSSecMD Inc Azi TVDss+N/-S+E/-W Dleg TFaceVSect1 9840.00 98.95 8.28 5796.05 6677.20 -3112.25 0.00 0.00 4736.302 9910.00 95.35 37.70 5787.15 6740.38 -3085.37 42.00 95.00 4804.923 10175.00 91.77 149.29 5762.39 6726.10 -2861.93 42.00 86.00 4886.414 10475.00 89.86 170.20 5758.07 6446.25 -2758.67 7.00 95.00 4676.425 10675.00 90.83 184.17 5756.86 6246.99 -2748.87 7.00 86.00 4499.986 10850.00 96.91 194.84 5745.02 6075.11 -2777.58 7.00 60.00 4332.067 11000.00 90.11 202.86 5735.82 5933.63 -2825.91 7.00 130.00 4183.418 11150.00 87.06 192.81 5739.54 5791.08 -2871.79 7.00-107.00 4034.849 11450.00 90.81 213.48 5745.17 5516.83 -2989.05 7.00 80.00 3736.7210 11750.00 90.04 192.49 5742.90 5242.20 -3105.54 7.00 -92.00 3438.5911 11900.00 93.62 202.37 5738.09 5099.36 -3150.38 7.00 70.00 3290.1812 12100.00 89.93 215.89 5731.88 4925.18 -3247.46 7.00 105.00 3091.3013 12275.00 89.29 228.12 5733.08 4795.39 -3364.34 7.00 93.00 2924.2714 12675.00 89.37 200.12 5737.83 4467.55 -3586.46 7.00 -90.00 2533.2715 12950.00 89.41 219.37 5740.77 4229.91 -3722.25 7.00 90.00 2260.5116 13500.00 88.92 180.87 5749.13 3723.20 -3907.87 7.00 -91.00 1722.82WELL DETAILS: 3G-24+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 5988311.60 1638141.82 70° 22' 46.848 N 150° 1' 6.587 WProject: Kuparuk River Unit_2Site: Kuparuk 3G PadWell: 3G-24Wellbore: 3G-24L1-02Plan: 3G-24L1-02_wp02WELLBORE DETAILS: 3G-24L1-02Parent Wellbore: 3G-24L1Tie on MD: 9840.00Azimuths to True NorthMagnetic North: 15.34°Magnetic FieldStrength: 57296.1nTDip Angle: 80.72°Date: 12/1/2021Model: BGGM2021TM35004000450050005500600065007000South(-)/North(+) (1000 usft/in)-5500
-5000
-4500
-4000
-3500
-3000-2500-2000-1500
West(-)/East(+) (1000 usft/in)3G-24L1-02 T2.83G-24L1-02 T2.9 Flt 83G-24L1-02 T2.63G-24L1-02 Polygon3G-24L1-02 T2.7 Flt 73G-24L1-02 T2.53G-24L1-02 T2.3 Flt 63G-24L1-02 T2.43G-24L1-02 T2.13G-24L1_wp023G-243G-24L1-02_wp02Top of BilletTDREFERENCE INFORMATIONCoordinate(N/E) Reference: Well 3G-24, True NorthVertical (TVD) Reference: Mean Sea LevelSection (VS) Reference: Slot - (0.00N, 0.00E)Measured Depth Reference: 3G-24 @ 90.00usft (Doyon 14)Calculation Method: Minimum Curvature3G-24L1-02_wp023G-24L1-02_wp02
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Project: Kuparuk River Unit_2Site: Kuparuk 3G PadWell: 3G-24Wellbore: 3G-24L1Plan:3G-24L1 3G-24L1-01 3G-24L1-02WELLBORE DETAILS: 3G-24L1Parent Wellbore: 3G-24Tie on MD: 9600.00Azimuths to True NorthMagnetic North: 15.34°Magnetic FieldStrength: 57296.1nTDip Angle: 80.72°Date: 12/1/2021Model: BGGM2021TM30003750450052506000675075008250900097501050011250South(-)/North(+) (1500 usft/in)-8250
-7500
-6750
-6000
-5250
-4500
-3750
-3000
-2250
-1500
-750
0
750
1500
2250
300037504500
West(-)/East(+) (1500 usft/in)30003750450052506000675075008250900097501050011250South(-)/North(+) (1500 usft/in)
-8250
-7500
-6750
-6000
-5250
-4500
-3750
-3000
-2250
-1500
-750
0
750
1500
2250
300037504500
West(-)/East(+) (1500 usft/in)3G-24L1 Polygon3G-24L1-02 Polygon4000500059913G-24587958703G-24L1-01_wp015000600062 9 73G -07500060006 5 7 23G-07 A
5000600060283G-10500059953G-174000500059913G-2457493G-24L1-02_wp02500059493G-25X400050003G -2610002000300040005000600061493H-0159113H-01A58993H-01AL158943H-01AL1PB110002000300040005000600061403H-0210002000300040005000600061693H-0310002000300040005000600062893H-04010002000300040005000600061143H-051000200030 0 0
