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Home My WebLink About222-006 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8547 September 29, 2023 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023 Dear Mr. Rixse, Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water “grease-like” filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, API and PTD numbers, treatment dates and volumes. If you have any additional questions, please contact me at 907-777-8406 or dhorner@hilcorp.com. Sincerely, Darci Horner Regulatory Tech Hilcorp Alaska, LLC Digitally signed by Darci Horner (c-100048) DN: cn=Darci Horner (c-100048) Date: 2023.09.29 09:45:20 - 08'00' Darci Horner (c-100048) Well Field API PTD Initial Top of Cement (ft.) Volume of Cement Pumped (bbls) Final Top of Cement (ft.) Cement Pump Date Corrosion Inhibitor Fill Volume (gal) Final CI Top (ft.) Corrosion Inhibitor Treatment Date Comments MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022. MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023. MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021. MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023 Drilled in March 2022. Completeted on 4/30/22. MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020. MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019. MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022. MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022. MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020. MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023. MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021. MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021. Notes: The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7 Initial top of cement footage measurement was taken from the 4" outlet down to the TOC RBDMS JSB 100323 Drilled in March 2022. CompletetedMPI-29 MPU 50029237080000 2220060 6'0.5 3 7/2/2023 15 surfce 9/27/2023 on 4/30/22. David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/22/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL – Revised: MPU I-29 (PTD: 222-006 API: 50-029-23708-00-00) FINAL LWD FORMATION EVALUATION LOGS (04/06/2022 to 04/22/2022) x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: MPU I-29 LWD Subfolders: MPU I-29 Geosteering Subfolders: Please include current contact information if different from above. Revised: PTD: 222-006 T36551 8/22/2023Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.22 12:34:23 -08'00' DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23708-00-00Well Name/No. MILNE PT UNIT I-29Completion Status1-OILCompletion Date4/30/2022Permit to Drill2220060Operator Hilcorp Alaska, LLCMD16538TVD4141Current Status1-OIL8/31/2022UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, DGR, ABG, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF5/3/20226130 16500 Electronic Data Set, Filename: MPU I-29 ADR Quadrants All Curves.las36551EDDigital DataDF5/3/2022150 16538 Electronic Data Set, Filename: MPU I-29 LWD Final.las36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 geosteering plot.emf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 geosteering plot.pdf36551EDDigital DataDF5/3/2022 Electronic File: Hilcorp MPU I-29 Geosteering End of Well Report.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 Post-Well Geosteering X-Section Summary..pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 geosteering plot.tif36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final MD.cgm36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final TVD.cgm36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 Surveys.xlsx36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_Definitive Survey Report.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_Definitive Survey Report.txt36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_GIS.txt36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_Plan.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_VSec.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final MD.emf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final TVD.emf36551EDDigital DataWednesday, August 31, 2022AOGCCPage 1 of 2MPU I-29 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23708-00-00Well Name/No. MILNE PT UNIT I-29Completion Status1-OILCompletion Date4/30/2022Permit to Drill2220060Operator Hilcorp Alaska, LLCMD16538TVD4141Current Status1-OIL8/31/2022UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion 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: 4/30/2022Release Date:1/31/2022DF5/3/2022 Electronic File: MPU I-29_ADR Image.dlis36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29_ADR Image.ver36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final MD.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final TVD.pdf36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final MD.tif36551EDDigital DataDF5/3/2022 Electronic File: MPU I-29 LWD Final TVD.tif36551EDDigital DataWednesday, August 31, 2022AOGCCPage 2 of 2M. Guhl8/31/2022 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 33.7' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-56 150' L-80 1894' L-80 3956' 7" L-80 3949' 5-1/2" L-80 4141' x4-1/2" 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ADL 025906, 025517 & 315848 88-004 1937' / 1768' N/AN/A None 16538' / 4141' Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 5-1/2" x 4-1/2" Screen Liner 4/25/2022 6138' - 7176' 3956' - 3929' 7394' - 7870' 3938' - 3966' 8195' - 10017' 3963' - 4010' 10140' - 12513' 4008' - 4060' 12637' - 13456' 4063' - 4080' 13993' - 14403' 4092' - 4093' 14486' - 16495' 4094' - 4141' Water-Bbl: PRODUCTION TEST Not on Production Date of Test: Flow Tubing 129.5# 47# 150' 2103' 6139' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 40# 5993' 1894' 32' DEPTH SET (MD) 4738' / 3724' PACKER SET (MD/TVD) CASING WT. PER FT.GRADE 26# 549692 551218 TOP SETTING DEPTH MD 33' 32' SETTING DEPTH TVD 6020925 BOTTOM TOP 33' 32' ROP, AGR, DGR, ABG, EWR, ADR MD & TVD HOLE SIZE AMOUNT PULLED 50-029-23708-00-00 MPU I-29 551717 6009443 1848' FNL, 388' FEL, Sec. 32, T13N, R10E, UM, AK CEMENTING RECORD 6010534 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 4/30/2022 2327' FSL, 3654' FEL, Sec. 33, T13N, R10E, UM, AK 2026' FNL, 1236' FWL, Sec. 21, T13N, R10E, UM, AK 222-006 Milne Point Field / Schrader Bluff Oil Pool 67.58' 16538' / 4141' 4/21/2022 4/6/2022 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Driven 20#/13.5# 32' 2103' Stg 1 L - 523 sx / T - 400 sx 8-1/2"5981' 16538' Stg 2 L - 705 sx / T - 270 sx 3948' 6012'4-1/2" 12.6# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 9-5/8"12-1/4" ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Uncemented TiebackTieback TUBING RECORD Uncemented Screen Liner Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 11:16 am, May 13, 2022 Completed 4/30/2022 MDG RBDMS 5/13/2022 MDG GSFD 8/11/2022MGR24AUG2022 DSR-5/13/22 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 36' 36' 1973' 1804' Top of Productive Interval 5960' 3945' 1422' 1355' 2269' 2012' 3972' 3278' 4722' 3717' 5369' 3865' 5541' 3889' 5960' 3945' SB OA 5960' 3945' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Schrader Bluff OA Schrader Bluff NE (Fault) Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top Schrader Bluff NA SV5 SV1 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Ugnu LA3 LOT / FIT Data Sheet, Drilling and Completion Reports, Casing and Cement Report, Definitive Directional Surveys, Wellbore Schematic Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Schrader Bluff OA Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 5.12.2022Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2022.05.12 16:37:17 -08'00' Monty M Myers _____________________________________________________________________________________ Edited By: JNL 5/5/2022 SCHEMATIC Milne Point Unit Well: MPU I-29 Last Completed: 4/30/2022 PTD: 222-006 TD =16,538’(MD) / TD =4,141’(TVD) 4 20” Orig. KB Elev.: 67.58’ / GL Elev.: 33.7’ 7” 5 6 4 99-5/8” 1 2 3 5-1/2” XO 4-1/2” @7870’ See Screen/ Solid Liner Detail PBTD = 16,538’(MD) / PBTD = 4,141’(TVD) 9-5/8” ‘ES’ Cementer @ 2,121’ 4-1/2” Shoe @ 16,538’ 7 8 12 10 4-1/2” 11 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 150’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,103’ 0.0732 9-5/8” Surface 40 / L-80 / TXP 8.835 2,103’ 6,139’ 0.0758 7” Tieback 26 / L-80 / TXP 6.276 Surface 5,993’ 0.0383 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.780 5,981’ 7,870’ 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 7,870’ 16,538’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 6,012’ 0.0152 OPEN HOLE / CEMENT DETAIL 20” Driven 12-1/4"Stg 1 Lead – 523 sx / Tail – 400 sx Stg 2 Lead – 705 sx / Tail 270 sx 8-1/2” Cementless Screened Liner WELL INCLINATION DETAIL KOP @ 176’ 90° Hole Angle = @ 6,178’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23708-00-00 Completion Date: 4/30/2022 JEWELRY DETAIL No. MD Item ID 1 Surface 4-1/2” TCII Tubing Hanger 4.500” 2 4,662’ Baker Gauge Carrier 2.908” 3 4,668’ Haliburton X-Profile Sliding Sleeve (opens down) 2.813” 4 4,674’ Zenith Ported Pressure Sub 2.913” 5 4,738’ Baker Retrievable Premier Packer 3.870” 6 4,810’ XN Nipple, 3.813” Packing Bore, 3.725” No-Go 2.750” 7 5,974’ Mule Shoe Joint – Bottom @6012’ 3.958” 8 5,981’ SLZXP Liner Top Packer 6.190” 9 5,579’ 7” H563 x 5.5” EZGO HT XO 4.810” 10 7,870’ 5-1/2” x 4-1/2” XO 3.920” 11 16,536’ Shoe 3.970” 5-1/2” x 4-1/2”SCREENS LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 24 6138’ 3956’ 7176’ 3929’ 11 7394’ 3938’ 7870’ 3966’ 45 8195’ 3963’ 10017’ 4010’ 58 10140’ 4008’ 12513’ 4060’ 20 12637’ 4063’ 13456’ 4080’ 10 13993’ 4092’ 14403’ 4093’ 49 14486’ 4094’ 16495’ 4141’ CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-29 Date:4/14/2020 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Demoski/Vanderpool Csg Setting Depth:6139 TMD 3957 TVD Mud Weight:9.3 ppg LOT / FIT Press =556 psi . LOT / FIT =12.00 ppg Hole Depth =6170 md Fluid Pumped=1.7 Bbls Volume Back =0.9 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->258 ->4253 ->482 ->8551 ->6 141 ->12 746 ->8 210 ->16 949 ->9 237 ->20 1156 ->10 263 ->24 1368 ->11 311 ->28 1622 ->12 346 ->32 1852 ->13 381 ->36 2118 ->14 428 ->40 2361 ->15 465 ->44 2648 ->16 502 ->45 2676 ->17 556 -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 556 ->0 2676 ->1 532 ->5 2663 ->2 527 ->10 2654 ->3 524 ->15 2647 ->4 521 ->20 2641 ->5 514 ->25 2634 ->6 507 ->26 2633 ->7 500 ->27 2632 ->8 494 ->28 2631 ->9 488 ->29 2630 ->10 481 ->30 2629 ->11 475 -> ->12 470 -> ->13 464 -> ->14 458 ->15 454 -> 0 2 4 6 8 9 10 111213 141516 17 0 4 8 12 16 20 24 28 32 36 40 4445 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 1020304050Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA Pressure (psi) 556532527524521514507500494488481475470464458454 2676 2663 2654 2647 2641 263426332632263126302629 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 4/6/2022 Move fluid around to each pit function testing the PVT system. Test flow line sensor. All good. PJSM. PU and MU conductor cleanout BHA (tricone, motor & crossover). Fill the stack with water and check for leaks (all good). Prep the pits to take on spud mud. Use super sucker to empty water from pits 1 & 2. Load pits 1 & 2 with 290 bbls of 8.8 ppg spud mud. Continue to fill the pits with 580 bbls of 8.7 ppg spud mud. Pre-spud meeting with all parties involved. Discussed well objectives and surface hole hazards. Table top diverter drill - discussed all roles and responsibilities. Reviewed safe briefing areas and emergency notification. Circulate and warm up lines, test mud lines and geo span to 250/3500 psi, good. Tag ice at 37'. Cleanout 20'' conductor to 114' utilizing fresh water, 400 GPM, 290 PSI, 30 RPM, 1K TQ, 2-4K WOB. 50K PU / 50K SO / 50K ROT. Displace water w/ 8.7 ppg spud mud, 180 GPM, 160 PSI. Drill 12-1/4" surface hole from 114' to 218' MD / 218' TVD, 104' drilled, 104'/hr AROP. 400 GPM, 400 PSI, 30 RPM, 2K ft/lbs TQ, 3-8K WOB. 55K PU / 55K SO / 55K ROT. 8.7 ppg MW, 300 vis. Circulate hole clean, 400 GPM, 365 PSI, 30 RPM, 1K TQ. POOH rack back 2 stands HWDP f/ 218' t/ 35'. Inspect bit, found carbide tool and shank from conductor auger lodged in cones of cleanout bit. Clean and clear rig floor. MU 12-1/4" Kymera bit, motor, GyroWhileDrilling, directional, gamma and resistivity and flex collar to 129'. Initialize MWD tools. Attempt to PU 2nd flex collar but stacked out at 138' three times. LD collar, make up stand HWDP then wash down with 270 GPM, 320 PSI - nothing observed. Rack back stand, MU flex collar, XO sub and stand of HWDP. Encountered fill at 205'. Wash down without difficulty. Obtain gyro survey @ 176'. Drill 12-1/4" surface hole from 218' to 1,005' (974' TVD). Drilled 787' = 112'/hr AROP. 540 GPM = 1,430 psi, 60 RPM = 3-5K ft/lbs torque, WOB = 5-7K, PU = 85K, SO = 82K, ROT = 85K. MW = 8.9+ ppg, Vis = 195, ECD = 10.0 ppg, max gas = N/A Last Gyro at 776' and first clean MWD at 858'. Released Gyro at 1,000'. Drill 12-1/4" surface hole from 1,005' to 1,525' (1449' TVD). Drilled 520' = 87'/hr AROP. 530 GPM = 1,490 psi, 90 RPM = 3-5K ft/lbs torque, WOB = 5-15K, PU = 85K, SO = 87K, ROT = 88K. MW = 9.1+ ppg, Vis = 111, ECD = 10.2 ppg, max gas = 393. Last survey at 1429.12' MD / 1361.56' TVD, 25.23° INC, 238.74° AZM, Distance from WP10 = 27.72', 18.66' high, 20.49' left. Daily disposal to G&I = 161 bbls. Total disposal to G&I = 218 bbls. Daily water hauled from L-Pad Lake = 65 bbls. Total water hauled from L-Pad Lake = 535bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/7/2022 Drill 12-1/4" surface hole from 1,525' to 2,240' (1,991' TVD). Drilled 715' = 119.2'/hr AROP. 550 GPM = 1,700 psi, 70 RPM = 4K ft/lbs torque, WOB = 1-15K, PU = 105K, SO = 90K, ROT = 98K. MW = 9.3+ ppg, Vis = 114, ECD = 10.8 ppg, max gas units = 433. Logged the base of permafrost at 1,973’ MD / 1,804’ TVD. Began 44.49° tangent at 2,009’ Drill 12-1/4" surface hole from 2,240' to 3,124' (2,705' TVD). Drilled 884' = 147.3'/hr AROP. 545 GPM = 1,850 psi, 80 RPM = 5-7K ft/lbs torque, WOB = 1-5K, PU = 125K, SO = 95K, ROT = 110K. MW = 9.2+ ppg, Vis = 110, ECD = 10.8 ppg, max gas units = 1,005. Pump 20 bbl hi vis sweep at 2339', back 250 stks late with no increase in cuttings. Begin 4.5°/100’ build and turn at 2,974’ with 50’ to 70’ slides per stand. Spot cement silos & Halliburton began loading cement. Drill 12-1/4" surface hole from 3,124' to 3,956' (3,268' TVD). Drilled 832' = 138.7'/hr AROP. 532 GPM = 1,940 psi, 80 RPM = 10K ft/lbs torque, WOB = 0-20K, PU = 150K, SO = 105K, ROT = 125K. MW = 9.3+ ppg, Vis = 120, ECD = 10.5 ppg, max gas units = 480 Drill 12-1/4" surface hole from 3,956' to 4,560' (3,641' TVD). Drilled 604' = 100.7'/hr AROP. 550 GPM = 1,660 psi, 80 RPM = 10K ft/lbs torque, WOB = 5-12K, PU = 160K, SO = 105K, ROT = 125K. MW = 9.0 ppg, Vis = 117, ECD = 10.3 ppg, max gas units = 2,331 Last survey at 4,473.28' MD / 3,594.29' TVD, 55.72° INC, 339.83° AZM, Distance from WP10 = 15.27', 12.00' high, 9.00' left Daily disposal to G&I = 1112 bbls Total disposal to G&I = 1482 bbls. Daily water hauled from L-Pad Lake = 715 bbls. Total water hauled from L-Pad Lake = 1250 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/8/2022 Drill 12-1/4" surface hole from 4,560' to 5,002' (3,816' TVD). Drilled 442' = 73.67'/hr AROP. 550 GPM = 1,910 psi, 80 RPM = 10-13K ft/lbs torque, WOB = 12K, PU = 170K, SO = 110K, ROT = 128K. MW = 9.3 ppg, Vis = 100, ECD = 10.3 ppg, max gas units = 1,313. Logged SB NA sand at 4,722' MD / 3,718' TVD. Pumped 20 bbl hi vis sweep at 4,725' - not seen. Drill 12-1/4" surface hole from 5,002' to 5,383' (3,866' TVD). Drilled 381' = 84.67'/hr AROP. 548 GPM = 2,190 psi, 80 RPM = 12-14K ft/lbs torque, WOB = 15-20K, PU = 160K, SO = 100K, ROT = 120K. MW = 9.4 ppg, Vis = 90, ECD = 10.9 ppg, max gas units = 560 When the pumps were shut down for a connection, the pits gained 25 bbls volume from lines flowing back. With the pits nearly full, this caused pit #1 to overflow to containment in the wheel well. An estimated 112 gallons filled containment and 15 gallons leaked to the pad. Stopped drilling, notified Milne security, secured the area and lowered the pit volume by transferring mud to pit #5. ACS contacted pusher and allowed rig to clean up mud. Verify PVT volume vs. strap volume - good. Set PVT high alarm at 75% and high high alarm at 80%. Drill 12-1/4" surface hole from 5,383' to 5,668' (3,904' TVD). Drilled 285' = 63.33'/hr AROP. 548 GPM = 1,700 psi, 80 RPM = 14- 17K ft/lbs torque, WOB = 15-30K, PU = 171K, SO = 95K, ROT = 115K. MW = 9.4+ ppg, Vis = 87, ECD = 10.6 ppg, max gas units = 932. Crossed Fault A at 5,541' from the OA sand to NE clay. As we finished drilling the stand down the hole started to unload cutting. As we continued to circulate our pump pressure decreased from 1,800 psi to 1,030 psi. Trouble shoot loss of pump pressure. Individually PT both MP 1 & 2 to 2,500 psi (both good). MWD also observed a loss in impellor RPM. Each time we brought the pumps up to drilling rate of 550 GPM our pump pressure continued to decline. It appears that there is a washout somewhere downhole. Discuss with Drilling Engineer and decision was made to TOOH looking for the washout. Attempt to TOOH on elevators but unable to. BROOH from 5,668' to washout at 4,973'. RIH to 5,002' and lay down 3 joints to 4,907'. 