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DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-21447-60-00Well Name/No. KUPARUK RIV UNIT 3F-02L1Completion Status1-OILCompletion Date11/28/2021Permit to Drill2210890Operator ConocoPhillips Alaska, Inc.MD11602TVD6103Current Status1-OIL1/24/2022UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:GR, ResNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF12/17/20217152 11602 Electronic Data Set, Filename: 3F-02L1 GAMMA RES.las36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 2MD Final Log.cgm36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5MD Final Log.cgm36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5TVDSS Final Log.cgm36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 01 PWD.cgm36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 02 PWD.cgm36098EDDigital DataDF12/17/2021 Electronic 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January 24, 2022AOGCCPage 1 of 5PB13F-02L1 GAMMA RES.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-21447-60-00Well Name/No. KUPARUK RIV UNIT 3F-02L1Completion Status1-OILCompletion Date11/28/2021Permit to Drill2210890Operator ConocoPhillips Alaska, Inc.MD11602TVD6103Current Status1-OIL1/24/2022UICNoDF12/17/2021 Electronic File: 3F-02L1_PWD Log Run 06.ASC36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1_PWD Log Run 07.ASC36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1_PWD Log Run 08.ASC36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1_PWD Log Run 09.ASC36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1_PWD Log Run 10.ASC36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 2MD Final.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5MD Final.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5TVDSS Final.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 01 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 02 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 03 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 04 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 05 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 06 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 07 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 08 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 09 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 10 PWD.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 NAD27 Definitive Survey.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 NAD27 Definitive Survey.txt36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 NAD83 Definitive Survey.pdf36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 NAD83 Definitive Survey.txt36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 2MD Final Log.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5MD Final Log.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 5TVDSS Final Log.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 01 PWD.tif36098EDDigital DataMonday, January 24, 2022AOGCCPage 2 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-21447-60-00Well Name/No. KUPARUK RIV UNIT 3F-02L1Completion Status1-OILCompletion Date11/28/2021Permit to Drill2210890Operator ConocoPhillips Alaska, Inc.MD11602TVD6103Current Status1-OIL1/24/2022UICNoDF12/17/2021 Electronic File: 3F-02L1 Run 02 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 03 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 04 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 05 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 06 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 07 PWD.tif36098EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 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01.ASC36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1_ PWD Log Run 02.ASC36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1_ PWD Log Run 03.ASC36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1_PWD Log Run 04.ASC36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 2MD Final.