400050 0 0
6 00 0
6 1 8 73H-061 000
2 00 0
30 00
4 00 0
5000600061313H-070100020003H-0810002000300040005000600063113H-09200030005 00 0
6000
6 2 693H-10
400060513H-10C60293H-10CL160523H-10CPB102000300040 0 05000600063843H-1 1
30 0 0
1 0 0 02000
5 0 00
6 00 0
6 1 023H-1 6
58903H-16A5 8 93
3 H-1 6A P B 13H-2530 0 0400 05000600062283H-2658213H-26L157623H-26L1-0158923H-26L1-0260163H-33A6 0313 H -33 AL160413H-33AL1PB103H-35058793G-24L1_wp02TIPKOPREFERENCE INFORMATIONCoordinate(N/E) Reference: Well 3G-24, True NorthVertical (TVD) Reference: Mean Sea LevelSection (VS) Reference: Slot - (0.00N, 0.00E)Measured Depth Reference: 3G-24 @ 90.00usft (Doyon 14)Calculation Method: Minimum Curvature3G-24L1_wp023G-24L1-01_wp013G-24L1-02_wp022
Last Tag
Annotation Depth (ftKB) End Date Wellbore Last Mod By
Last tag: 20' Rat Hole 9,678.0 8/16/2019 3G-24 jhansen8
Last Rev Reason
Annotation End Date Wellbore Last Mod By
Rev Reason: Pulled Plug & Measured BHP 3/9/2020 3G-24 zembaej
Casing Strings
Casing Description
CONDUCTOR
OD (in)
16
ID (in)
15.06
Top (ftKB)
35.0
Set Depth (ftKB)
115.0
Set Depth (TVD) …
115.0
Wt/Len (l…
62.58
Grade
H-40
Top Thread
WELDED
Casing Description
SURFACE
OD (in)
9 5/8
ID (in)
8.92
Top (ftKB)
34.5
Set Depth (ftKB)
4,572.5
Set Depth (TVD) …
3,102.2
Wt/Len (l…
36.00
Grade
J-55
Top Thread
BTC
Casing Description
PRODUCTION
OD (in)
7
ID (in)
6.28
Top (ftKB)
35.0
Set Depth (ftKB)
9,930.7
Set Depth (TVD) …
6,074.4
Wt/Len (l…
26.00
Grade
J-55
Top Thread
AB-MOD
Tubing Strings
Tubing Description
TUBING
3.5"x2.875" @9420'
String Ma…
3 1/2
ID (in)
2.99
Top (ftKB)
31.4
Set Depth (ft…
9,527.3
Set Depth (TVD) (…
5,773.6
Wt (lb/ft)
9.30
Grade
J-55
Top Connection
EUE8rdABMOD
Completion Details
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des Com
Nominal
ID (in)
31.4 31.4 0.03 HANGER WKM GEN IV HANGER 3.500
1,785.2 1,631.7 42.71 SAFETY VLV OTIS FMX SAFETY VALVE - LOCKED OUT 2.813
9,420.0 5,699.9 48.25 XO Reducing CROSSOVER 3.5 x 2.875 2.875
9,426.3 5,704.1 48.06 PBR CAMCO OEJ PBR 2.312
9,443.8 5,715.9 47.54 PACKER CAMCO HRP-1-SP PACKER 2.347
9,514.9 5,764.9 45.52 NIPPLE CAMCO D NIPPLE NO GO 2.250
9,526.6 5,773.1 45.27 SOS CAMCO SHEAR OUT SUB 2.441
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Des Com Run Date ID (in)
9,336.0 5,645.3 50.62 PATCH 3.5" HALLIBURTON PERMANENT PATCH (SEE
DRAWING IN WORKING FILE)
12/24/200
5
2.360
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft
)Type Com
9,618.0 9,658.0 5,838.5 5,867.9 A-2, A-1, 3G-24 1/8/1991 4.0 IPERF 180 deg. phasing, 4 1/2"
JRC
Mandrel Inserts
St
ati
on
N
o/Top (ftKB)
Top (TVD)
(ftKB) Make Model OD (in) Serv
Valve
Type
Latch
Type
Port Size
(in)
TRO Run
(psi) Run Date Com
1 2,983.7 2,304.3 McMurray FMHO 1 GAS LIFT DMY BK 0.000 0.0 9/19/1996
2 5,497.2 3,586.2 McMurray FMHO 1 GAS LIFT DMY BK 0.000 0.0 1/9/1991
3 6,846.5 4,281.9 McMurray FMHO 1 GAS LIFT DMY BK 0.000 0.0 1/9/1991
4 7,803.6 4,780.8 McMurray FMHO 1 GAS LIFT DMY BK 0.000 0.0 9/19/1996
5 8,714.8 5,279.2 McMurray FMHO 1 GAS LIFT DMY BK 0.000 0.0 1/9/1991
6 9,371.2 5,667.9 MACCO SPM-2 1 1/2 GAS LIFT DMY RK 0.000 0.0 8/20/2019 Ext
PKG
7 9,467.7 5,732.1 CAMCO TGPD 1 1/2 PROD DMY RK 0.000 0.0 1/9/1991
Notes: General & Safety
End Date Annotation
11/29/2016 NOTE: Waivered for water injection only, TxIA communication on gas.