4/9/2022 Circulate the hole clean at 4,907' with 500 GPM, 1910 PSI ICP, 1630 PSI FCP, 50 RPM, 12K TQ. Reciprocate from 4,907' t/ 4,814'. Perform flow check - static. TIH f/ 4,907' t/ 5,573' then wash down f/ 5,573' t/ 5,668' with 550 GPM, 1925 PSI, 70 RPM, 11K TQ. Drill 12-1/4" hole from 5,668' to 5,978' (3,949' TVD). Drilled 310' = 88.57'/hr AROP. 550 GPM = 2,400 psi, 80 RPM = 15K ft/lbs torque, WOB = 22K, PU = 175K, SO = 100K, ROT = 125K. MW = 9.4 ppg, Vis = 77, ECD = 10.7 ppg, max gas units = 478. Entered SB OA sand at 5,960' MD / 3,945' TVD Drill 12-1/4" hole from 5,978' to TD of surface hole at 6,150' (3,957' TVD). Drilled 172' = 86'/hr AROP. 540 GPM = 2,390 psi, 80 RPM = 12-15K ft/lbs torque, WOB = 20K, PU = 175K, SO = 100K, ROT = 125K. MW = 9.4 ppg, Vis = 50, ECD = 10.5 ppg, max gas units = 1498 Obtain final MWD survey and downlink gyro tool into out run mode. Pump out from 6,150' to 5,954'. Pump 40 bbl hi vis sweep, back 250 stks late with 25% increase at 550 GPM, 1920 PSI ICP / 1730 PSI FCP, 80 RPM, 13K TQ. Reciprocate from 5,954' to 5,858'. TIH from 5,954' to 6,150'. Flow check - static. Final survey at 6096.56’ MD / 3955.93’ TVD, 88.92° inc, 0.81° azm, 2.88’ from plan, 2.58’ low and 1.29’ left. BROOH from 6,150' to 3,861' with 550 GPM, 1350 PSI, 80 RPM, 14K TQ at 5-15'/minute. Slowing down as needed to cleanup slides/tight spots. Continue to BROOH from 3,861' to 3,350' with 550 GPM, 1750 PSI, 80 RPM, 14K TQ at 5-15'/minute. Slowing down as needed to cleanup slides/tight spots. The top drive threw a fault code and unable to rotate. Call out electrician to troubleshoot. Reset and top drive started working. Top drive house overheated. Turn off the pumps/rotary. TIH to 3,372'. Continue to BROOH from 3,372' to 2620' with 550 GPM, 1350 PSI, 80 RPM, 14K TQ at 5-15'/minute. Slowing down as needed to cleanup slides/tight spots. Daily disposal to G&I = 1048 bbls. Total disposal to G&I = 3304 bbls. Daily water hauled from L-Pad Lake = 627 bbls. Total water hauled from L-Pad Lake = 1971bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 50-029-23708-00-00API #: Well Name: Field: County/State: MP I-29 Milne Point Hilcorp Energy Company Composite Report , Alaska 4/6/2022Spud Date: 4/10/2022 Continue to BROOH from 2620' to 2053' with 550 GPM, 1350 PSI, 80 RPM, 14K TQ, 110K PU at 5-15'/minute. Slowing down as needed to cleanup slides/tight spots Circulate a bottoms up while reaming from 2053' to 1958', 550 GPM, 1200 PSI, 80 RPM, 10K TQ. No increase in cuttings observed. Added 3#/bbl gel to increase YP from 19 to 23 through the permafrost. BROOH from 1958' to 722', 550 GPM, 1160 PSI, 80 RPM, 5-10K TQ, 80K PU. Slowing down as needed to cleanup slides/tight spots. Pull slow from 912' to 722' to circulate 2x bottoms up with 25% increase in sand over the shakers. Rack back HWDP & jars from 722' to 162'. Pulled 2 stands with no swabbing then blew down the top drive. L/D two 8" flex drill collars to 98'. Plug in and read MWD tools - 100% data recovery. L/D BHA from 98'. In-Line Stabilizer was 50% worn prior to run and 80% worn post run from back reaming. Motor stabilizer was repaired prior to run and fully worn post run. Bit Grade: PCD cutters - 2-2-BF-C-X-I-WT-TD / cones - 1-1-WT-A-F-I-NO-TD Clean and clear rig floor. RU Volant casing running tool. RU to run 9-5/8" casing. PJSM. PU and MU the 9-5/8" shoe track using Baker Lok on each connection: Round nose float shoe, 1 joints and FC joint. Fill the shoe track and install the top hat. MU the baffle adapter joint. Pump through the float and ensure proper operations (good). Torque to 21,000 ft/lbs with the Volant tool. Installing centralizers per tally. RIH with 9-5/8", 40#, L-80 TXP-BTC casing from 166' to 2,199' (BPF at 1,973') PU = 142K & SO = 85K. Torque to 21,000 ft/lbs with the Volant tool. Installing centralizers per tally. Filling the casing on the fly topping off every 10 joints. CBU: Stage the pumps up to 6 BPM = 125 psi slowly reciprocating pipe 40' (2,199' to 2,238'). Continue to RIH with 9-5/8", 40#, L-80 TXP-BTC casing from 2,238' to 3,077'. Torque to 21,000 ft/lbs with the Volant tool. Installing centralizers per tally. Filling the casing on the fly topping off every 10 joints. Daily disposal to G&I = 629 bbls. Total disposal to G&I = 3933 bbls. Daily water hauled from L-Pad Lake = 490 bbls. Total water hauled from L-Pad Lake = 2461 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/11/2022 Continue to RIH with 9-5/8", 40#, L-80 TXP-BTC casing from 3,077' to 4,236'. Torque to 21,000 ft/lbs with the Volant tool. Installed ES cementer at 3998' between joint #99 & #100. Run 47# casing from 4,036, torque to 24,000 ft/lbs with the Volant tool. Installing centralizers per tally. Filling casing on the fly and topping off every 10 joints. CBU before final build and turn. Stage up pumps to 6 BPM, 200 PSI. Reciprocate pipe 40' from 4,236' to 4,198'. 220K PU / 130K SO. Continue to RIH with 9-5/8", 47#, L-80 TXP-BTC casing from 4,236' to 5,218'. Torque to 24,000 ft/lbs with the Volant tool. Installing centralizers per tally. Filling casing on the fly and topping off every 10 joints. While making up the connection between joint #128 & 129, began to see torque 6 turns into it. Back out and observe threads galled. L/D joint #129 due to galled threads, but able to dress box on #128. P/U replacement joint and torque to 24,000 ft/lbs without issue. Continue to RIH with 9- 5/8", 47#, L-80 TXP-BTC casing from 5,218' to 6,082'. Precautionary wash down from 6,082' to 6,139' at 6 BPM, 320 PSI. Torque to 24,000 ft/lbs with the Volant tool. Installing centralizers per tally. Filling casing on the fly and topping off every 10 joints. 62 bbls total lost while running casing. 89.7 bbls calculated displacement. Circulate and condition for cement job. 6 BPM, 200 PSI, 2 RPM, 20K TQ. 320K breakover, 295K PU / 123K SO. Only able to rotate while reciprocating the casing string otherwise stall at 20K torque limit. Reciprocate 30' f/ 6,139' t/ 6,109'. 30 bbls lost during circulation. Shut down, break out the Volant tool, re-dope cup and blow down top drive. Make back up to casing. Rig up cement lines. Close upper and lower IBOP. Continue to circulate at 6 BPM, 200 PSI while holding PJSM. *** Provided BOP test notification to the AOGCC at 17:29 *** Continue to circulate at 6 BPM = 200 psi rotating at 2 RPM = 20K ft/lbs and reciprocating 20'. Mix black water pills. Blow air down to the cement unit. PJSM for 1st stage cement job. Continue to circulate at 6 BPM while rotating and reciprocating. HES filled lines with 5 bbls fresh water. Attempt PT surface lines to 1,000/4,000 psi. Low PT passed but the block valve is not holding at high pressure. Add second block valve but both are leaking at high pressure. Grease the block valves and still not holding. Pump 1st stage cement job: Pump 60 bbls of 10 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 3 BPM, 250 PSI. Drop bypass plug. Mix and pump 219 bbls of 12.0 ppg lead cement (Type I/II cement, 2.347 ft^3/sk yield, 523 sks) at 5 BMP = 300 psi Mix & pump 82 bbls 15.8 ppg tail cement (premium G cement 1.156 ft^3/sk yield, 400 sks) at 5 BPM = 330 psi. Drop the shutoff plug. Pump 20 bbls of fresh water with HEH at 5 BPM = 220 PSI. With the rig pumps displace with 264.9 bbls of 9.4 ppg mud at 7 BPM = 250 psi. At 2540 strokes caught up to the cement 7 BPM = 400 psi. HES pumped 80 bbls 9.4 ppg tuned spacer at 5 BPM = 450 psi. With the rig pumps continue to displace with 85.6 bbls 9.4 ppg mud at 6 BPM = 750 psi. Rotated and reciprocated until the last 15 bbls then slowed the rate to 3 BPM = 550 psi. The plug did not bump on calculated strokes. Pump an additional 6 bbls (half the shoe track + half the spacer joint) and still did not bump. Called and discussed with the drilling Engineer. Pumped an additional 3 bbls and still did not bump. Break out the Volant, check the floats and the floats are holding. Drop the free fall opening plug. Cement in place at 23:54 hours. Casing set on depth at 6,139'. Allow the time for the opening plug to fall. Bring the pumps on and started pressuring up. ES cementer opened in 7 strokes at 500 psi. Continue to circulate through the ES cementer at 6 BPM = 200 psi. Observed thick clabbered mud at 1,660 strokes and then cement. Started taking returns to the pits at 3853 strokes. Dumped 67 bbls cement and 195 bbls interface to the rock washer. Disconnect the knife valve accumulator lines. Drain and flush the stack with black water. Function and flush the annular 3 times with black water. Reconnect the knife valve accumulator lines. Continue to circulate through the ES cementer at 6 BPM =200 psi while WOC, hauling off mud/cement and prepping for the second stage cement job. Daily disposal to G&I = 779 bbls. Total disposal to G&I = 4712 bbls. Daily water hauled from L-Pad Lake = 510 bbls. Total water hauled from L-Pad Lake = 2971 bbls. Daily fluid loss = 132 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/12/2022 Continue to circulate through ES cementer at 2121' at 6 BPM, 190 PSI while preparing for 2nd stage cement job. Hold PJSM with all parties involved. Break out Volant tool, inspect dies and dope cup. C/O 2" block valves. Blow air through cement lines. Pump 5 bbls water. Pressure test lines to 1400 PSI low / 4200 PSI high. Mix and pump 60 bbls 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls. at 3 BPM, 125 PSI. Mix and pump 362 bbls 10.7 ppg ArcticCem lead cement, 705 sks (2.883 ft^3/sk yield) at 4.5 BPM, 330 PSI. Dump returns at 161 bbls lead cement pumped. 10# spacer back at 185 bbls lead cement pumped. Observed 10.4 ppg cement back, swap to tail cement. Mix & pump 56 bbls 15.8 ppg tail cement, 270 sks (1.17 ft^3/sk yield) at 3 BPM, 295 PSI. Observed good 10.7 ppg cement back at 28 bbls tail cement pumped. Shut down, back out Volant and load closing plug. M/U Volant. Displace with 9.4 ppg spud mud from rig at 6 BPM, 170 PSI ICP / 610 PSI FCP. Slow to 3 BPM, 510 PSI for last 10 bbls. Plug bumped @ 1328 strokes, 1.4 bbls early. Pressure up & observe ES cementer close at 1510 PSI, continue up to 1700 PSI. Bleed off pressure, check for flow - static. CIP at 12:26. 60 bbls spacer back, 85 bbls interface and 182 bbls of good cement back to surface. 100% returns during cement job. Drain cement from stack. Disconnect knife valve accumulator lines. Flush diverter stack with black water and function diverter 3x flushing with black water. R/D Volant tool. Vacuum out fluid from casing joint. Remove grub screws from speed head. Hoist diverter stack 3'. PU 140K indicated on casing string. Wellhead rep install casing slips then set casing with 100K on slips. Cut casing as per wellhead rep. LD 16.91' cut joint. ND diverter stack and set back in the cellar. Mobilize the slip lock casing head and tubing spool into the cellar. Warm up both with steam. NU the slip lock casing head. PT the void to 500 psi for 5 minutes and 3,800 psi for 10 minutes (good test). Install the tubing spool on top the casing head. Simops: Clear the rig floor on casing running equipment. NU the MPD orbital valve onto the rotating head. Remove the diverter T from the cellar. NU the BOP stack. Simops: Mobilize test plug and wear ring to the rig floor. Set rig mat for MPD skid. Load, strap and tally 5" DP. Daily disposal to G&I = 1821 bbls. Total disposal to G&I = 6533 bbls. Daily water hauled from L-Pad Lake = 185 bbls. Total water hauled from L-Pad Lake = 3156 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. The plug did not bump on calculated strokes. Pump an additional 6 bbls (half the shoe track + half the spacer joint) and still did not bump. Called and discussed with the drilling Engineer. Pumped an additional 3 bbls and still did not bump. B 4/13/2022 Change upper rams. PJSM. Remove 5.5" solid rams and install 4.5" x 7" VBR. Mobilize MPD trip nipple & test plug to the rig floor. Orient MPD head to align orbit valve and install 90° elbow then torque down MPD head. Torque MPD flanged connections to orbit valve. Sim-ops: prepare BOP test equipment and install test plug. Install MPD test cap. Fill BOP stack with water. Pressure test MPD head to 1500 PSI for 5 min - good. Remove test cap and install trip nipple. Trip nipple too short. Obtain new measurement required and L/D trip nipple for modification. R/U to test BOPs. Notified AOGCC at 05:28 on 11 April and inspector Adam Earl waived witness at 20:08 on 11 April. Install 4-1/2" test joint and R/U test equipment. Fill choke manifold and purge air from system. Test BOPE to 250 PSI low / 3000 PSI high. Tests held for 5 min each & charted. All tests performed with fresh water against test plug. 1. Annular on 4.5” test joint, choke valves 1, 12, 13, 14 & Kill Demco. 2. Upper 4.5”x7” VBR on 4.5” test joint, choke valves 9 & 11, Kill & upper IBOP 3. Choke valves 5, 8 & 10, Manual kill & Lower IBOP. 4. Choke valves 4, 6, 7 & 5” Dart Valve. 5. Choke valve 2 & 5” FOSV. 6. Lower 2.875”x5” VBR on 4.5” test joint. 7. Manual choke 8. Lower 2.875”x5” VBR on 5” test joint. 9. Upper 4.5”x7” VBR on 7” test joint, HCR choke. 10. Blind rams & Choke valve 3. 