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 5MD Final.pdf36099EDDigital DataMonday, January 24, 2022AOGCCPage 3 of 53F-02L1PB1 GAMMA RES.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-21447-60-00Well Name/No. KUPARUK RIV UNIT 3F-02L1Completion Status1-OILCompletion Date11/28/2021Permit to Drill2210890Operator ConocoPhillips Alaska, Inc.MD11602TVD6103Current Status1-OIL1/24/2022UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDDF12/17/2021 Electronic File: 3F-02L1PB1 5TVDSS Final.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 01 PWD.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 02 PWD.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 03 PWD.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1 Run 04 PWD.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 NAD27 Definitive Survey.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 NAD27 Definitive Survey.txt36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 NAD83 Definitive Survey.pdf36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 NAD83 Definitive Survey.txt36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 2MD Final Log.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 5MD Final Log.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 5TVDSS Final Log.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 Run 01 PWD.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 Run 02 PWD.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 Run 03 PWD.tif36099EDDigital DataDF12/17/2021 Electronic File: 3F-02L1PB1 Run 04 PWD.tif36099EDDigital Data0 0 2210890 KUPARUK RIV UNIT 3F-02L1 PB1 LOG HEADERS36099LogLog Header ScansMonday, January 24, 2022AOGCCPage 4 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-21447-60-00Well Name/No. KUPARUK RIV UNIT 3F-02L1Completion Status1-OILCompletion Date11/28/2021Permit to Drill2210890Operator ConocoPhillips Alaska, Inc.MD11602TVD6103Current Status1-OIL1/24/2022UICNoCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 11/28/2021Release Date:11/1/2021Monday, January 24, 2022AOGCCPage 5 of 5M. 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' 3!89'89 #.2. <() T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA December 17, 2021 AOGCC Attention: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject: Final Log Distribution for ConocoPhillips Alaska, Inc. 3F-02L1PB1 Kuparuk River API #: 50-029-21447-70-00 Permit No: 221-089 Rig: CDR3 The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files. Thank you. Signature of receiver & date received: Please return transmittal letter to: Jenny Jones Jenny.E.Jones@conocophillips.com Melissa LeMay Melissa.LeMay@bakerhughes.com 15% &4FU 12/20/2021 By Abby Bell at 3:35 pm, Dec 17, 2021 T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA December 17, 2021 AOGCC Attention: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject: Final Log Distribution for ConocoPhillips Alaska, Inc. 3F-02L1 Kuparuk River API #: 50-029-21447-60-00 Permit No: 221-089 Rig: CDR3 The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files. Thank you. Signature of receiver & date received: Please return transmittal letter to: Jenny Jones Jenny.E.Jones@conocophillips.com Melissa LeMay Melissa.LeMay@bakerhughes.com 15% &4FU 12/20/2021 By Abby Bell at 3:35 pm, Dec 17, 2021 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 Tyler Senden CTD Engineering Director ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3F-02L1 ConocoPhillips Alaska, Inc. Permit to Drill Number: 221-089 Surface Location: 78’ FNL, 139’ FWL, Sec. 29, T12n, R9E, UM Bottomhole Location: 258’ FSL, 751’ FEL, SEC. 29, T12N, R9E, 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 185-226, API 50-029-21447-00- 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: 2021.11.01 17:41:06 -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: 11,600' TVD:5948' 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): 93' 15. Distance to Nearest Well Open Surface: x- 508639 y- 5985745 Zone- 4 52' to Same Pool: 292' (3F-01L1) 16. Deviated wells: Kickoff depth: 7400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 97 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 3" 2-3/8" 4.7# L-80 ST-L 4205' 7395' 5845' 11600' 5948' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 7699 TVD 110' 3084' 6283' 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: Shane Germann Tyler Senden Contact Email:shane.germann@cop.com CTD Engineering Director Contact Phone:907-263-4597 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 7270'-7390', 7561'-7602', 7624'-7666' 5841'-5934', 6067'-6099', 6116'-6149' 11/5/2021 21,970'258' FSL, 751' FEL, SEC 29, T12N, R9E, UM 1291' FNL, 1436' FEL, SEC 29, T12N, R9E KRU 3F-02L1 Kuparuk River Pool / Kuparuk River Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 7839'7" Total Depth MD (ft): Total Depth TVD (ft): 5952180 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 4443 LONS 84-149 P.O. Box 100360 Anchorage, AK 99510-0360 ConocoPhillips Alaska Inc 78' FNL, 139' FWL, SEC 29, T12N, R9E, UM ADL 25643 2560 18. Casing Program: Top - Setting Depth - BottomSpecifications 5037 Cement Volume MDSize Plugs (measured): (including stage data) Slotted / Solid Liner 7750 6213 Conductor/Structural 16"72' 7864 6303 LengthCasing N/A Authorized Title: Authorized Signature: 450 sx Class G & 200 sx PF "C"Production Liner 7804' Intermediate Authorized Name: 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): 3468' 270 sx AS II 110' 3505'9-5/8" 980 sx PF "E" & 400 sx PF "C" Effect. Depth MD (ft): Effect. Depth TVD (ft): 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) 10/21/202 By Samantha Carlisle at 12:22 pm, Oct 21, 2021 X 221-089 X X 50-029-21447-60-00 X DLB X X X TVDss DSR-10/21/21 TVD: 6041' TVD BOP test to 5000 psig Annular preventer test to 2500 psig VTL 11/1/21 X DLB 10/25/2021 DLB X dts 11/1/2021 JLC 11/1/2021 11/1/21 Jeremy Price Digitally signed by Jeremy Price Date: 2021.11.01 17:41:41 -08'00' P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Oct 20, 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 an application for a permit to drill one lateral out of the KRU 3F-02 (PTD# 185-226) using the coiled tubing drilling rig, Nabors CDR3-AC. CTD operations are scheduled to begin in mid-November 2021. The objective will be to drill one lateral, KRU 3F-02L1, targeting the Kuparuk A-sand interval. Attached to permit to drill applications are the following documents: Permit to Drill Application Forms (10-401) for 3F-02L1 Detailed Summary of Operations Directional Plans for 3F-02L1 Current Wellbore Schematic Proposed CTD Schematic If you have any questions or require additional information, please contact me at 907-263-4597. Sincerely, Shane Germann Coiled Tubing Drilling Engineer ConocoPhillips Alaska Digitally signed by Shane Germann DN: O=ConocoPhillips Alaska, CN=Shane Germann, E=shane.germann@cop.com Reason: I am the author of this document Location: your signing location here Date: 2021.10.19 14:47:28-08'00' Foxit PDF Editor Version: 11.0.0 Kuparuk CTD Lateral 3F-02L1 Application for Permit to Drill Document Page 1 of 6 October 20, 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 CTD Operations .......................................................................................................................................... 