8/31/2010 NOTE: View Schematic w/ Alaska Schematic9.0
3/6/2008 NOTE:SSSV CONTROL LINE LEAK - LAST GX SEALANT TREATMENT
3G-24, 3/10/2020 8:00:33 AM
Vertical schematic (actual)
PRODUCTION; 35.0-9,930.7
IPERF; 9,618.0-9,658.0
SOS; 9,526.6
NIPPLE; 9,514.9
PRODUCTION; 9,467.7
PACKER; 9,443.8
PBR; 9,426.3
GAS LIFT; 9,371.2
PATCH; 9,336.0
GAS LIFT; 8,714.8
GAS LIFT; 7,803.6
GAS LIFT; 6,846.5
GAS LIFT; 5,497.2
SURFACE; 34.5-4,572.5
GAS LIFT; 2,983.7
SAFETY VLV; 1,785.2
CONDUCTOR; 35.0-115.0
HANGER; 31.4
KUP INJ
KB-Grd (ft)
37.21
Rig Release Date
10/12/1990
3G-24
...
TD
Act Btm (ftKB)
9,940.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
501032014500
Wellbore Status
INJ
Max Angle & MD
Incl (°)
62.36
MD (ftKB)
3,900.00
WELLNAME WELLBORE3G-24
Annotation
Last WO:
End DateH2S (ppm) DateComment
SSSV: LOCKED OUT
3-1/2" 9.3# L-80 EUE 8rd Tubing to surface3-1/2" Nipple @ 5021' (2.813" ID)3-1/2" MMG gas lift mandrel @ 9325' MDPBR 9395' MDPacker @ 9406' MD (4.0" ID)3-1/2" Nipple @ 9560' MD (2.813" ID)3-1/2" Nipple @ 9626' MD (2.813" ID)3-1/2" Nipple @ 9646' MD (2.813" ID)Northern Solutions WEDGE (see details)7" 26# J-55 shoe @ 9931' MDA-sand perfs 9618' - 9658' MD9-5/8" 36# J-55 shoe @ 4573' MD16" 62# H-40 shoe @ 115' MDProposed KOP @ 9634' MD3G-24L1 wp02TD 13,700' MDWOB = 13,700' MDTop of Billet @ 12,100' MDNorthern Solutions Wedge* 3-1/2" 9.3# L-80 Base Pipe* 5.905" OD (12.9' long)* ~23.14' Total Length* 0.625" Bore thru Upper Tray* 1.125" Bore thru Lower Section* HES 2.81" X Nipple below 3G-24L1-02 wp02TD 13,500' MDWOB = 12,502' MDTop of Liner ~ 9634' MD3G-24L1-01 wp01TD 13,700' MDWOB = 13,700' MDTop of Billet @ 9,840' MDNORTHNORTHSOUTHProposed CTD Schematic (Post RWO & CTD operations). Note: RWO operations currently in progress (10-29-21)
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
KRU 3G-24L1-02
221-092
X
Kuparuk River Kuparuk River Oil
X 190-134
103-20145-00-00
X
X
WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3G-24L1-02Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2210920KUPARUK RIVER, KUPARUK RIV OIL - 490100NA1Permit fee attachedYes2Lease number appropriateYes3Unique well name and numberYes4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYesDirectional plan view included, no land plat in package.8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitYesAIO 2C applies.14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)YesKRU 3G-24L1-02 will not be pre-produced.16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA18Conductor string providedNA19Surface casing protects all known USDWsNA20CMT vol adequate to circulate on conductor & surf csgNA21CMT vol adequate to tie-in long string to surf csgNoProductive interval will be completed with uncemented slotted liner22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesRig has steel tanks; all waste to approved disposal wells24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision analysis complete; no major risk failures26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYesMax formation pressure is 4548 psig(14.9 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD chok28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 3960 psig; will test BOPs to 4500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesH2S measures required33Is presence of H2S gas probableYesKRU 3H-05 P&A'd34Mechanical condition of wells within AOR verified (For service well only)No3G-Pad wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYes36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate11/2/2021ApprVTLDate11/3/2021ApprDLBDate11/2/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03JLC 11/4/2021