11. Hyd, Super Choke A. 12. Manual Super Choke B Perform Accumulator test: 3000 psi sys pressure, 1600 psi after closure, 200 psi recovery in 44 sec, full recovery in 204 sec, 6 N2 bottle avg = 2150 PSI. Rig electrician tested rig gas alarms. Bag close in 15 sec, UPR close in 7 sec, LPR close in 7 sec, HCR’s close in 2 sec/ea. R/D test equip, Pull test plug & L/D test jt. blow down choke manifold and lines. Locate 16" air boots, make up and Install trip nipple assembly with welded extension. P/U test jt & M/U running tool. Install 9-1/8" ID wear bushing. Pull trip nipple and C/O air boot with a damaged air fitting. Rig up 5" handling equipment, dress rig tongs for BHA. Hold PJSM, Make up 8-1/2" clean-out assembly. Smith XR+CPS Tri-Cone bit, 6-3/4" strataforce 6/7 - 6 stg motor. Daily disposal to G&I = 171 bbls. Total disposal to G&I = 6704 bbls. Daily water hauled from L-Pad Lake = 0 bbls. Total water hauled from L-Pad Lake = 3156 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/14/2022 TIH with 8-1/2" cleanout BHA from 32' with HWDP & jars out of the derrick to 591'. Single in the hole with 5" drill pipe (3.18" drift) from 591' to 2,018'. 75K SO. Wash down with stands from the derrick from 2,018' and tagged cement at 2,114' with 115 GPM, 260 PSI. Drill cement from 2114' with 460 GPM, 970 PSI, 30 RPM, 4-5K TQ, 5-10K WOB. Drilled ES cementer on depth @ 2,121'. Continue to wash down to 2,143'. Ream ES cementer 2x times. Slack off through clean. Set down at 2,143', suspect ES cementer retaining collar. Drilled with 460 GPM, 970 PSI, 30 RPM, 4-5K TQ, 0-2K WOB and broke through at 2,143'. Ream to 2,150'. P/U to 2,130' then S/O to 2,190' without problem. Blow down top drive. Rack back two stands to 2,018' Single in the hole with 5" drill pipe (3.18" drift) from 2,018'. Tagged cement high at 5858' with 15K, plug did not bump during cement job. Fill pipe and confirm cement at 5858'. 215K PU / 77K SO. CBU at 450 GPM, 900 PSI, 30 RPM, 15K TQ, reciprocate pipe 90'. L/D single joint of drill pipe, rig up test equipment and fill choke and kill line with mud. Close 4-1/2" x 7" VBR on 5" drill pipe. Pressure test casing to 2500 PSI for 30 min on chart. Bleed off pressure and R/D test equipment. Drill cement f/ 5858' t/ 6000'. 500 GPM, 1500 psi. 30 RPM, 15k Tq. PUW 225k , SOW 85k , ROT 107k Circulate 1.5x bottoms up at 6000' until mud returns clean up, 500 GPM, 1450 PSI, 30 RPM, 16k Tq. Reciprocate 90' Blow down top drive & rig up test equipment. Close upper 4-1/2"x7" VBR on 5" drill pipe. Pump down drill pipe and kill line. Pressure test 9-5/8" casing to 2500 PSI for 30 min on chart - good. 4.5 bbls pumped, 4.5 bbls bled back. R/D test equipment and blow down lines. Service and inspect TD, Blocks Drwks and Roughneck. Drill Baffle adaptor, Float Collar & Shoe, tag all equip 5' deep. Good cmt through shoe track - 500 GPM, 1200 PSI, 40 RPM, 16k Tq, 3-8k WOB. Reamed float equip 2x & slack off w/o drag. Drill rat hole out t/ 6150’. Drill 20' New hole F/ 6150' T/ 6170'. 5-12k WOB, 40 RPM, 16k Tq, 500 GPM, 1200 PSi. Ream through shoe 3x dressing shoe clean while CBU – 500 GPM - 1200 psi, 40 RPM – 12k Tq. Even 9.3 ppg mud wt in/out. Work through shoe with no rotary/pumps – no drag observed. PUW 230k, SOW 75k, ROT 130k Blow down top drive & rig up test equipment. Close upper 4-1/2"x7" VBR on 5" drill pipe. Purge air from system. Daily disposal to G&I = 143 bbls. Total disposal to G&I = 6847 bbls. Daily water hauled from L-Pad Lake = 40 bbls. Total water hauled from L-Pad Lake = 3196 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/15/2022 Perform 12.0 ppg FIT at 6139' MD / 3957' TVD with 9.3 ppg mud. Close upper pipe rams on 5" drill pipe and pump down kill line and drill pipe. Pressure up to 556 PSI at surface. Pumped 1.7 bbls, bled back 0.9 bbls. Blow down lines and R/D test equipment. AOGCC gave approval to proceed at 07:12 based upon FIT test results. Pump 16 bbl 10.6 ppg dry job. Blow down top drive. POOH from 6,109' to 591'. 115K PU / 75K SO. Observe metal to metal drag, slow pulling speed due to excessive vibration of rig. Lay down 15 joints of HWDP and rack back stand with jars. L/D mud motor and bit. Bit graded 1-1-WT-A-E-1-NO-TD. No losses on the trip out. Clean and clear rig floor. Remove master bushing and install split bushings for MPD. Mobilize BHA components to the rig floor. PJSM. M/U 8-1/2" NOV TK66 bit, NRP-A2 bit sleeve, 7600 Geo-Pilot, MWD ADR, DGR, PWD, directional tools, stabilizer and float sub to 94'. Plug in and initialize MWD tools. SimOps: Test MPD lines t/ 1250 psi - Good. TIH 2 NM flex collars, float sub, HWDP & jars to 283'. Pulse test MWD 450 GPM, 790 PSI - good. Break in RSS Seals. Single in the hole with 5" drill pipe from the pipe shed f/ 283' t/ 5232'. RIH with stand f/ Derrick to 6087’. Fill pipe every 20 stands. PUW 217k, SOW 85k PJSM. Remove trip nipple and install MPD RCD. Flood lines and flow through MPD chokes. M/U stand of drill pipe and RIH to 6170'. Pull back to shoe and hold PJSM for displacement. Remove air blockage from gas monitor. Pump 30 bbls 9.3 ppg spud mud @ 6 BPM, 500 psi dump returns to rockwasher reducing volume in pit. Start pump 8.8 ppg Spacer pill from pill pit, 4.5 BPM, 385 psi. Daily disposal to G&I = 114 bbls. Total disposal to G&I = 6961 bbls. Daily water hauled from L-Pad Lake = 65 bbls. Total water hauled from L-Pad Lake = 3261 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 0 lbs. 4/16/2022 Displace wellbore with 8.9 ppg BaraDrill-N, 275 GPM, 580 PSI, 40 RPM, 15K TQ, once new mud in open hole reciprocate from 6130' to 6085'. Dumped spacer + 80 bbls of interface. Close MPD chokes and monitor pressure for 15 min. - no pressure observed. Blow down top drive and MPD lines. PJSM. Slip and cut 80' of drilling line. Add hydraulic and gear oil to top drive. Inspect saver sub - threads good. Sim-ops: Clean trip tank, pit #4 and pill pit. Slow pump rates. Perform pump efficiency test: #1 pump 10.0 bbls @ 3.0 BPM, 200 PSI (35 PSI on charge pump), 10.0 bbls returned to trip tank. #2 pump 10.0 bbls @3.0 BPM, 200 PSI (35 PSI on charge pump), 10.5 bbls returned to trip tank. Wash down f/ 6,085' t/ 6,170', 450 GPM, 900 PSI, 45 RPM, 13K TQ Drill 8-1/2" lateral f/ 6170' t/ 6609' (3949’ TVD) 439' drilled, 73'/hr AROP. 450 GPM, 1020 PSI, 80 RPM, 15K TQ, 5-15K WOB. 9.1 ppg MW, 40 vis, 9.9 ECD, max gas 1289u. 192K PU / 40K SO / 120K ROT. Initially target 91° inc., increased to 92°. Drilling with MPD chokes open, close on connection to monitor pressure -no pressure. Began adding 1% lube at 6,465'. Drill 8-1/2" lateral f/ 6609' t/ 7216' (3927’ TVD) 607' drilled, 101'/hr AROP. 500 GPM, 1350 psi, 120 RPM, 18k Tq, 5-15k WOB. 9.2 ppg MW, 40 vis, 10.2 ECD, max gas 3403u. 225k PU / 40k SO / 115k ROT. Increase lube to 2%. Pump 34 bbls Hi-Vis sweep @ 7066'. 430 stks late with 0% increase Target 92°. Crossed Fault #1 at 7,157’ MD/ 3,928’ TVD. 20' throw DTN, moved the bit from lower OA-1 to the NF Shale above OA Sand. Adjust target to 86° for re-entry to OA package. At 7050’ MD, connection gas increase to 3400u. Start holding 160psi on conn. 100 psi drilling. Drill 8-1/2" lateral f/ 7216' t/ 7703' (3980’ TVD) 487' drilled, 81'/hr AROP. 500 GPM, 1450 psi, 120 RPM, 19k Tq, 5-15k WOB. 9.1 ppg MW, 41 vis, 10.69 ECD, max gas 3479u. 223k PU / 40k SO / 118k ROT. MPD holding 200 psi on conn. 100 psi drilling. Re-enter top of OA1 @ 7413’ MD / 3839’ TVD. Hold 87° targeting the OA3 sand. Total of 256’ drilled above the OA package. MBTs @ 7.5 ppb, dump and dilute 200 bbls whole mud @ 7620' MD Last survey at 7634.89’ MD / 3952.49' TVD, 86.97° inc, 4.50° azm, 22.65’ from plan, 15.24' high and 16.70’ left. We have drilled 12 concretions for a total thickness of 66' (4.3% of the lateral). Daily disposal to G&I = 865 bbls. Total disposal to G&I = 7826 bbls. Daily water hauled from L-Pad Lake = 180 bbls. Total water hauled from L-Pad Lake = 3441 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 10 lbs. Total metal recovered = 10 lbs. Pressure test casing to 2500 PSI for 30 min on chart. Bleed off pressure and R/D test equipment. Drill cement f/ 5858' t/6000'. 500 / Tagged cement high at 5858' with 15K, plug did not bump during cement job. 4/17/2022 Drill 8-1/2" lateral f/ 7,703' t/ 8,335', 632' drilled, 105.33'/hr AROP. 500 GPM, 1540 PSI, 120 RPM, 18K TQ, 11K WOB. 225K PU / no SO / 120K ROT. 9.1. MW, 41 vis, 10.93 ECD, 1455u max gas. Pumped hi-vis sweep at 8084', 350 strokes late, 50% increase. Encountered fault #2 at 7,730', 9' DTS throw. Drilled out the bottom of OA-3 from 7853' to 8241', 388' drilled out of zone. Backream 30' on connections. MPD hold 60 PSI while drilling and 300 PSI on connections. Drill 8-1/2" lateral f/ 8,335' t/ 8,767', 432' drilled, 72'/hr AROP. 500 GPM, 1660 PSI, 120 RPM, 21K TQ, 5-15K WOB. 250K PU / no SO / 112K ROT. 9.2 ppg MW, 41 vis, 10.9 ECD, 2381u max gas. Backream 30' on connections. MPD hold 60 PSI while drilling and 300 PSI on connections. Backreamed full stands at 8465' and 8560'. Observed 100% increase in sand at 8550'. Pumped low-vis sweep at 8655', could not identify it coming back but saw 50% increase in sand. Began increasing BaraLube Gold Seal to 3%. Drop MBT from 8.0 to 6.5 w/ both centrifuges and 200 mesh shaker screens. Drill 8-1/2" lateral f/ 8767' t/ 9239', 472' drilled, 79'/hr AROP. 500 GPM, 1720 PSI, 120 RPM, 20K TQ, 5-15K WOB. 225K PU / no SO / 110K ROT. 9.2 ppg MW, 44 vis, 11.1 ECD, 1525u max gas. Backream 30' on connections. MPD hold 60 PSI while drilling and 300 PSI on connections. Pumped hi-vis sweep at 9036', return at calc stks, 30% increase Drill 8-1/2" lateral f/ 9239' t/ 9701', 462' drilled, 103'/hr AROP. 500 GPM, 1730 PSI, 120 RPM, 20K TQ, 5-15K WOB. 225K PU / no SO / 110K ROT. 9.1 ppg MW, 42 vis, 10.96 ECD, 1549u max gas. Backream 30' on connections. MPD hold 60 PSI while drilling and 300 PSI on connections. Pumped low-vis sweep at 9414', was not recognized at surface. MBT’s @ 8.5 ppb, perform 200 bbls whole mud dump and dilute @ 9512’. Reduced MBT's to 7 ppb. Kelly down @ 9701’, Top Drive wash pipe swivel packing leaking. Greased packing and still leaking. Rack stand back and line up MPD to circulate across top, through injection line. Hold 370 psi while change out swivel packing. Last survey at 9537.28’ MD / 3993.94' TVD, 85.98° inc, 8.99° azm, 13.49’ from plan, 10.76' high and 8.14’ left. We have drilled 20 concretions for a total thickness of 162' (4.5% of the lateral). Daily disposal to G&I = 862 bbls. Total disposal to G&I = 8688 bbls. Daily water hauled from L-Pad Lake = 770 bbls. Total water hauled from L-Pad Lake = 4211 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 4 lbs. Total metal recovered = 14 lbs. 4/18/2022 C/O swivel packing. Check new swivel packing with 500 GPM, 1750 PSI, 50 RPM, 19K TQ - holding good. MPD circulate across top, through injection line, hold 370 psi while change out swivel packing. Blow down injection line. Drill 8-1/2" production lateral from 9,701' to 10,083', 500 GPM, 1770 PSI, 120 RPM, 22k TQ, 5- 15K WOB. 9.1 ppg MW, 43 vis, 11.04 ECD, 240K PU / no SO / 121K ROT, max gas 1791u. Pumped hi-vis sweep at 9,987', back on time with 25% increase. MPD holding 100 PSI while drilling & 320 PSI on connections. Drill 8-1/2" production lateral from 10,083' to 10,749', 500 GPM, 1820 PSI, 120 RPM, 23k TQ, 5-15K WOB. 9.2 ppg MW, 42 vis, 11.10 ECD, 275K PU / no SO / 111K ROT, max gas 2071u. MPD open choke 55 PSI while drilling & 320 PSI on connections. Pumped low-vis sweep at 10,558', return not observed. Drill 8-1/2" production lateral from 10,749' to 11,321' 500 GPM, 1820 PSI, 120 RPM, 25k TQ, 5-15K WOB. 9.1 ppg MW, 41 vis, 10.9 ECD, 300K PU / no SO / 110K ROT, max gas 1620u. Pump hi-vis sweep at 11035', return on time w/ 50% increase. MPD open choke w/ 55 PSI while drilling & Hold 300 PSI on conn. At 10,796’ dumped 125 bbls from pit #1 (sand trap pit) and bring on 100 bbls new mud from pit #5. Drilled through fault #4 at 10,893’ with a 16’ DTS, putting Wellbore into the lower OA3. Target 91° and undulate up to OA1. Tq increasing to 25k+, increase lube to 3.5% at 11069’ Drill 8-1/2" production lateral from 11,321' to 11,511, 500 GPM, 1820 PSI, 120 RPM, 24k TQ, 5-15K WOB. 9.1 ppg MW, 44 vis, 11.10 ECD, 295K PU / no SO / 110K ROT, max gas 840u. MPD open choke 55 PSI while drilling & 300 PSI on connections. Enter OA1 at 11452'. Backream full stands. HES network down, unable to data exchange to Geology team. CBU while rotate and reciprocate full stand f/ 11511’ t/ 11416’. Rack stand back and pump tandem lo-vis/hi vis sweeps. 0% increase. Cont rot & ricip 90’, f/ 11416’ t/ 11321' while HES trouble shoot network. 500 GPM, 1800 psi, 120 RPM, 23k Tq Wash/Ream back to bottom. Drill 8-1/2" production lateral from 11,511' to 11,606', 500 GPM, 1880 PSI, 120 RPM, 25k TQ, 5-15K WOB. 9.1 ppg MW, 44 vis, 11.15 ECD, 295K PU / no SO / 110K ROT, max gas 1288u. MPD open choke 55 PSI while drilling & 300 PSI on connections. Last survey at 11346.22’ MD / 4021.30' TVD, 90.80° inc, 11.26° azm, 6.21’ from plan, 0.34' high and 6.2’ right. We have drilled 27 concretions for a total thickness of 196' (3.6% of the lateral). Daily disposal to G&I = 1142 bbls. Total disposal to G&I = 9830 bbls. Daily water hauled from L-Pad Lake = 770 bbls. Total water hauled from L-Pad Lake = 4981 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 5 lbs. Total metal recovered = 19 lbs. 4/19/2022 Drill 8-1/2" production lateral f/ 11,606' t/ 12,017', 411' drilled, 68.5'/hr AROP. 500 GPM, 1880 PSI, 120 RPM, 26K TQ, 6-8K WOB. 290K PU / no SO / 115K ROT, 9.1 MW, 45 vis, 11.05 ECD, max gas 887u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Perform 200 bbl mud dump & dilute at 11,701' and 110 bbls at 11,990'. MBT at 11,890' was 7.0 ppb. Backreaming full stands to aid in hole cleaning and reduce torque and drag. Drill 8-1/2" production lateral f/ 12,017' t/ 12462', 445' drilled, 74.2'/hr AROP. 500 GPM, 1880 PSI, 120 RPM, 26K TQ, 5-15K WOB. 280K PU / no SO / 113K ROT, 9.0 MW, 40 vis, 10.80 ECD, max gas 1288u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pumped hi-vis sweep at 12,177', back on time with 25% increase. Perform 100 bbl mud dump & dilute at 12,180'. Rig on generator power at 17:00. Drill 8-1/2" production lateral f/ 12462' t/ 12765', 303' drilled, 50.5’/hr AROP. 500 GPM, 1800 PSI, 120 RPM, 27K TQ, 5-18K WOB. 325K PU / no SO / 110K ROT, 9.0 MW, 40 vis, 10.70 ECD, max gas 981u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pumped Lo-Vis sweep at 12653’, return on time w/ 30% increase. Perform 120 bbl mud dump & dilute at 12700’. Continue backreaming full stands Drill 8-1/2" production lateral f/ 12765’' t/ 13090', 325' drilled, 54'/hr AROP. 500 GPM, 1800 PSI, 120 RPM, 28K TQ, 3-15K WOB. 325K PU / no SO / 110K ROT, 8.95 MW, 40 vis, 10.56 ECD, max gas 771u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Perform 140 bbl mud dump & dilute at 12895’. Continue backreaming full stands. Surveys at 12773’ & 12869’ showed magnetic interference from MP I-19L1 close approach. Last survey at 12,964.54’ MD / 4073.47' TVD, 88.45° inc, 8.26° azm, 92.68’ from plan, 4.75' low and 92.55’ right. We have drilled 38 concretions for a total thickness of 312' (4.5% of the lateral). Daily disposal to G&I = 1345 bbls. Total disposal to G&I = 11175 bbls. Daily water hauled from L-Pad Lake = 770 bbls. Total water hauled from L-Pad Lake = 5661 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 5 lbs. Total metal recovered = 19 lbs. 4/20/2022 Drill 8-1/2" production lateral from 13,090' to 13,370', 280' drilled, 46.6'/hr AROP. 500 GPM, 1810 PSI, 120 RPM, 27K TQ, 10K WOB. 310K PU / no SO / 115K ROT, 9 ppg MW, 44 vis, 10.59 ECD, max gas 701u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pump 