4 Liner Running .................................................................................................................................................................. 5 14. Disposal of Drilling Mud and Cuttings ........................................................................................... 5 (Requirements of 20 AAC 25.005(c)(14)) ............................................................................................................................................... 5 15. Directional Plans for Intentionally Deviated Wells ........................................................................ 6 (Requirements of 20 AAC 25.050(b)) ..................................................................................................................................................... 6 16. Attachments .................................................................................................................................... 6 Attachment 1: Directional Plans for the 3F-02L1 lateral ................................................................................................. 6 Attachment 2: Current Well Schematic for 3F-02 ........................................................................................................... 6 Attachment 3: Proposed Well Schematic for the 3F-02L1 lateral ................................................................................... 6 PTD Application: 3F-02L1 Page 2 of 6 October 20, 2021 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed lateral described in this document is 3F-02L1. The lateral will be classified as “Development” well. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) The lateral will target the A-Sand package in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of the 3F-02L1. 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 5000 psi. Using the maximum formation pressure in the area of 5037 psi found in 3F-03 measured 8/16/2019 (i.e.15.62 ppg EMW, SWHP converted to BHP), the maximum potential surface pressure in 3F-02, assuming a gas gradient of 0.1 psi/ft, would be 4443 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 3F-02 was measured at 3183 psi @ 6200’ TVD (9.87 ppg, SWHP converted to BHP) on 6/10/2020. The maximum downhole pressure in the 3F-02 vicinity is 3F-03 at 5037 psi @ 6200’ TVD (15.62 ppg, SWHP converted to BHP– Measured 8/16/2019). Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) The offset injection wells to 3F-02 have injected gas, so there is a possibility of encountering free gas while drilling the 3F-02 lateral. 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 3F-02 lateral will be formation 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 3F-02 lateral will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. PTD Application: 3F-02L1 Page 3 of 6 October 20, 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 3F-02L1 ~7395’ 11,600’ 5845’ 5948’ 2-3/8", 4.7#, L-80, ST-L slotted liner, solid liner with swell packer, and 6’ polished bore with a liner-top packer Existing Casing/Liner Information Category OD Weight (ppf)Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16” 65 H-40 Welded 38’ 110’ 38’ 110’ 1640 670 Surface 9-5/8” 36.0 J-55 BTC 37’ 3505’ 37’ 3084’ 3520 2020 Production 7” 26.0 J-55 BTC 40’ 7839’ 40’ 6283’ 4980 4320 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 completion fluid in order to provide formation over- balance and well bore stability while running completions (11.8 ppg NaBr) 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 3F-02L1 lateral, operations will target a constant BHP of ~11.8 ppg EMW at the window (just over formation pressure). 