30 bbl hi vis sweep @ 13100', back on time w/ 25% increase, all sand. Maintain 88 deg in lower portion of the OA-3 to avoid J-08. Closest point to J-08 approx 13' at 13535' Drill 8-1/2" production lateral from 13,370' to 13,795', 425' drilled, 70.8'/hr AROP. 500 GPM, 1890 PSI, 120 RPM, 28K TQ, 5-17K WOB. 310K PU / no SO / 110K ROT, 9.0 ppg MW, 42 vis, 10.8 ECD, max gas 738u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pump 30 bbl low vis sweep @ 13604', no indication of sweep at returns. Maintain target of 88° Drill 8-1/2" production lateral from 13795' to 14176', 381' drilled, 63.5'/hr AROP 500 GPM, 1890 PSI, 120 RPM, 30K TQ, 5-15K WOB. 335K PU / no SO / 112K ROT, 9 ppg MW, 40 vis, 10.90 ECD, max gas 795u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections Pump 30 bbl hi vis sweep @ 13986', on time with 40% increase. Maintain trajectory through the OA3 Drill 8-1/2" production lateral from 14176' to 14746', 570' drilled, 95/hr AROP. 500 GPM, 1850 PSI, 120 RPM, 30K TQ, 5-15K WOB. 210K PU / no SO / 113K ROT, 9 ppg MW, 40 vis, 10.62 ECD, max gas 1125u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Continue to maintain the OA3 30 bbl lo vis sweep @ 14461', no increase. Start adding 0.5% MI Lube 776 at 14367’ MD. Total Lube @ 4.5%. Observe instant Tq decrease as lube exit bit & record a 12-13k reduction in Tq, down to 16-17k, f/ 29-30k. PUW decrease f/ 325k t/ 210k over 2 stands drilled. Last survey at 14,676.74’ MD / 4096.40' TVD, 89.81° inc, 11.11° azm, 18.22’ from plan, 9.59' high and 15.49’ left. We have drilled 64 concretions for a total thickness of 467' (5.5% of the lateral). Daily disposal to G&I = 803 bbls. Total disposal to G&I = 11978 bbls. Daily water hauled from L-Pad Lake = 990 bbls. Total water hauled from L-Pad Lake = 6651 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 6 lbs. Total metal recovered = 35 lbs. 4/21/2022 Drill 8-1/2" production lateral from 14746' to 15430', 684' drilled, 114'/hr AROP. 500 GPM, 2070 PSI, 120 RPM, 18K TQ, 8-12K WOB. 190K PU / no SO / 110K ROT, 9 ppg MW, 43 vis, 11.2 ECD, max gas 1479u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pump 30 bbl hi vis sweep @ 15030', back on time with 100% increase mostly sand. Continue to drill in OA-3 targeting 89°. Crossed Fault #5 (16’ DTN) at 15,270’ MD /4,101’ TVD. Moved from OA-3 to OA-1. Rig back on hi line @ 06:30 Drill 8-1/2" production lateral from 15430' to 15935', 505' drilled, 84'/hr AROP. 500 GPM, 2110 PSI, 120 RPM, 18K TQ, 5-12K WOB. 192K PU / no SO /107K ROT, 9 ppg MW, 43 vis, 10.95 ECD, max gas 1074u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pump 30 bbl hi vis sweep @ 15505', back on time with 50% increase, mostly sand. Drilling in SB_OA1 , undulate down and enter the OA2 @ 15608’ Drill 8-1/2" production lateral from 15935' to 16270', 335' drilled, 56'/hr AROP. 500 GPM, 2210 PSI, 120 RPM, 19K TQ, 5-17K WOB. 205K PU / no SO /110K ROT, 9 ppg MW, 46 vis, 11.3 ECD, max gas 911u. MPD chokes open while drilling with 50 PSI, trap 300 PSI on connections. Pump 30 bbl hi vis sweep @ 15984', on time with 40% increase. Continue down trajectory, entering the OA3 @ 15970' Drill 8-1/2" production lateral from 16270' to 16538', 268' drilled, 59'/hr AROP. 500 GPM, 2130 PSI, 120 RPM, 23K TQ, 5-16K WOB. 205K PU / no SO /110K ROT, 9 ppg MW, 45 vis, 11.3 ECD, max gas 911u. MPD chokes full open drilling with 50 PSI, trap 300 PSI on connections. Ream 30' and obtain final survey Last survey at 16467.82’ MD / 4141.19' TVD, 89.75° inc, 9.67° azm, 18.28’ from plan, 17.33' high and 5.83’ right. We have drilled 86 concretions for a total thickness of 550' (5.3% of the lateral). Pump 30 bbl hi-vis sweep. Circulate hole clean, 500 GPM 2050 psi, 120 RPM 19k Tq. Rot & Recip 70’ while sweep in hole . Daily disposal to G&I = 1264 bbls. Total disposal to G&I = 13242 bbls. Daily water hauled from L- Pad Lake = 990 bbls. Total water hauled from L-Pad Lake = 7641 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 132 bbls. Daily metal recovered = 13 lbs. Total metal recovered = 48 lbs. 4/22/2022 Pump 30 bbl hi-vis sweep around circulating the hole clean, 500 GPM 2050 psi, 120 RPM 19k Tq. working pipe 70', sweep back on time with 50% increase. Continue to circulate an additional 3 BU pumping 500 gpm, 2100 psi, 120 RPM, 18K tq, rack stand back ea. BU for total 3 stds to 16174'. Prep pits for pumping SAPP train and displacing to lubricated brine. Wash and ream from 16174' to bottom @ 16538', 500 gpm, 2100 psi, 60 rpm, 17k torque. No fill PTM and crew change. PJSM with all parties involved for pumping SAPP train and displacing to lubricated brine. In mud PU 205k, no SO, ROT 110k Pump SAPP train as per Baroid procedure, Pump 3-40 bbl SAPP pills with 20 bbl 8.9 ppg brine spacers followed with 8.9 ppg 4% lubed/vissed brine pumping 300 gpm, 1120 psi, 40 rpm, 20k tq working pipe 70'. Add 7 drums 776 lube to bring lube content to 4.5% while displacing. Take mud returns to rock washer, dump interface and SAPP returns @ 1081 bbls, see brine @ 1111 bbls at surface, pump additional 208 bbls, divert clean brine returns to pit 4 (1319 bbls 8.9 brine pumped). MPD choke hold 110 psi line press. ECD 10.57, no losses displacing CBU 450 gpm, 1500 psi, 40 rpm, 15k torque, working pipe 70'. Perform PST - pass with 8.65 sec, 8.72 sec & 8.61 sec. Rack 1 stand back and obtain SPR's. Regained SOW with 65k dn. 170k up. MPD pressure built test - Start w/ 16psi line psi, build t/ 46psi then 21 psi consecutively next 2x. BROOH F/ 16462' T/14273' at 5-10 mins a stand. MPD full open choke with ECD 10.6-10.7 while BROOH & trapping 350 psi on connection. 450-500 GPM, 1620-1720 PSI, 120 RPM, 20k TQ, Max Gas 74u. 177K PU, 40 SO, 115K ROT. Dynamic losses @ 10-15 BPH. BROOH F/ 14273' T/ 12082' at 5- 10 mins a stand. MPD full open choke with ECD 10.3-10.6 while BROOH & trapping 270-300 psi on connection. 430 GPM, 1300 PSI, 120 RPM, 17k TQ, Max Gas 65u. 190K PU, 65 SO, 110K ROT. Dynamic losses @ 7-10 BPH. Daily disposal to G&I = 1849 bbls. Total disposal to G&I = 15091 bbls. Daily water hauled from L- Pad Lake = 430 bbls. Total water hauled from L-Pad Lake = 8071 bbls. Daily fluid loss = 70 bbls. Total fluid loss = 202 bbls. Daily metal recovered = 3 lbs. Total metal recovered = 51 lbs. 4/23/2022 Continue BROOH F/ 12082' ' T/ 9514' at 5-10 mins a stand. MPD full open choke with ECD 10.2 while BROOH & trapping 250 psi on connection. 450 GPM, 1100 PSI, 120 RPM, 15k TQ, Max Gas 74u. 170K PU, 85K SO, 110K ROT. Losses @ 4-6 BPH BROOH Continue BROOH F/ 9514' T/ 8230' at 5-10 mins a stand. MPD full open choke while BROOH & trapping 250 psi on connection. 465 GPM, 1000 PSI, 120 RPM, 12-14k TQ, Max Gas 70u. Started to pack off @ 8230', drop back down 10', BR very slow thru out of zone section f/ 8230' to 8183', hole unloading, stop and circulate clean, mostly clay, max gas 2567u. Continue to BR very slow to end of out of zone section @ 7880' stopping as needed to let cleanup. 450 gpm, 1070 psi, 120 rpm, 10k torque, ECD 10.5 Continue BROOH F/ 7880' T/ 7223' at 5- 10 mins a stand. MPD full open choke while BROOH & trapping 250 psi on connection. 465 GPM, 1000 PSI, 120 RPM, 12-14k TQ, Max Gas 1122u Started to experiencing intermittent pack off f 7223' to 7135'. Reduce pulling speed, stopping as needed until cleaned up. BROOH f/ 7135' t/ 6085' at 5-10 mins a stand. MPD full open choke while BROOH & trapping 250 psi on connection. 450 GPM, 900 PSI, 120 RPM, 6k TQ, Max Gas 582u 130k PU, 100k SO, 110k ROT. No issues pulling into 9-5/8" casing shoe. Dynamic losses @ 4-6 BPH. Total of 248 bbls loss while BROOH to shoe. Pump 30bbls high vis sweep and circulate casing clean. 100% increase at the shakers from sweep. 450 GPM, 1000 PSI, 80 RPM, 5K TQ. 140K PU, 90K SO 106K ROT PST after 1st BU failed and shaker still fair amount of sand/silt. Mix and pump 2nd hi-vis sweep around. Shakers clean up significantly and 2nd PST pass with 8.33 sec, 8.54 sec & 7.87sec. MW in/out 9.25 ppg, 46 vis. Total of 5x BU circulated. Monitor MPD pressure build in 5 min intervals. 45psi, 27 psi, 18psi. Blow down TopDrive. Monitor well for flow at 2” on RCD. Static after 5min. Continue monitor for 30 min while holding PJSM and prep for removing MPD RCD with new crew. Remove MPD bearing and install trip nipple. Daily disposal to G&I = 0 bbls. Total disposal to G&I = 15091 bbls. Daily water hauled from L-Pad Lake = 100 bbls. Total water hauled from L-Pad Lake = 8171 bbls. Daily fluid loss = 178 bbls. Total fluid loss = 380 bbls. Daily metal recovered = 7 lbs. Total metal recovered = 58 lbs. 4/24/2022 Finish installing the trip nipple, check for leaks, good, fill the trip tank with 9.2+ brine. Continue to monitor well, currently 5 bph loss rate. BD MPD lines. POOH f/ 6085' to 5607' LD 15 jts 5'' DP, Monitor well, mix and pump 30 bbl 10.2 ppg dry job, BD TD and Geo span. install stripping rubber. TOOH L/D 5'' DP to the pipe shed from 5607' to 5235', Adjust flow paddle in flow line due to not reading correctly Continue to TOOH L/D 5'' DP to the pipe shed from 5235' to 283' @ HWDP. Loss rate 5-6 BPH TOOH Flow check before pulling BHA, slight losses. L/D jar stand, float subs, NMFCs, Download MWD data, L/D remaining BHA. 8 1/2'' PDC Bit grade= 2-2-BT-A-X-I-CT-TD. 66 bbl losses TOOH from shoe Clear rig floor of BHA accessories and tools. Clean the rig floor in prep to run lower completion string. Monitor well, static loss rate @ 3 BPH. Load tools to rig floor. R/U 4 1/2'' handling equipment and power tongs. Remove split bushings. Ready Safety joint. Monitor well, static loss rate @ 3 BPH Run 4-1/2'', 13.5#, L-80 H625 screen lower completion as per tally to 6150'. Torque to optimum @ 9600 ft/lbs with Doyon double stack tongs. 110K PU / 90K S O. 23 bbls loss while RIH w/ screens Daily disposal to G&I = 382 bbls. Total disposal to G&I = 15473 bbls. Daily water hauled from L-Pad Lake = 0 bbls. Total water hauled from L-Pad Lake = 8171 bbls. Daily fluid loss = 102 bbls. Total fluid loss = 482 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/25/2022 Run 4-1/2'', 13.5#, L-80 H625 screen lower completion as per tally from 6150' to 8668', install 4 1/2'' blank joints as required for total of 29. Torque to optimum @ 9600 ft/lbs with double stack tongs. 3 bph loss rate RIH w/ screens C/O to 5 1/2'' handling equipment- power tong dies, ready safety joint and XOs, M/U XO, Continue to run 5 1/2'', 20#, L-80, EZGO HT screen lower completion f/ 8668' to 9016', install 5 1/2'' blank jts as required. Torque to optimum @ 9000 ft/lbs with double stack tongs. PU 125K, SO 80K. 3 bph loss rate RIH Continue to run 5 1/2'', 20#, L-80, EZGO HT screen lower completion f/ 9016' to 10530', install 5 1/2'' blank jts as required for total of 8. Torque to optimum @ 9000 ft/lbs with double stack tongs. 3 bph loss rate RIH C/O to 5'' elevators. M/U Baker 7" x 9-5/8" SLZXP liner top packer assy as per BOT rep at 10530', verify 9 pins set @ 44k shear, verify pipe count. Obtain parameters: 145K PU / 82K SO Drift and RIH with 1 stand 5'' DP, Pump 10 bbls to ensure clear flow path through Baker tools, 2 bpm, 120 PSI. Drift and RIH with 19 more stds 5'' DP out of derrick f/ 10663' to 12472' @ 30 fpm Loss rate continues at 3 bph. PU 165K, SO 85K Drift and Single in with 127 joints 5'' HWDP from the pipe shed f/ 12472' t/ 16386'. RIH with 5" DP from Derrick t/ 16538', tagging bottom 2x w/ 10k dn. Loss rate continues at 3 BPH. Total of 66 bbls loss running lower completion. PU 275K, SO 145K L/D top single from stand. Rig up to circulate through cement line and from test pump to set packer. Circulate 15 bbls to ensure clear flow path. Drop 1” phenolic ball, pull string into tension and set. Chase with hi-vis sweep & set SLZXP packer as per Baker rep. 690 stks to seat ball. LPT @ 5981' MD. Rig up test equip, close UPR, test LTP to 1500psi for 10mins charted – Good. Hold 300 psi on DP and pull running tool free of packer slowly. Increase flow rate to 8 BPM when returns observed. Circulate sweep out and 2x BU until shakers clean and passing PST obtained. Reciprocate string 60', keeping running tool out of seal bore receptacle. 350 GPM - 930 psi. 210k PU / 175k SO. Blow down Top Drive and all surface lines. Flow check – slight losses. Install stripping rubber Pull out of hole @ 5200’, laying down HWDP to pipe shed. Losses @ 3 BPH Daily disposal to G&I = 0 bbls. Total disposal to G&I = 15473 bbls. Daily water hauled from L-Pad Lake = 70 bbls. Total water hauled from L-Pad Lake = 8241 bbls. Daily fluid loss = 64 bbls. Total fluid loss = 546 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/26/2022 POOH with liner running tool LD 5'' HWDP to pipe shed from 5200’ to 4200'. Losses @ 3 BPH Build and pump dry job, Remove casing equipment and clear off the rig floor. Attempt to break out TD, fault tripped, Rig electrician Troubleshoot no power to drillers console, cooling fan breaker tripped, re-set good. Monitor well with trip tank, loss rate 2-3 bph. B/O and BD TD, Continue POOH with liner running tool LD 5'' HWDP to pipe shed from 4200’ to 2275' Install FOSV and 5' pup, slip and cut 94' drilling line, inspect saver sub and backup dies, L/D FOSV and pup joint, re-calibrate block height, adjust brakes and service TD. Monitor well, 3 bph loss rate. Continue POOH LD 5'' HWDP to pipe shed from 2275' to surface, inspect and LD running tool. Dog sub sheared, HRD hydraulically released, all indications of proper operation. 35 bbl losses TOOH. Swap to completions AFE @ 18:00 Refer to MP I-29 completions report for details. Daily disposal to G&I = 114 bbls. Total disposal to G&I = 15587 bbls. Daily water hauled from L-Pad Lake = 60 bbls. Total water hauled from L-Pad Lake = 8301 bbls. Daily fluid loss = 52 bbls. Total fluid loss = 598 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. Activity Date Ops Summary 4/26/2022 Refer to MP I-29 Drilling Report for details,Break down the stand from Derrick, with stuck drift in it. Make up 4-1/2" IF stack washer and TIH w/ 44 stands 5" DP from Derrick t/ 4187'. 115k PU, 102k SO. Monitor well - slight losses. Pump dry job and POOH laying down DP to shed t/ 949'. 17 bbls loss during round trip.,TIH w/ remaining 44 stands 5" DP from Derrick f/ 949' t/ 5111'. 130k PU, 125k SO. Monitor well - slight losses. Pump dry job and POOH laying down DP to shed t/ 2000'. 80k PU, 77k SO,Daily disposal to G&I = 114 bbls Total disposal to G&I = 15587 bbls. Daily water hauled from L-Pad Lake = 60 bbls. Total water hauled from L-Pad Lake = 8301 bbls. Daily fluid loss = 52 bbls. Total fluid loss = 598 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/27/2022 POOH laying down 5'' DP to shed f/ 2000' to surface, L/D stack flush tool. 23.8 bbl losses on TOOH LD pipe,Drain stack, remove wear bushing, mobilize tools to rig floor, RU 7'' Handling equipment and power tongs. Ready FOSV and XO. Monitor well with trip tank, 3 bph loss rate,PJSM, PU 7'' Bullet seal as per BOT rep, MU 1st jt, troubleshoot tong torque, torque gauge not reading accurate, Doyon source and replace gauge- check connection, torque properly to optimum at 14,750 ft/lbs.,PU and RIH 7'' 26# L-80 TXP tie back string as per tally to tag 5,982' with 5K down (PU = 149K & SO =108K), torque to 14,750 ft/lbs, RIH at moderate speed due to pipe wanting to overflow. Loss rate = 3 BPH,Space out. Lay down three joints of 7" casing. MU 9.85' and 14.83' pup joint. MU joint #146 of casing and mandrel casing hanger. Land the hanger.,RU to reverse circulate. PJSM to reverse circulate. Found line to mud pump #1 frozen. Thaw out line. Simops: Close the annular and pressure up to 500 psi. Strip through the bag until the pressure dropped. Remove casing equipment from the rig floor.,Reverse circulate 90 bbls of corrosion inhibited 2% KCl at 5 BPM = 550 psi followed by 78 bbls of diesel at 5 BPM = 680 psi. Pump 5 bbls KCl to clear the line of diesel. SO stripping through the bag and land the mandrel casing hanger (70K). Open the annular. RD reverse circulating equipment. Blow down the cement line. Lay down the landing joint. RD 7" casing elevators. RU 5" DP elevators. Drain the stack. Daily disposal to G&I = 57 bbls. Total disposal to G&I = 15,644 bbls. Daily water hauled from L-Pad Lake = 75 bbls. Total water hauled from L-Pad Lake = 8,376 bbls. Daily fluid loss = 60 bbls. Total fluid loss = 658 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/28/2022 Finish blowing down the kill line, PU running tool, install hanger pack off and RILDS. Test void to 500 psi 5 min and 5000 psi for 10 min as per WHR, good.,Rig up test equipment, install 3'' flange x 1502 on OA, source and RU 2" hose, troubleshoot chart recorder, with the rig pump, test the 9 5/8" x 7" annulus to 1500 psi for 30 charted min, good test, RD test equipment. Monitor well with trip tank, 3 bph loss rate. AOGCC rep Lou Laubenstein waived BOP test witness @ 11:15 via phone call.,RU test equipment with 4 1/2'' test joint, flood stack and lines, attempt to get a shell test, found test plug not holding.,Drain stack, pull test plug, C/O test plug as per WHR. Re-install test plug, fill stack and flood the lines. Shell test (passed).,Conduct bi-weekly BOPE test to 250/3,000 psi: Lower pipe rams (2-7/8” x 5” VBR’s) 4-1/2” test joint, upper pipe rams (4-1/2” x 7” VBR’s) with 4-1/2” test joint, annular with 4-1/2” test joint to 250/3,000 psi, accumulator drawdown test and test gas alarms. The states right to witness was waived by AOGCC inspector Lou Laubenstein on 4/28/22 at 11:15 hours. Tests: 1. Annular to 2500 psi with 4-1/2” test joint, 3” Demco kill, upper IBOP, choke valves 1, 12, 13 & 14 (passed). 2. UPR with 4-1/2” test joint, HCR kill, lower IBOP, choke valves 9 & 11 (passed). 3. Manual kill, 5” TIW, choke valves 5, 8 & 10 (passed). 4. 5” dart valve, choke valves 4, 6 & 7 (passed). 5. Choke valve 2 (passed). 6. HCR choke (passed). 7. Manual choke (passed). 8. LPR with 4-1/2” test joint (passed). 9. Blind rams (passed). 10. Manual adjustable choke (passed). 11. Hydraulic super choke (passed). Accumulator Test: System pressure = 2950 psi. Pressure after closure = 1620 psi. 200 psi attained in 42 seconds. Full pressure attained in 184 seconds. Nitrogen Bottles - 6 at 2000 psi,RD BOPE testing equipment. Blow down the choke manifold, kill lines and top drive.,RU to run 4-1/2" JP completion.,PJSM. PU, MU and RIH mule shoe joint on 4-1/2", 12.6#, L-80, TXP tubing, torque to 6,170 ft-lbs to 1,190',MU XN nipple assembly, 1 joint, Premier Packer assembly, 1 joint and JP assembly (sliding sleeve with gauge). MU the Tec wire to the gauge. Test gauge (good). Continue to RIH with JP completion on 4-1/2", 12.6#, L-80, TXP tubing, torque to 6,170 ft-lbs from 1,361' to 4,795' spooling Tec wire and installing cannon clamps the first 10 joints then every other joint. Testing the Tec wire every 1,000'. Daily disposal to G&I = 409 bbls. Total disposal to G&I = 16,053 bbls. Daily water hauled from L-Pad Lake = 135 bbls. Total water hauled from L-Pad Lake = 8,511 bbls. Daily fluid loss = 48 bbls. Total fluid loss = 706 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/29/2022 Continue to RIH with JP completion on 4-1/2", 12.6#, L-80, TXP tubing, torque to 6,170 ft-lbs from 4,795' to 5977' at joint # 142 spooling Tec wire and installing cannon clamps every other joint. Testing the Tec wire every 1,000'. Loss rate = 1.5 BPH while RIH. 14.9 bbl losses while running completion.,MU tubing hanger and pup joint with BPV installed. MU the landing joint with crossover. Run tech wire thru hanger and secure same. Drain stack to cellar box. Land the hanger (PU = 95K, SO = 77K, 37K on hanger) with mule shoe at 6,012' and RILDS. LD the landing joint.,RD 4-1/2'' tubing running tools, tech wire sheave in the derrick. Off load the tec wire spooling unit.,Remove the MPD drip pan and bell nipple. ND BOP stack. Remove the kill line hose off the mud cross and set the BOP stack on the pedestal.,Install the CTS plug into the BPV. NU the tubing head adaptor and tree.,Terminate tech wire thru adaptor. Final readings: tubing pressure = 1676 psi, IA pressure = 1679 psi, tubing/IA temp = 74°F. PT the tubing hanger void to 500 psi for 5 minutes and 5,000 psi for 10 minutes (good test).,RU to test the tree. Fill the tree with diesel. PT the tree to 250/5,000 psi (good test). RD testing equipment.,Drain diesel from the tree through the wing valve. Pull the CTS plug and BPV with the dry rod.,RU to reverse circulate down the IA taking returns up the tubing while being able to u-tube the tubing/IA once we are done pumping. PT the lines to 3,000 psi (good test).,PJSM. Reverse circulate 195 bbls of 8.4 ppg CI source water down the IA taking returns up the tubing. Got back 76 bbls in the returns. Shut down and line up to the diesel. Pump 55 bbls of diesel down the IA and 45 bbls of diesel down the tubing.,Shut in the well. Bleed the pressure off the tree and drain diesel down to the wing valve. Place the ball & rod on top of the master. Reinstall the tree cap. Open the master dropping the ball and rod at 01:15 hours. Bleed pressure off the tree.,Allow time for the ball & rod to gravitate to the ball seat. RU to be able to chart the pressure tests.,Slowly pressure up on the tubing to 3,500 psi to set the Premier packer. PT the tubing to 3,500 psi for 30 minutes charted (good test). Line up to pressure up on the IA. PT the IA to 3,500 psi for 30 minutes charted (good test).,Bleed the IA to 0 psi. Bleed the tubing down to 500 psi (would not bleed down to 0 psi). Daily disposal to G&I = 296 bbls. Total disposal to G&I = 16,349 bbls. Daily water hauled from L-Pad Lake = 70 bbls. Total water hauled from L-Pad Lake = 8,581 bbls. Daily fluid loss = 137 bbls. Total fluid loss = 843 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 58 lbs. 4/30/2022 Blow down and RD the circulating lines. Rig released at 06:00 hours 50-029-23708-00-00API #: Well Name: Field: County/State: MP I-29 Milne Point Hilcorp Energy Company Composite Report , Alaska 4/6/2022Spud Date: TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 1 1 1 1 95 1 1 1 50 1 X Yes No X Yes No 332 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:Yes X No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 1.17 4/12/2022 Surface Spud mud Type I/II 523 2.35 Premium G 400 1.16 5 2,103.44 Casing 9 5/8 47.0 L-80 TXP Tenaris 2,046.60 2,103.44 56.84 2,123.66 2,121.04 Casing Pup Joint 9 5/8 40.0 L-80 TXP 17.60 2,121.04 17.20 2,140.86 2,123.66 ES Cementer 10 3/4 TXP Halliburton 2.62 Casing Pup Joint 9 5/8 40.0 L-80 TXP 6,012.80 Casing 9 5/8 40.0 L-80 TXP Tenaris 3,871.94 6,012.80 2,140.86 6,053.77 6,014.21 Baffle Adapter 10 3/4 TXP Halliburton 1.41 6,014.21 1.33 6,055.10 6,053.77 Casing 9 5/8 40.0 L-80 TXP Tenaris 39.56 Float Collar 10 3/4 TXP Innovex 79 total 9-5/8" x 12"1/4" bowspring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating on joint #2. One each with stop rings mid-joint on joint #3 & 4. One each on joints 5 to 25, every other joint to #49 then every third joint to #94. One each on joints #95 to 104. One each with stop rings on pup joints above and below ES cementer. One each on every third joint #107 to #147. Casing 9 5/8 40.0 L-80 TXP Tenaris 82.29 6,137.39 6,055.10 www.wellez.net WellEz Information Management LLC ver_04818br 5 Ftg. Returned Ftg. Cut Jt. Ftg. Balance No. Jts. Delivered 168 No. Jts. Run 150 18 Length Measurements W/O Threads Ftg. Delivered Ftg. Run RKB to CHF Type of Shoe:Innovex Casing Crew:Doyon 12 219 ES Cementer Closure OK 56 ArcticCem Type Premium G 270 Tuned Spacer 705 2.88 Stage Collar @ 6 Bump press 100 182 6,139.006,150.00 CEMENTING REPORT Csg Wt. On Slips:100,000 Spud Mud 23:54 4/11/2022 2,122 2122.16 15.8 82 Bump press Circulated cement to surface Bump Plug? 3 9.4 6 154.1/155.5 459.8/450.5 67 RigFIRST STAGE10Tuned Spacer 60 15.8 610 9.4 6 1510 10 10.7 362 4.5 95 750 Bump Plug? Csg Wt. On Hook:123,000 Type Float Collar:Innovex No. Hrs to Run:18.5 9 5/8 47.0 L-80 TXP TXP Innovex 1.61 6,139.00 6,137.39 24.58 56.84 32.26 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP I-29 Date Run 11-Apr-22 CASING RECORD County State Alaska Supv.C. Demoski / I. Toomey 6,054.10 Floats Held 374.4 719 249 470 Spud Mud Rotate Csg Recip Csg Ft. Min. 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B0:',)5066DJ B0:',)5066DJ 352-(&7('WR7' $SSURYHG%\&KHFNHG%\'DWH 30 &203$66%XLOG(3DJH Benjamin Hand Digitally signed by Benjamin Hand Date: 2022.04.25 09:48:10 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2022.04.25 12:43:21 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Doug Yessak - (C) To:Regg, James B (OGC);DOA AOGCC Prudhoe Bay;Brooks, Phoebe L (OGC) Cc:Nathan Sperry;Brian Glasheen;Cody Dinger;Ian Toomey - (C) Subject:Doyon 14 BOP Date:Friday, April 29, 2022 11:58:39 AM Attachments:Doyon 14 BOPE TEST 4-28-22.xlsx Doug Yessak Hilcorp DSM Doyon 14 907-670-3090 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 038, 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:14 DATE: 4/28/22 Rig Rep.: Rig Phone: 907-670-3096 Operator: Op. Phone:907-670-3090 Rep.: E-Mail Well Name:PTD #22220060 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: Weekly: Bi-Weekly: X Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1402 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 2P Standing Order Posted P Misc.NA Inside BOP 2P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8" 5K P Pit Level Indicators PP #1 Rams 1 4-1/2"X7" VBR P Flow Indicator PP #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 1 2-7/8"X5" VBR P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8" 5K P Inside Reel valves 0NA HCR Valves 2 3-1/8" 5k P Kill Line Valves 2 3-1/8" 5K P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)2950 P CHOKE MANIFOLD:Pressure After Closure (psi)1620 P Quantity Test Result 200 psi Attained (sec)42 P No. Valves 14 P Full Pressure Attained (sec)184 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 6 @ 2125 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice yes Date/Time 4-26-22 / 15:53 Waived By Test Start Date/Time:4/28/2022 17:00 (date) (time)Witness Test Finish Date/Time:4/28/2022 21:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Lou Laubenstein Doyon Test Annular w/4-1/2" test jt. 250-3000 psi, Upper & lower VBR'S with 4-1/2". draw down on BOP functioned from both primary & remote controls. All tests preformed against Test plug. Tested one 4-1/2" IF FOSV & one DART 4-1/2" IF valves. Tested all gas alarms, both audio and visual. J Hansen / A Carlo HilCorp Alaska LLC D Yessak / I Toomey MPU I-29 Test Pressure (psi): dyessak@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0428_BOP_Doyon14_MPU_I-29 9 9 9 9 9999 9 9 - 5HJJ 9 4/28/22 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20000415 0720 Follow up surface casing cementing summary Date:Friday, April 15, 2022 8:44:27 AM From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Friday, April 15, 2022 7:20 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: PTD 222-006 Hilcorp Well MPU I-29 FIT Data for Review Mel, I’m sending this to follow up per our conversation. Here is a summary of our surface cement job: Stage 1 Volumes Pumped 60 bbls spacer 219 bbls 12.0ppg lead 82 bbls 15.8ppg tail We did not bump the plug on stage 1. We dropped the free fall opening plug (contingency plug to open the ES cementer) and we dumped 195 bbls of interface (mud/spacer/cement) and 67 bbls of cement. This is the cement from stage 1 that made it above the ES cementer. Stage 2 Volumes Pumped 60 bbls spacer 362 bbls 10.7ppg lead 56 bbls 15.8ppg tail We bumped the plug and had 185 bbls of good cement back to surface. It’s worth noting that on stage 2 jobs, we pump lead cement until we see cement at surface, then we swap to our tail cement. When we drilled out, we found cement 130’ high of the shoetrack (between 9 and 10 bbls). We drilled hard cement through the entire shoetrack. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 From: Nathan Sperry Sent: Friday, April 15, 2022 6:45 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PTD 222-006 Hilcorp Well MPU I-29 FIT Data for Review Importance: High Good morning Mel, Attached is the casing test and FIT data from MPU I-29. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220415 0712 APPROVAL to Drill Ahead PTD 222-006 Hilcorp Well MPU I-29 FIT Data for Review Date:Friday, April 15, 2022 8:43:19 AM Attachments:MPU I-29_9.625"" Casing PT FIT @ 6000".pdf From: Rixse, Melvin G (OGC) Sent: Friday, April 15, 2022 7:12 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: Re: PTD 222-006 Hilcorp Well MPU I-29 FIT Data for Review Nathan, Please send the cementing summary later today. As we discussed, insignificant cement losses during 9-5/8” cementing, so you are approved to drill production hole. Mel Rixse On Apr 15, 2022, at 6:45 AM, Nathan Sperry <Nathan.Sperry@hilcorp.com> wrote: Good morning Mel, Attached is the casing test and FIT data from MPU I-29. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-29 Date:4/14/2020 Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Demoski/Vanderpool Csg Setting Depth:6139 TMD 3957 TVD Mud Weight:9.3 ppg LOT / FIT Press =556 psi . LOT / FIT =12.00 ppg Hole Depth =6170 md Fluid Pumped=1.7 Bbls Volume Back =0.9 bbls Estimated Pump Output:0.101 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->0 0 ->0 0 ->2 58 ->4 253 ->4 82 ->8 551 ->6 141 ->12 746 ->8 210 ->16 949 ->9 237 ->20 1156 ->10 263 ->24 1368 ->11 311 ->28 1622 ->12 346 ->32 1852 ->13 381 ->36 2118 ->14 428 ->40 2361 ->15 465 ->44 2648 ->16 502 ->45 2676 ->17 556 -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 556 ->0 2676 ->1 532 ->5 2663 ->2 527 ->10 2654 ->3 524 ->15 2647 ->4 521 ->20 2641 ->5 514 ->25 2634 ->6 507 ->26 2633 ->7 500 ->27 2632 ->8 494 ->28 2631 ->9 488 ->29 2630 ->10 481 ->30 2629 ->11 475 -> ->12 470 -> ->13 464 -> ->14 458 ->15 454 -> 0 2 4 6 8 9 10 111213 141516 17 0 4 8 12 16 20 24 28 32 36 40 4445 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 10 20 30 40 50Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA Pressure (psi) 556532527524521514507500494488481475470464458454 2676 2663 2654 2647 2641 263426332632263126302629 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Alaska NS - Doyon 14 - DSMs To:Regg, James B (OGC);DOA AOGCC Prudhoe Bay;Brooks, Phoebe L (OGC) Cc:Doyon Rig14;Nathan Sperry Subject:Doyon 14 BOPE TEST 4-14-22 MPU I-29 Date:Thursday, April 14, 2022 3:28:44 PM Attachments:Doyon 14 BOPE TEST 4-14-22 MPU I-29.xlsx Attached is our initial drilling BOP test report for well MPU I-29. Regards, C.A. Demoski Doyon 14 DSM 907-670-3090 Office 907-670-3092 Rig Floor 907-378-7530 Cell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 038, 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:14 DATE: 4/14/22 Rig Rep.: Rig Phone: 907-670-3096 Operator: Op. Phone:907-670-3090 Rep.: E-Mail Well Name:PTD #22220060 Sundry # Operation: Drilling: X Workover: Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1402 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 1P Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 13-5/8" 5K P Pit Level Indicators PP #1 Rams 1 4-1/2"X7" VBR P Flow Indicator PP #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 1 2-7/8"X5" VBR P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8" 5K P Inside Reel valves 0NA HCR Valves 2 3-1/8" 5k P Kill Line Valves 2 3-1/8" 5K P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1600 P Quantity Test Result 200 psi Attained (sec)44 P No. Valves 14 P Full Pressure Attained (sec)204 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 6 @ 2150 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:6.