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 py p the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud In the 3F-02L1 lateral, operations will target a constant BHP of ~11.8 ppg EMW at the window (just over formation weight is not, in many cases, the primary well control barrier. pp yg pressure). DLB 10/25/21 PTD Application: 3F-02L1 Page 4 of 6 October 20, 2021 Pressure at the 3F-02 Window (7400’ MD, 5942’ TVD) Using MPD Pumps On (1.9 bpm) Pumps Off A-sand Formation Pressure (9.9 ppg) 3058 psi 3058 psi Mud Hydrostatic (8.6 ppg) 2657 psi 2657 psi Annular friction (i.e. ECD, 0.080 psi/ft) 592 psi 0 psi Mud + ECD Combined (no choke pressure) 3249 psi (overbalanced ~191 psi) 2657 psi (underbalanced ~401 psi) Target BHP at Window (11.8 ppg) 3646 psi 3646 psi Choke Pressure Required to Maintain Target BHP 397 psi 989 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 CTD Operations KRU well 3F-02 is equipped with 3-1/2” tubing and 7” production casing. The CTD sidetrack will utilize one lateral to target the A-sands to the south of 3F-02. CDR3-AC will mill a 2-string window in the 3-1/2” tubing and 7” casing at ~7400’ MD and the 3F-02L1 lateral will be drilled to TD at 11,600’ MD, targeting the A-sands to the south. It will be completed with 2-3/8” slotted liner, solid liner with a swell packer, and a 6’ polished bore from TD up to ~7395’ MD. CTD Pre-Rig, Drill, and Complete 3F-02L1 Sidetrack: November 2021 Pre-CTD Work 1. Pre-CTD diagnostics 2. Slickline: Dummy whipstock drift, pull BPI, set plug, bail sand, c/o GLV’s, injectivity test 3. CTU: Pump cement (fill IA within C-sand straddle packers), mill cement 4. Slickline: Dummy whipstock drift 5. E-Line: Run caliper/GR 6. E-Line: Set Whipstock at 7400‘ MD (p) Target BHP at Window (11.8 ppg) 3646 psi 3646 psi DLB PTD Application: 3F-02L1 Page 5 of 6 October 20, 2021 Rig Work 1. MIRU Nabors CDR3-AC rig using 2” coil tubing. NU 7-1/16” BOPE, test. 2. Drill 3F-02L1 Lateral (A-sand - South) i. Mill 2.80” window at ~7400’ MD. ii. Drill 3” bi-center lateral to TD of 11,600’ MD. iii. Run 2Ǫ” slotted liner, solid liner with swell-packer, & 6’ polished bore from TD up to ~7395’ MD (into tubing-tail) 3. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post-Rig Work 1. Set liner-top packer on 6’ polished bore 2. 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. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running The 3F-02 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. PTD Application: 3F-02L1 Page 6 of 6 October 20, 2021 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 3F-02L1 21,970’ Distance to Nearest Well within Pool Lateral Name Distance Well 3F-02L1 292’ 3F-01L1 16. Attachments Attachment 1: Directional Plans for the 3F-02L1 lateral Attachment 2: Current Well Schematic for 3F-02 Attachment 3: Proposed Well Schematic for the 3F-02L1 lateral ' (" " $:'_Kuparuk # $ "!%" # $ & "'$ ' (" " ' " )' * &+ )' , - "#$% &'(. )' /' % ( )'" !!+%+ % %!- ' " .( 0 0 * " . - , 1 , /' . 2 - , ,* #.'/, %! 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( 6 )8 " ", 6=8 B ", 6=8 , " " =7/9=871..$4.1$= 9=8 =7/9=871#4.$819$= 9=8 , 2! ! )% % ! *! )% % !, - Kuparuk River Unit_2ConocoPhillips Alaska Inc_KuparukAnticollision Report for 3F-02 - 3F-02L1 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 7,300.00 to 11,600.00 usft. True Vertical Depth. Trav. Cylinder North Proximity Scan on Current Survey Data (North Reference)Reference Design: Kuparuk 3F Pad - 3F-02 - 3F-02L1 CTD Sidetrack - 3F-02L1 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningKuparuk 3F Pad3F-01 - 3F-01 - 3F-01 360.83 10,500.00 148.41 8,500.00 1.69910,500.00Clearance Factor Pass - 3F-01 - 3F-01 - 3F-01 357.96 10,558.67 147.71 8,600.00 1.70310,558.67Ellipse Separation Pass - 3F-01 - 3F-01L1 - 3F-01L1 292.20 10,878.32 105.40 8,800.00 1.56410,878.32Clearance Factor Pass - 3F-01 - 3F-01L1-01 - 3F-01L1-01 292.20 10,878.32 105.40 8,800.00 1.56410,878.32Clearance Factor Pass - 3F-02 - 3F-02 - 3F-02 121.93 7,645.68 116.56 7,700.00 22.7297,645.68Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool100.00 7,300.00GCT-MS7,300.00 11,600.00 3F-02L1 wp05 MWD OWSGEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.27 August, 2021-10:56COMPASSPage 2 of 4 555057005850600061506300True Vertical Depth (300 usft/in)2750 3000 3250 3500 3750 47504250 5250500045004000250022502000175015001250Vertical Section at 180.00° (500 usft/in)3F-02L1 T3.8.6T312L-03F.5T3L12F-033.7TL12F-03.2T312LF-03.9T312L03F-3.1TL102F-33F-02L1 T3.433.TL102F-33F-02L1 T3.103F-02/3F-023F-02/3F-02L1 wp05SECTION DETAILSSecInc Azi TVDssMD+N/-SDleg TFace+E/-WVSect1196.300.00 0.0038.92 103.92 5771.43 -1196.30 3648.271 7300.001211.390.03 -68.3238.93 103.88 5849.23 -1211.39 3709.2627400.001215.5035.00 0.0047.68 103.88 5867.40 -1215.50 3725.8937425.001229.0618.00 0.0060.28 103.88 5908.48 -1229.06 3780.7447495.001376.5518.00 59.9790.00 144.50 5980.00 -1376.55 3986.1357765.881520.017.00 -80.0092.34 131.11 5976.02 -1520.01 4116.1767960.001709.017.00 75.0096.70 148.12 5956.18 -1709.01 4277.107 8210.001865.177.00 115.0091.43 159.21 5943.74 -1865.17 4354.3588385.002307.737.00 91.0090.70 190.70 5935.17 -2307.73 4393.419 8835.002667.547.00 92.0089.68 218.69 5933.84 -2667.54 4227.9510 9235.003027.377.00 -90.0089.71 190.68 5936.01 -3027.37 4062.5611 9635.003340.417.00 -85.0091.61 168.71 5932.32 -3340.41 4064.1912 9950.003513.905.00 90.0091.59 177.47 5927.42 -3513.90 4085.2113 10125.003902.085.00 -85.0093.20 157.51 5910.52 -3902.08 4171.3014 10525.004189.635.00 120.0085.69 170.50 5913.43 -4189.63 4253.7215 10825.004429.085.00 -90.0085.79 157.97 5932.09 -4429.08 4321.3116 11075.004619.515.00 67.0089.73 167.17 5939.91 -4619.51 4381.0817 11275.004942.205.00 98.0087.51 183.27 5947.78 -4942.20 4408.0918 11600.00WELL DETAILS: 3F-020.00+N/-S +E/-WLatittude0.00 0.00Kuparuk River Unit_2Kuparuk 3F Pad3F-023F-02L1 CTD Sidetrack3F-02L1 wp05WELLBORE DETAILS3F-02L1 CTD SidetrackParent Wellbore : 3F-02Planned Tie On Depth (ft MD): 7300Azimuths to True NorthMagnetic North: 15.31°Magnetic FieldStrength: 57297.6nTDip Angle: 80.72°Date: 12/15/2021Model: BGGM2021TM-5250-4500-3750-3000-2250-1500South(-)/North(+) (1500 usft/in)2250 3000 3750 4500 5250West(-)/East(+) (1500 usft/in)3F-023F-02L1 wp05Reference Coordinate: Well 3F-02, True NorthReference TVD: Mean Sea LevelReference Section:Slot - (0.00N, 0.00E)Reference MD:3F-02 @ 93.00usft (3F-02)Calculation Method: Minimum CurvatureNorthing5985745.10Ground Level:Easting 508638.99 70° 22' 20.186 NLongitude 149° 55' 47.232 W -5700 -4750 -3800 -2850 -1900 -950 0 South(-)/North(+) (950 usft/in)2850 3800 4750 5700 6650 7600 West(-)/East(+) (950 usft/in)40004250450047505000525055005750600062103F-02/3F-02 375040004250450047505000525055005750600061523F-01/3F-01375040004250450047505000525 0550057503F-01/3F-01L137504000425045004750500052 50550057503F-01/3F-01L1-0140004250450047505000525055005750 5948 3F-02/3F-02L1 CTD Sidetrack Project:Kuparuk River Unit_2 Site:Kuparuk 3F Pad Well:3F-02 Wellbore:3F-02L1 CTD Sidetrack Plan: 3F-02L1 wp05 (3F-02/3F-02L1 CTD Sidetrack) Mean Sea Level WELLBORE DETAILS:3F-02L1 CTD Sidetrack Parent Wellbore:3F-02 Tie on MD:7300.00 