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice yes Date/Time 4-11-22 / 17:28 Waived By Test Start Date/Time:4/13/2022 18:00 (date) (time)Witness Test Finish Date/Time:4/14/2022 0:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Doyon Test Annular w/4-1/2" test jt. 250-3000 psi, Upper VBR with 4-1/2" and 7" test joint Lower VBR with 4-1/2" and 5" test jts. Draw down on BOP functioned from both primary & remote controls. All tests preformed against Test plug. Tested one 4-1/2" IF FOSV & one DART 4-1/2" IF valves. Tested all gas alarms, both audio and visual. T. Shones / J. Charlie HilCorp Alaska LLC C. Demoski / J. Vanderpool MPU I-29 Test Pressure (psi): AlaskaNS-Doyon14-DSMs@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0414_BOP_Doyon14_MPU_I-29 99 9 9 9 9 9 9 9 9 - 5HJJ 4/14/22 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Alaska NS - Doyon 14 - DSMs To:Regg, James B (OGC);DOA AOGCC Prudhoe Bay;Brooks, Phoebe L (OGC) Cc:Nathan Sperry;Ian Toomey - (C);Claude Demoski - (C) Subject:Doyon 14 diverter 4-5-2022 Date:Tuesday, April 5, 2022 8:12:23 PM Attachments:Diverter-Doyon 14 _ 04-05-22.xls Doug Yessak Hilcorp DSM Doyon 14 907-670-3090 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 038, 37' Date: 4/5/2022 Development: X Exploratory: Drlg Contractor: Rig No. 14 AOGCC Rep: Operator:Oper. Rep: Field/Unit/Well No.:Rig Rep: PTD No.: 2220060 Rig Phone: Rig Email: MMISCELL ANEOUS:DIVERTER SYSTEM: Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P Warning Sign P Misc: NA No Threaded Connections? P 24 hr Notice: P Vent line Below Diverter? P AACCUMULATOR SYSTEM:Diverter Size: 21 1/4 in. Systems Pressure: 2950 psig P Hole Size: 12 1/4 in. Pressure After Closure: 1700 psig P Vent Line(s) Size: 16 in. P 200 psi Recharge Time: 37 Seconds P Vent Line(s) Length: 360 ft. P Full Recharge Time:175 Seconds P Closest Ignition Source: 76 ft. P Nitrogen Bottles (Number of): 6 Outlet from Rig Substructure: 352 ft. P Avg. Pressure: 2100 psig P Accumulator Misc: NA Vent Line(s) Anchored: P MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: P Trip Tank: P P Divert Valve(s) Full Opening: P Mud Pits: P P Valve(s) Auto & Simultaneous: Flow Monitor: P P Annular Closed Time: 28 sec P Mud System Misc: 0 NA Knife Valve Open Time: 20 sec P Diverter Misc: NA GGAS DETECTORS:Visual Alarm Methane: P P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA Total Test Time: 1 hrs Non-Compliance Items: 0 Remarks: Submit to: phoebe.brooks@alaska.gov Hilcorp Alaska LLC AOGCC Lou Laubenstein waived witness on 4-4-22 @ 14:35. Function test performed utilizing a joint 5'' drill pipe, Rig electrician calibrated and tested the gas alarms. Test PVT gain/loss and flow alarm. 0 Yessak / Toomey Milne Point Unit I-29 SSTATE OF AL ASKA AAL ASK A OIL AND GAS CONSERVATION COMMISSION DDiv er t er Sys t em s In s p ec t i o n Rep o r t GGENERAL INFORMATION WaivedDoyon AOGCC.Inspectors@alaska.gov 0 TTEST DATA Hansen / Carlo AlaskaNS-Doyon14-DSMs@hilcorp.co 907-670-3090 TTEST DETAIL S jim.regg@alaska.gov Form 10-425 (Revised 11/2015)2022-0405_Diverter_Doyon14_MPU_I-29 9 9 9 9 9 9 9 -5HJJ CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PTD 222-006 Hilcorp Well MPU I-29: Adding 5-1/2" to 4-1/2" liner Date:Tuesday, April 5, 2022 3:10:22 PM From: Rixse, Melvin G (OGC) Sent: Tuesday, April 5, 2022 9:37 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: PTD 222-006 Hilcorp Well MPU I-29: Adding 5-1/2" to 4-1/2" liner Nathan, Change approved. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Joe Lastufka From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Tuesday, April 5, 2022 9:33 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: PTD 222-006 Hilcorp Well MPU I-29: Adding 5-1/2" to 4-1/2" liner Hello Mel, Are you okay with the change proposed below? Also FYI – we’re a little more than a week out from our FIT for MPU I-29. I will update you on our expected timing for the FIT as we get closer. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 From: Nathan Sperry Sent: Wednesday, March 16, 2022 2:56 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PTD 222-006 Hilcorp Well MPU I-29: Adding 5-1/2" to 4-1/2" liner Hello Mel, We are planning to replace ~2,000’ of 4-1/2” screened liner with 5-1/2” screened liner. We will rely on a safety joint made up to a 5-1/2” XO on the rig floor for our primary well control response. The updated drilling procedure is attached. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220317 1457 PTD 222-006 Hilcorp Well MPU I-29_ Adding 5-1_2_ to 4-1_2_ liner Date:Thursday, March 17, 2022 4:37:28 PM Attachments:MPU I-29 Drilling Program V4.pdf Subject: PTD 222-006 Hilcorp Well MPU I-29: Adding 5-1/2" to 4-1/2" liner Hello Mel, We are planning to replace ~2,000’ of 4-1/2” screened liner with 5-1/2” screened liner. We will rely on a safety joint made up to a 5-1/2” XO on the rig floor for our primary well control response. The updated drilling procedure is attached. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907-777-8450 C: 907-301-8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Milne Point Unit (MPU) I-29 Drilling Program Version 4 3/16/2022 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 5-1/2” x 4-1/2” Screened Liner ........................................................................................ 33 17.0 Run 7” Tieback ........................................................................................................................ 38 18.0 Run Upper Completion – Jet Pump ........................................................................................ 41 19.0 Doyon 14 Diverter Schematic .................................................................................................. 43 20.0 Doyon 14 BOP Schematic ........................................................................................................ 44 21.0 Wellhead Schematic ................................................................................................................. 45 22.0 Days Vs Depth .......................................................................................................................... 46 23.0 Formation Tops & Information............................................................................................... 47 24.0 Anticipated Drilling Hazards .................................................................................................. 49 25.0 Doyon 14 Rig Layout ............................................................................................................... 52 26.0 FIT Procedure .......................................................................................................................... 53 27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 54 28.0 Casing Design ........................................................................................................................... 55 29.0 8-1/2” Hole Section MASP ....................................................................................................... 56 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58 Page 2 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 1.0 Well Summary Well MPU I-29 Pad Milne Point “I” Pad Planned Completion Type Jet Pump Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 16,535’ MD / 4,159’ TVD PBTD, MD / TVD 16,535’ MD / 4,159’ TVD Surface Location (Governmental) 2327' FSL, 1626' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551717, Y= 6009443 Top of Productive Horizon (Governmental) 2379' FNL, 385' FEL, Sec 32, T13N, R10E, UM, AK TPH Location (NAD 27) X= 549701, Y= 6010003 BHL (Governmental) 2020' FNL, 1234' FWL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 551215, Y= 6020931 AFE Number AFE Drilling Days 17 AFE Completion Days 4 Maximum Anticipated Pressure (Surface) 1402 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1817 psig Work String 5” 19.5# S-135 NC 50 Doyon 14 KB Elevation above MSL: 33.7 ft + 33.7 ft = 67.4 ft GL Elevation above MSL: 33.7 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604 8-1/2” 5-1/2” Screens 4.780” 4.653” 6.000” 20 L-80 EZGO HT 9,189 8,830 466 8-1/2” 4-1/2” Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279 Tubing 4-1/2" 3.958” 3.833” 4.729” 12.6 L-80 TXP 8,430 7,500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5” 4.276” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz.  Report covers operations from 6am to 6am  Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry.  Ensure time entry adds up to 24 hours total.  Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports.  Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates  Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update  Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting  Health and Safety: Notify EHS field coordinator.  Environmental: Drilling Environmental Coordinator  Notify Drilling Manager & Drilling Engineer on all incidents  Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally  Send final “As-Run” Casing tally t o nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report  Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Completion Engineer David Gorm 907.777.8333 dgorm@hilcorp.com Geologist Katie Cunha 907.564-4786 Katharine.cunha@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 7.0 Drilling / Completion Summary MPU I-29 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. I-29 is part of a multi well program targeting the Schrader Bluff sand on I-pad The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled and completed with a 5-1/2” x 4-1/2” liner. The well will be produced with a jet pump. Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately March 1, 2022, pending rig schedule. Surface casing will be run to 6,231’ MD / 3,960’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD 6. Run 5-1/2” x 4-1/2” production liner 7. Run 7” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and co mpletion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior appro val from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team.  Review all conditions of approval of the PTD on the 10 -401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with.  BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-29. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.  The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD.  If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test.  All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”.  All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away fr om potential ignition sources  Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.  Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing, “A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests:  None Page 9 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”  21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2”  13-5/8” x 5M Hydril “GK” Annular BOP  13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity  Mud cross w/ 3” x 5M side outlets  13-5/8” x 5M Hydril MPL Single ram  3-1/8” x 5M Choke Line  3-1/8” x 5M Kill line  3-1/8” x 5M Choke manifold  Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications:  Well control event (BOPs utilized to shut in the well to control influx of formation fluids).  24 hours notice prior to spud.  24 hours notice prior to testing BOPs.  24 hours notice prior to casing running & cement operations.  Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 9.0 R/U and Preparatory Work 9.1 I-29 will utilize a newly set 20” conductor on I-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install la nding ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U . 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80F). 9.10 Ensure 6” liners in mud pumps.  Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).  N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.  N/U 21-1/4” diverter “T”.  Knife gate, 16” diverter line.  Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).  Diverter line must be 75 ft from nearest ignition source  Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter.  Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure.  Ensure that the annular closes in less than 45 seconds (API Standard 64 3 rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include:  A prohibition on vehicle parking  A prohibition on ignition sources or running equipment  A prohibition on staged equipment or materials  Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 10.4 Rig & Diverter Orientation:  May change on location Page 13 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly:  Ensure BHA components have been inspected previously.  Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted.  Ensure TF offset is measured accurately and entered correctly into the MWD software.  GWD will be the primary gyro tool.  Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.  Drill string will be 5” 19.5# S-135.  Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.  Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well.  Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer.  Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.  Hold a safety meeting with rig crews to discuss:  Conductor broaching ops and mitigation procedures.  Well control procedures and rig evacuat ion  Flow rates, hole cleaning, mud cooling, etc.  Pump sweeps and maintain mud rheology to ensure effective hole cleaning.  Keep mud as cool as possible to keep from washing out permafrost.  Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate.  Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen  Slow in/out of slips and while tripping to keep swab and surge pressures low  Ensure shakers are functioning properly. Check for holes in screens on connections.  Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off.  Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates).  Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.  Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100- 2,400’ TVD (just below permafrost). Be prepared for hydrates:  Gas hydrates can be identified by the gas detector and a decrease in MW or ECD  Monitor returns for hydrates, checking pressurized & non-pressurized scales Page 14 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure  Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. F lowrates can also be reduced to prevent mud from belching over the bell nipple.  Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surfac e.  Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys.  Surface Hole AC:  There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary:  Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone  PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office.  Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.  Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losse s and strengthen the wellbore.  Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.  Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 ≤ 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP  Pump at full drill rate (400-600 gpm), and maximize rotation.  Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions  Monitor well for any signs of packing off or losses.  Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling.  If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 9-5/8” casing running equipment (CRT & Tongs)  Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.  Use BOL 2000 thread compound. Dope pin end only w/ paint brush.  R/U of CRT if hole conditions require.  R/U a fill up tool to fill casing while running if the CRT is not used.  Ensure all casing has been drifted to 8.5” on the location prior to running.  Note that 47# drift is 8.525”  Be sure to count t he total # of joints on the location before running.  Keep hole covered while R/U casing tools.  Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor  Ensure bypass baffle is correctly installed on top of float collar.  Ensure proper operation of float equipment while picking up.  Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 12.6 Continue running 9-5/8” surface casing  Fill casing while running using fill up line on rig floor.  Use BOL 2000 thread compound. Dope pin end only w/ paint brush.  Centralization:  1 centralizer every joint to ~ 1000’ MD from shoe  1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)  Verify depth of lowest Ugnu water sand for isolation with Geologist  Utilize a collar clamp until weight is sufficient to keep slips set properly.  Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions.  Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost .  Install centralizers over couplings on 5 joints below and 5 joints above stage tool.  Do not place tongs on ES cementer, this can cause damaged to the tool.  Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8” 21,440 ft -lbs 23,820 ft -lbs 26,200 ft -lbs Page 19 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Page 20 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 12.8 Continue running 9-5/8” surface casing  Centralizers: 1 centralizer every 3rd joint to 200’ from surface  Fill casing while running using fill up line on rig floor.  Use BOL 2000 thread compound. Dope pin end only w/ paint brush.  Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface  Ensure drifted to 8.525” Page 21 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT . Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming c ement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.  How to handle cement returns at surface. Ensure vac trucks are on standby and ready t o assist.  Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump.  Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.  Positions and expectations of personnel involved with the ce menting operation. i. Extra hands in the pits to strap during the cement job to identify any losses  Review test reports and ensure pump times are acceptable.  Co nduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test . 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Page 23 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop to p plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer.  Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,500’ x 0.0732 bpf + (6,231’-120’-2,500) x 0.0758 bpf = 456.8 bbls 80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 24 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 13.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig co mponents, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Second Stage Surface Cement Job: 13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. 13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.19 Fill surface lines with water and pressure test. 13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.21 Mix and pump cmt per below recipe for the 2nd stage. 13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However ce ment will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.25 Displacement calculation: 2500’ x 0.0732 bpf = 183.0 bbls mud Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 26 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips. 13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez:  Pre flush type, volume (bbls) & weight (ppg)  Cement slurry type, lead or tail, volume & weight  Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration  Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid  Note if casing is reciprocated or rotated during the job  Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold  Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure  Note if pre flush or cement returns at surface & volume  Note time cement in place  Note calculated top of cement  Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows:  BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate  Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity, blind ram in bottom cavity.  Single ram can be dressed with 2-7/8” x 5” VBRs  NU bell nipple, install flowline.  Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross).  Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.  Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints  Test 2-7/8” x 5” rams with the 4-1/2” and 5” test joints  Confirm test pressures with PTD  Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug  Once BOPE test is complete, send a copy of the test report t o town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5” liners in mud pumps. Page 28 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage too l. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA.  Ensure BHA components have been inspected previously.  Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted.  Ensure TF offset is measured accurately and entered correctly into the MWD software.  Ensure MWD is RU and operational.  Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below.  Drill string will be 5” 19.5# S-135 NC50.  Run a ported float in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 Page 29 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 15.10 8-1/2” hole section mud program summary:  Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW.  Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible.  Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning  Run the centrifuge continuously while drilling the production hole, this will help with solids removal.  Dump and dilute as necessary to keep drilled solids to an absolute minimum.  MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 30 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.14 Begin drilling 8-1/2” hole section, o n-bottom staging technique:  Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.  Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations  If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and rest art on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.  Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM  RPM: 120+  Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection.  Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low  Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection  Monitor Torque and Drag with pumps on every 5 stands  Monitor ECD, pump pressure & hookload trends for hole cleaning indication  Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time.  Use ADR to stay in section. Reservoir plan is to stay in OA sand.  Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur.  Target ROP is as fast as we can clean the hole without having to backream connections  Schrader Bluff OA Concretions: 4-6% Historically  MPD will be utilized to monitor pressure build up on connections.  8-1/2” Lateral A/C:  I-19L1 has a clearance factor of 0.104. I-19L1 is a reservoir abandoned leg (abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE risk due to a collision.  I-22 WP03 has a clearance factor of 0.652. This is a plan that will not be drilled prior to I-29. There is no HSE risk.  J-08 has a clearance factor of 0.199. J-08 was abandoned as part of the J-08A sidetrack in 1999. There is no HSE risk associated with a collision.  J-08A has a clearance factor of 0.586. J-08A is a Schrader Bluff producer that has been shut-in since 2017. There is no HSE risk due to a collision. Page 31 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 15.15 Reference: Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure.  Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells.  If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side.  Attempt to lowside in a fast drilling interval wher e the wellbore is headed up.  Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes.  Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed  Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary  If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displa ce out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + liner volume with viscosified brine.  Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb  Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. Page 32 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 15.15 Mo nitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe  Circulate at full drill rate (less if losses are seen, 350 GPM min imum).  Rotate at maximum RPM that can be sustained.  Pulling speed 5 – 10 min/stand (slip to slip t ime, not including connections), adjust as dictated by hole conditions  When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well fo r flow/pressure build up with MPD . Increase fluid weight if necessary.  Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise  If necessary, increase MW at shoe for any higher than expected pressure seen  Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on T OOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 16.0 Run 5-1/2” x 4-1/2” Screened Liner NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1 Well control preparedness: In the event of an influx of formatio n fluids while running the 4- 1/2” screened liner, the following well control response procedure will be followed:  P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 5-1/2” screened liner.  P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” screened liner.  Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.  Proceed with well kill operations. 16.2 R/U 4-1/2” liner running equipment.  Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV.  Ensure all casing has been drifted on the deck prior to running.  Be sure to count the total # of joints on the deck before running.  Keep hole covered while R/U casing tools.  Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.3 Run 4-1/2” screened production liner until XO point for 5-1/2” screens (planning 2,000’ of 5- 1/2” on top of liner)  Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens  Utilize a collar clamp until weight is sufficient to keep slips set properly.  Use lift nubbins and st abbing guides for the liner run.  Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids)  Install screen joints as per the Running Order (From Completion Engineer post TD). o Do not place tongs or slips on screen joints o Screen placement ±40’ o The screen connection is 4-1/2” 13.5# Hydril 625  If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while runnin g inner string.  Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 34 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 5-1/2” 20# L-80 EZGO HT Torque OD Minimum Optimum Maximum 5-1/2 6,997 ft -lbs 10,728 ft -lbs 4-1/2” 13.5# L-80 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 35 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Page 36 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9 -5/8” casing. Ensure hanger/pkr will not be set in a 9-5/8” connection.  AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner. 16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary.  Ensure 5” DP/HWDP has been drifted  There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered dur ing RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. Page 37 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4 ,500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 38 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 17.0 Run 7” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment. 17.2 RU 7” casing handling equipment.  Ensure XO to DP made up to FOSV and ready on rig floor.  Rig up computer torque monitoring service.  String should stay full while running, RU fill up line and check as appropriate. 17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9 -5/8” x 7” annulus. 17.4 MU first joint of 7” to seal assy. 17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7”, 26#, L-80, TXP = Casing OD Torque (Min) Torque (Opt) Torque (Max) Torque (Operating) 7” 13,280 ft -lbs 14,750 ft -lbs 16,230 ft-lbs 20,000 ft -lbs Page 39 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Page 40 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 17.7 MU 7” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7” joints. 17.13 Space out with pups as needed to leave the no-go 1 ft above fully no -go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.14 PU and MU the 7” casing hanger. 17.15 Ensure circulation is possible through 7” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7” tieback seal assembly). 17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 RD casing running tools. 17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted. Page 41 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 18.0 Run Upper Completion – Jet Pump 18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.  Ensure wear bushing is pulled.  Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 crossover is on rig floor and M/U to FOSV.  Ensure all tubing has been drifted in the pipe shed prior to running.  Be sure to count the total # of joints in the pipe shed before running.  Keep hole covered while RU casing tools.  Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.  Monitor displacement from wellbore while RIH. 18.2 PU, MU and RH with the following 4-1/2” JP completion (confirm tally with Operations Engineer):  WLEG/Mule shoe  XX joints, 4-1/2”, 12.6#, L-80, TXP  Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin  Nipple, 3.813” XN profile (3.750” no -go), 4-1/2”, TXPM (RHC plug body installed)  Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin  1 joint, 4-1/2”, 12.6#, L-80, TXP  Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin  Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II  Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin  1 joint, 4-1/2”, 12.6#, L-80, TXP  Pup joint, 4-1/2”, 12.6#, L-80, TXP  Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin  Ported Pressure Sub, 4-1/2”, 12.6#, L-80, EUE 8rd  Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin  Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP  Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin  Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd  Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin  Pup joint, 4-1/2”, 12.6#, L-80, TXP  XXX joints, 4-1/2”, 12.6#, L-80, TXP 18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused control line ports are dummied off. Page 42 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 Land the tubing hanger and RILDS. Lay down the landing joint. 