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well 3F-02, True North Vertical (TVD) Reference:Mean Sea Level Section (VS) Reference:Slot - (0.00N, 0.00E) Measured Depth Reference:3F-02 @ 93.00usft (3F-02) Calculation Method: Minimum Curvature Azimuths to True North Magnetic North: 15.31° Magnetic Field Strength: 57297.6nT Dip Angle: 80.72° Date: 12/15/2021 Model: BGGM2021 T M Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: RKB 7,428.0 10/14/2021 3F-02 zembaej Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Set plug (A-Sand Iso), Pulled BPI & DV from Prod Mandrel, & Installed New GLD 10/14/2021 3F-02 zembaej Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 38.0 Set Depth (ftKB) 110.0 Set Depth (TVD) … 110.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.92 Top (ftKB) 37.0 Set Depth (ftKB) 3,504.5 Set Depth (TVD) … 3,085.3 Wt/Len (l… 36.00 Grade J-55 Top Thread BTC Casing Description PRODUCTION TIE- BACK OD (in) 7 ID (in) 6.28 Top (ftKB) 40.6 Set Depth (ftKB) 1,882.0 Set Depth (TVD) … 1,840.9 Wt/Len (l… 26.00 Grade L-80 Top Thread TC-ll Casing Description PRODUCTION POST TIE-BACK OD (in) 7 ID (in) 6.28 Top (ftKB) 1,882.0 Set Depth (ftKB) 7,839.2 Set Depth (TVD) … 6,283.4 Wt/Len (l… 26.00 Grade J-55 Top Thread BTC Tubing Strings Tubing Description TUBING WO String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 33.1 Set Depth (ft… 7,141.0 Set Depth (TVD) (… 5,741.1 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE 8rd Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 33.1 33.1 0.01 HANGER FMC Gen IV Tbg Hanger w/ 3-1/2 EUE Top and Bottom w/ 3" Type 'H' Profile 3.000 508.4 508.4 0.11 NIPPLE CAMCO 'DS' NIPPLE 2.875 7,070.0 5,686.3 39.63 SEAL ASSY BAKER LOCATOR SUB w/ 7-ft 3.000 7,077.3 5,692.0 39.60 PBR BAKER 80-40 PBR 4.000 7,100.7 5,710.0 39.50 PACKER BAKER FHL PACKER 2.900 7,122.4 5,726.8 39.44 NIPPLE CAMCO 'DS' NIPPLE 2.812 7,133.6 5,735.4 39.41 OVERSHOT BAKER POOR BOY OVERSHOT 2.990 Tubing Description TUBING Original String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 7,135.3 Set Depth (ft… 7,456.7 Set Depth (TVD) (… 5,986.3 Wt (lb/ft) 9.30 Grade J-55 Top Connection EUE 8RD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 7,159.6 5,755.5 39.33 PBR BAKER PBR 3.000 7,173.3 5,766.1 39.29 PACKER BAKER FHL PACKER 3.000 7,249.1 5,824.9 39.07 BLAST JT RICKERT BLAST JOINTS (5) 2.992 7,418.8 5,956.9 38.98 NIPPLE AVA BPL LANDING NIPPLE 05B 2.750 7,431.9 5,967.1 39.02 LOCATOR BAKER LOCATOR SEAL ASSEMBLY 3.000 7,433.7 5,968.4 39.03 PACKER BAKER FB-1 PACKER 3.000 7,437.0 5,971.0 39.04 SBE BAKER SEAL BORE EXTENSION 4.000 7,441.4 5,974.4 39.05 XO-Reducing 3.5"x2.875" 2.441 7,448.6 5,980.0 39.07 NIPPLE CAMCO D NIPPLE NO GO 2.250 7,456.0 5,985.8 39.09 SOS CAMCO SHEAROUT SUB 2.438 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 7,428.0 5,964.0 39.01 OTHER 9' of Sand came in from the C-Sand 10/14/2021 0.000 7,437.6 5,971.5 39.04 OTHER Dump bailed 11' of Silica Sand on top of CA- 2 Plug 10/13/2021 0.000 7,448.6 5,980.0 39.07 TUBING PLUG Set 2.25" CA-2 Plug (25" OAL) 10/12/2021 0.000 7,699.0 6,174.3 38.93 FISH 50% of Grapple & Wire Still in hole from 4/1/94 4/2/1994 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 7,270.0 7,390.0 5,841.1 5,934.4 C-4, C-3, C-2, C -1, 3F-02 11/30/1985 12.0 IPERF 5" Csg Gun; 120 deg ph 7,561.0 7,602.0 6,067.1 6,099.0 A-4, A-3, 3F-02 11/30/1985 4.0 IPERF 4" Csg Gun; 90 deg ph 7,570.0 7,600.0 6,074.1 6,097.4 A-3, 3F-02 4/10/1998 4.0 RPERF 2 1/8" Enerjet Bighole; 0 deg ph, 0 deg orient 7,624.0 7,666.0 6,116.0 6,148.7 A-2, 3F-02 11/30/1985 4.0 IPERF 4" Csg Gun; 90 deg ph Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 40.6 1,882.0 40.6 1,840.9 CSG TIE- BACK 6/24/2013 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 2,721.0 2,500.4 41.90 Camco KBMG 1 GAS LIFT GLV BK 0.156 1,265.0 10/14/2021 2 4,501.8 3,795.5 43.83 Camco KBMG 1 GAS LIFT GLV BK 0.188 1,299.0 10/14/2021 3 5,603.6 4,595.5 43.06 Camco KBMG 1 GAS LIFT OV BK 0.250 0.0 10/14/2021 4 6,464.9 5,228.7 41.67 Camco KBMG 1 GAS LIFT DMY BK 0.000 0.0 10/14/2021 5 7,015.4 5,644.4 39.86 Camco KBMG 1 GAS LIFT DMY BK 0.000 0.0 10/14/2021 6 7,211.4 5,795.7 39.19 Camco KBUG 1 PROD OPEN OPEN 0.000 0.0 10/13/2021 3F-02, 10/15/2021 8:44:23 AM Vertical schematic (actual) PRODUCTION POST TIE- BACK; 1,882.0-7,839.2 FISH; 7,699.0 IPERF; 7,624.0-7,666.0 RPERF; 7,570.0-7,600.0 IPERF; 7,561.0-7,602.0 SOS; 7,456.0 TUBING PLUG; 7,448.6 NIPPLE; 7,448.6 OTHER; 7,437.6 SBE; 7,437.1 PACKER; 7,433.7 OTHER; 7,428.0 NIPPLE; 7,418.8 IPERF; 7,270.0-7,390.0 PRODUCTION; 7,211.4 PACKER; 7,173.3 PBR; 7,159.6 OVERSHOT; 7,133.6 NIPPLE; 7,122.4 PACKER; 7,100.7 PBR; 7,077.3 SEAL ASSY; 7,070.0 GAS LIFT; 7,015.4 GAS LIFT; 6,464.9 GAS LIFT; 5,603.6 GAS LIFT; 4,501.8 SURFACE; 37.0-3,504.5 GAS LIFT; 2,721.0 PRODUCTION TIE-BACK; 40.6- 1,882.0 CSG TIE-BACK; 40.6 ftKB NIPPLE; 508.4 CONDUCTOR; 38.0-110.0 HANGER; 33.1 KUP PROD KB-Grd (ft) 41.00 Rig Release Date 10/3/1985 3F-02 ... TD Act Btm (ftKB) 7,864.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292144700 Wellbore Status PROD Max Angle & MD Incl (°) 45.70 MD (ftKB) 3,800.00 WELLNAME WELLBORE3F-02 Annotation Last WO: End Date 6/29/2013 H2S (ppm) 135 Date 11/20/2016 Comment SSSV: NIPPLE 3F-02 Proposed CTD Schematic 3-1/2" Camco DS nipple @ 508' MD (2.875" min ID) 3-1/2" 9.3# L-80 EUE 8rd Tubing to surface 3-1/2" Camco gas lift mandrels @ 2721', 4502', 5604', 6465', 7015' Baker 80-40 PBR @ 7077' MD (4.0" ID) Baker FHL packer @ 7107' MD (2.9" ID) 3-1/2" Camco DS nipple @ 7122' MD (2.812" min ID) Baker PB Overshot @ 7134' MD Baker PBR @ 7160' MD (3.0" ID) Baker FHL packer @ 7173' MD (3.0" ID) 3-1/2" Camco gas lift mandrels @ 7211' MD AVA BPL Landing Nipple @ 7418' MD (2.75" ID) Baker FB-1 packer @ 7433' MD (3.0" ID) Baker SBE @ 7437' MD Camco D nipple @ 7448' MD (2.25" min ID, No-Go) 3-1/2" SOS @ 7456' MD 9-5/8" 36# J-55 shoe @ 3505' MD 7" 26# J-55 shoe @ 7839' MD 16" 62# H-40 shoe @ 110' MD A-sand perfs 7561' - 7666' MD KOP @ 7400' MD C-sand perfs 7270' - 7390' MD Modified by SJG 10/19/21 3F-02L1 wp05 TD ~ 11600' MD Top of Liner ~ 7395' MD 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. 029-21447-00-00 X 221-089 185-226 Kuparuk River Unit X Kuparuk River Oil X KRU 3F-02L1 X WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3F-02L1Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2210890KUPARUK 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 unitYesWellbore 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 waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-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)NAConductor set for KRU 3F-0218Conductor string providedNASurface casing set and fully cemented19Surface 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 an uncemented slotted/solid 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 faillures26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYesMax formation pressure is 5037 psig(15.6 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 4443 psig; will test BOPs to 5000 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 probableNA34Mechanical condition of wells within AOR verified (For service well only)No3F-Pad wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYesCTD MPD utilized to maintain pressure.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate10/21/2021ApprVTLDate11/1/2021ApprDLBDate10/21/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03JLC 11/1/2021