18.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.7 NU the tubing head adapter and NU the tree. 18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.9 Pull the plug off tool and BPV. 18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect to 2,500’ MD. 18.11 Drop the ball & rod. 18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30 minutes (charted). 18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed both the IA and tubing to 0 psi. 18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.15 RDMO Page 43 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 44 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 45 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 21.0 Wellhead Schematic Page 46 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 22.0 Days Vs Depth Page 47 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 23.0 Formation Tops & Information Page 48 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure Page 49 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates are generally not seen on I-pad. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates , but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non- pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste s tream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM ’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation aft er slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C:  There are no wells with a clearance factor of <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations b etween surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. Page 50 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I- 04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I -15 in 2009. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning auto matic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 51 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maint. circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are six planned fault crossings for I-29. The maximum expected throw for a fault is 62’ on the fault crossed in the heel of the well. H2S: Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I- 04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I -15 in 2009. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if ne cessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC:  I-19L1 has a clearance factor of 0.104. I-19L1 is a reservoir abandoned leg (abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE risk due to a collision.  I-22 WP03 has a clearance factor of 0.652. This is a plan that will not be drilled prior to I-29. There is no HSE risk.  J-08 has a clearance factor of 0.199. J-08 was abandoned as part of the J-08A sidetrack in 1999. There is no HSE risk associated with a collision.  J-08A has a clearance factor of 0.586. J-08A is a Schrader Bluff producer that has been shut-in since 2017. There is no HSE risk due to a collision. Page 52 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 25.0 Doyon 14 Rig Layout Page 53 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing t est and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 54 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 27.0 Doyon 14 Rig Choke Manifold Schematic Page 55 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 28.0 Casing Design Page 56 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 57 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 58 Milne Point Unit I-29 SB Producer PTD Application Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Manger Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-29 Hilcorp North Slope, LLC Permit to Drill Number: 222-006 Surface Location: 2327’ FSL, 3654’ FEL, SEC. 33, T13N, R10E, UM, AK Bottomhole Location: 2020’ FNL, 1234’ FWL, SEC. 21, T12N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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 AOGCCwithin 90days 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 January, 2022. 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(QVXUHWKDWFDVLQJWHVWDQGVXEVHTXHQW),7WHVWVDUHUHFRUGHGRQWKHVDPHFKDUW'RFXPHQWLQFUHPHQWDO YROXPHSXPSHGDQGUHWXUQHGGXULQJWHVW 3DJH Milne Point Unit I-29 SB Producer PTD Application 'R\RQ5LJ&KRNH0DQLIROG6FKHPDWLF 3DJH Milne Point Unit I-29 SB Producer PTD Application &DVLQJ'HVLJQ 3DJH Milne Point Unit I-29 SB Producer PTD Application ´+ROH6HFWLRQ0$63 '/% 3DJH Milne Point Unit I-29 SB Producer PTD Application 6SLGHU3ORW1$'*RYHUQPHQWDO6HFWLRQV 3DJH Milne Point Unit I-29 SB Producer PTD Application 6XUIDFH3ODW$V%XLOW1$' 6WDQGDUG3URSRVDO5HSRUW -DQXDU\ 3ODQ038,ZSD +LOFRUS$ODVND//& 0LOQH3RLQW 03W,3DG 3ODQ038, 038, 0650130019502600325039004550True Vertical Depth (1300 usft/in)-1300 -650 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 7150 7800 8450 9100 9750 10400 11050 11700Vertical Section at 8.00° (1300 usft/in)MPI-29 wp06 tgt 10 LMPI-29 wp06 tgt 11 LMPI-29 wp06 tgt 12 LMPI-29 wp06 tgt 13 UMPI-29 wp06 tgt 14 UMPI-29 wp06 tgt 15 UMPI-29 wp06 tgt 16 UMPI-29 wp06 tgt 17 LMPI-29 wp06 tgt 18 LMPI-29 wp06 tgt 19 LMPI-29 wp06 tgt 20 UMPI-29 wp06 tgt 21 UMPI-29 wp06 tgt 22 UMPI-29 wp06 tgt 23 LMPI-29 wp06 tgt 24 LMPI-29 wp06 tgt 25 LMPI-29 wp06 tgt 26 LMPI-29 wp06 tgt 27 UMPI-29 wp06 tgt 28 UMPI-29 wp06 tgt 29 UMPI-29 wp06 tgt 30 UMPI-29 wp06 tgt 31 LMPI-29 wp06 tgt 32 LMPI-29 wp07 tgt OA topMPI-29 wp07 tgt 01 UMPI-29 wp07 tgt 02 LMPI-29 wp06 tgt 03 UMPI-29 wp07 tgt 04 UMPI-29 wp06 tgt 05 UMPI-29 wp06 tgt 06 UMPI-29 wp06 tgt 08 LMPI-29 wp06 tgt 07 LMPI-29 wp06 tgt 09 LMPI-29 Interp9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015500160001650016535MPU I-29 wp08aStart Dir 3º/100' : 257.5' MD, 257.5'TVDStart Dir 4º/100' : 557.5' MD, 556.27'TVDEnd Dir : 1107.5' MD, 1074.64' TVDStart Dir 4.25º/100' : 1507.5' MD, 1430.73'TVDEnd Dir : 1918.5' MD, 1762.86' TVDStart Dir 4.5º/100' : 2818.45' MD, 2404.9'TVDFault #1End Dir : 5165.61' MD, 3835.65' TVDStart of ESP Pump TangentEnd of ESP Pump TangentStart Dir 4º/100' : 5465.61' MD, 3877.4'TVDEnd Dir : 5496.88' MD, 3881.45' TVDStart Dir 4º/100' : 6053.87' MD, 3948.25'TVDStart Dir 2º/100' : 6230.59' MD, 3960.4'TVDEnd Dir : 6399.49' MD, 3958.37' TVDStart Dir 2.5º/100' : 6610.16' MD, 3949.63'TVDEnd Dir : 6853.48' MD, 3951.6' TVDStart Dir 2.5º/100' : 6968.29' MD, 3957.45'TVDEnd Dir : 7143.4' MD, 3961.08' TVDStart Dir 2º/100' : 7368.4' MD, 3958.92'TVDEnd Dir : 7548.94' MD, 3962.87' TVDStart Dir 2º/100' : 7650.79' MD, 3968.31'TVDEnd Dir : 7832.94' MD, 3972.47' TVDStart Dir 2º/100' : 8232.94' MD, 3969.4'TVDEnd Dir : 8306.13' MD, 3969.77' TVDStart Dir 2º/100' : 8612' MD, 3975.2'TVDEnd Dir : 8710.28' MD, 3977.38' TVDStart Dir 2º/100' : 9160.28' MD, 3989.4'TVDEnd Dir : 9213.84' MD, 3991.24' TVDStart Dir 2º/100' : 9467.68' MD, 4001.95'TVDEnd Dir : 9486.61' MD, 4002.7' TVDStart Dir 2º/100' : 9836.61' MD, 4015.4'TVDEnd Dir : 10069.2' MD, 4015.02' TVDStart Dir 2º/100' : 10099.29' MD, 4013.83'TVDEnd Dir : 10327.84' MD, 4013.58' TVDStart Dir 2º/100' : 10697.84' MD, 4027.4'TVDEnd Dir : 10839.7' MD, 4031.9' TVDStart Dir 2º/100' : 10923.98' MD, 4034.1'TVDEnd Dir : 11109.59' MD, 4037.39' TVDStart Dir 2º/100' : 11759.59' MD, 4043.4'TVDEnd Dir : 11836.89' MD, 4045.01' TVDStart Dir 2.04º/100' : 12273.11' MD, 4059.19'TVDEnd Dir : 12516.43' MD, 4057.08' TVDStart Dir 2.04º/100' : 12537.84' MD, 4056.02'TVDEnd Dir : 12731.37' MD, 4053.04' TVDStart Dir 2.5º/100' : 13381.37' MD, 4065.4'TVDEnd Dir : 13594.13' MD, 4079.31' TVDStart Dir 2.5º/100' : 13624.47' MD, 4082.69'TVDEnd Dir : 13814.42' MD, 4096.05'TVDStart Dir 2º/100' : 13964.42' MD, 4100.4'TVDEnd Dir : 14022.21' MD, 4101.49' TVDStart Dir 2º/100' : 14579.93' MD, 4106.4'TVDEnd Dir : 14752.24' MD, 4102.74' TVDStart Dir 2º/100' : 14781.47' MD, 4101.24'TVDEnd Dir : 15053.57' MD, 4100.19' TVDStart Dir 2º/100' : 15333.57' MD, 4112.4'TVDEnd Dir : 15348.71' MD, 4113.02' TVDStart Dir 2º/100' : 15607.37' MD, 4122.97'TVDEnd Dir : 15627.32' MD, 4123.67' TVDStart Dir 2º/100' : 15902.32' MD, 4132.4'TVDEnd Dir : 16060.22' MD, 4141.76' TVDStart Dir 2º/100' : 16105.6' MD, 4145.7'TVDEnd Dir : 16315.47' MD, 4156.29' TVDTotal Depth : 16535.47' MD, 4159.4' TVDSV5BPRFSV0UG3UG COAL1LA3UG MBUG MDUG MESB NASB NBSB NCSB NESB OASB OA (2) post-Fault 1Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU I-2933.70+N/-S+E/-WNorthingEastingLatitudeLongitude0.000.006009442.87551717.4270° 26' 11.558 N149° 34' 42.021 WSURVEY PROGRAMDate: 2022-01-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1125.00 MPU I-29 wp08a (MPU I-29) GYD_Quest GWD1125.00 6231.00 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+Sag6231.00 16535.47 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1350.53 1283.13 1417.41 SV51786.62 1719.22 1951.81 BPRF2195.89 2128.49 2525.48 SV02746.25 2678.85 3268.29 UG32944.42 2877.02 3518.90 UG COAL13273.19 3205.79 3951.79 LA33510.27 3442.87 4311.31 UG MB3561.85 3494.45 4401.04 UG MD3642.03 3574.63 4555.27 UG ME3734.00 3666.60 4770.17 SB NA3758.50 3691.10 4839.88 SB NB3790.73 3723.33 4946.83 SB NC3814.09 3746.69 5043.37 SB NE3877.34 3809.94 5465.18 SB OA3938.55 3871.15 5973.01 SB OA (2) post-Fault 1REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 D14 as built RKB @ 67.40usftMeasured Depth Reference:MPU I-29 D14 as built RKB @ 67.40usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-29Wellbore:MPU I-29Design:MPU I-29 wp08aCASING DETAILSTVD TVDSS MD SizeName3960.41 3893.01 6231.00 9-5/8 9 5/8" x 12 1/4"4159.40 4092.00 16535.47 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 257.50 0.00 0.00 257.50 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 257.5' MD, 257.5'TVD3 557.50 9.00 200.00 556.27 -22.10 -8.04 3.00 200.00 -23.00 Start Dir 4º/100' : 557.5' MD, 556.27'TVD4 907.50 22.24 218.63 892.76 -99.96 -59.02 4.00 30.00 -107.205 1107.50 27.10 233.98 1074.64 -156.41 -119.60 4.00 60.00 -171.53 End Dir : 1107.5' MD, 1074.64' TVD6 1507.50 27.10 233.98 1430.73 -263.57 -266.96 0.00 0.00 -298.16 Start Dir 4.25º/100' : 1507.5' MD, 1430.73'TVD7 1918.50 44.49 236.92 1762.86 -398.27 -464.86 4.25 6.87 -459.09 End Dir : 1918.5' MD, 1762.86' TVD8 2818.45 44.49 236.92 2404.90 -742.51 -993.24 0.00 0.00 -873.52 Start Dir 4.5º/100' : 2818.45' MD, 2404.9'TVD9 5165.61 82.00 359.00 3835.65 277.12 -2007.50 4.50 119.40 -4.97 End Dir : 5165.61' MD, 3835.65' TVD10 5465.61 82.00 359.00 3877.40 574.16 -2012.68 0.00 0.00 288.46 MPI-29 wp07 tgt OA top End of ESP Pump Tangent11 5496.88 83.11 359.58 3881.45 605.16 -2013.07 4.00 27.20 319.10 End Dir : 5496.88' MD, 3881.45' TVD12 6053.87 83.11 359.58 3948.25 1158.12 -2017.16 0.00 0.00 866.11 Start Dir 4º/100' : 6053.87' MD, 3948.25'TVD13 6230.59 89.00 3.50 3960.40 1334.25 -2012.41 4.00 33.78 1041.19 MPI-29 wp07 tgt 02 L Start Dir 2º/100' : 6230.59' MD, 3960.4'TVD14 6399.49 92.38 3.53 3958.37 1502.79 -2002.06 2.00 0.48 1209.53 End Dir : 6399.49' MD, 3958.37' TVD15 6610.16 92.38 3.53 3949.63 1712.88 -1989.11 0.00 0.00 1419.38 Start Dir 2.5º/100' : 6610.16' MD, 3949.63'TVD16 6770.63 88.50 2.50 3948.40 1873.09 -1980.67 2.50 -165.14 1579.21 MPI-29 wp07 tgt 04 U17 6853.48 87.08 0.99 3951.60 1955.83 -1978.15 2.50 -133.44 1661.49 End Dir : 6853.48' MD, 3951.6' TVD18 6968.29 87.08 0.99 3957.45 2070.47 -1976.16 0.00 0.00 1775.30 Start Dir 2.5º/100' : 6968.29' MD, 3957.45'TVD19 7143.40 90.55 3.66 3961.08 2245.36 -1969.05 2.50 37.53 1949.47 End Dir : 7143.4' MD, 3961.08' TVD20 7318.40 90.55 3.66 3959.40 2420.00 -1957.88 0.00 0.00 2123.96 MPI-29 wp06 tgt 05 U21 7368.40 90.55 3.66 3958.92 2469.89 -1954.69 0.00 0.00 2173.82 Start Dir 2º/100' : 7368.4' MD, 3958.92'TVD22 7548.94 86.94 3.76 3962.87 2649.99 -1943.01 2.00 178.45 2353.78 End Dir : 7548.94' MD, 3962.87' TVD23 7650.79 86.94 3.76 3968.31 2751.47 -1936.35 0.00 0.00 2455.20 Start Dir 2º/100' : 7650.79' MD, 3968.31'TVD24 7832.94 90.44 4.77 3972.47 2933.03 -1922.81 2.00 16.15 2636.88 End Dir : 7832.94' MD, 3972.47' TVD25 8232.94 90.44 4.77 3969.40 3331.64 -1889.55 0.00 0.00 3036.24 MPI-29 wp06 tgt 08 L Start Dir 2º/100' : 8232.94' MD, 3969.4'TVD26 8306.13 88.98 4.63 3969.77 3404.58 -1883.55 2.00 -174.59 3109.31 End Dir : 8306.13' MD, 3969.77' TVD27 8612.00 88.98 4.63 3975.20 3709.41 -1858.85 0.00 0.00 3414.60 Start Dir 2º/100' : 8612' MD, 3975.2'TVD28 8710.28 88.47 6.53 3977.38 3807.19 -1849.30 2.00 105.14 3512.77 End Dir : 8710.28' MD, 3977.38' TVD29 9160.28 88.47 6.53 3989.40 4254.11 -1798.14 0.00 0.00 3962.46 MPI-29 wp06 tgt 10 L Start Dir 2º/100' : 9160.28' MD, 3989.4'TVD30 9213.84 87.58 7.13 3991.24 4307.26 -1791.78 2.00 146.01 4015.97 End Dir : 9213.84' MD, 3991.24' TVD31 9467.68 87.58 7.13 4001.95 4558.91 -1760.30 0.00 0.00 4269.56 Start Dir 2º/100' : 9467.68' MD, 4001.95'TVD32 9486.61 87.92 7.30 4002.70 4577.67 -1757.92 2.00 26.77 4288.47 End Dir : 9486.61' MD, 4002.7' TVD33 9836.61 87.92 7.30 4015.40 4924.61 -1713.48 0.00 0.00 4638.21 MPI-29 wp06 tgt 12 L Start Dir 2º/100' : 9836.61' MD, 4015.4'TVD3410069.20 92.27 8.96 4015.02 5154.80 -1680.60 2.00 20.92 4870.74 End Dir : 10069.2' MD, 4015.02' TVD3510099.29 92.27 8.96 4013.83 5184.50 -1675.91 0.00 0.00 4900.80 Start Dir 2º/100' : 10099.29' MD, 4013.83'TVD3610327.84 87.86 10.18 4013.58 5409.81 -1637.92 2.00 164.52 5129.21 End Dir : 10327.84' MD, 4013.58' TVD3710697.84 87.86 10.18 4027.40 5773.73 -1572.58 0.00 0.00 5498.68 MPI-29 wp06 tgt 15 U Start Dir 2º/100' : 10697.84' MD, 4027.4'TVD3810839.70 88.50 7.42 4031.90 5913.84 -1550.89 2.00 -76.94 5640.44 End Dir : 10839.7' MD, 4031.9' TVD3910923.98 88.50 7.42 4034.10 5997.38 -1540.02 0.00 0.00 5724.68 Start Dir 2º/100' : 10923.98' MD, 4034.1'TVD4011109.59 89.47 11.00 4037.39 6180.54 -1510.33 2.00 74.94 5910.19 End Dir : 11109.59' MD, 4037.39' TVD41 11759.59 89.47 11.00 4043.40 6818.57 -1386.31 0.00 0.00 6559.27 MPI-29 wp06 tgt 18 L Start Dir 2º/100' : 11759.59' MD, 4043.4'TVD4211836.89 88.14 10.22 4045.01 6894.53 -1372.08 2.00 -149.52 6636.48 End Dir : 11836.89' MD, 4045.01' TVD4312273.11 88.14 10.22 4059.19 7323.61 -1294.76 0.00 0.00 7072.14 MPI-29 Interp Start Dir 2.04º/100' : 12273.11' MD, 4059.19'TVD4412516.43 92.86 11.76 4057.08 7562.38 -1248.40 2.04 18.12 7315.04 End Dir : 12516.43' MD, 4057.08' TVD4512537.84 92.86 11.76 4056.02 7583.32 -1244.04 0.00 0.00 7336.38 Start Dir 2.04º/100' : 12537.84' MD, 4056.02'TVD4612731.37 88.91 11.91 4053.04 7772.68 -1204.36 2.04 177.81 7529.42 End Dir : 12731.37' MD, 4053.04' TVD4713381.37 88.91 11.91 4065.40 8408.57 -1070.25 0.00 0.00 8177.79 MPI-29 wp06 tgt 22 U Start Dir 2.5º/100' : 13381.37' MD, 4065.4'TVD4813594.13 83.59 11.89 4079.31 8616.23 -1026.49 2.50 -179.74 8389.52 End Dir : 13594.13' MD, 4079.31' TVD4913624.47 83.59 11.89 4082.69 8645.74 -1020.28 0.00 0.00 8419.60 Start Dir 2.5º/100' : 13624.47' MD, 4082.69'TVD5013814.42 88.34 11.91 4096.05 8831.10 -981.23 2.50 0.29 8608.59 End Dir : 13814.42' MD, 4096.05'TVD51 13964.42 88.34 11.91 4100.40 8977.81 -950.28 0.00 0.00 8758.18 MPI-29 wp06 tgt 24 L Start Dir 2º/100' : 13964.42' MD, 4100.4'TVD5214022.21 89.50 11.93 4101.49 9034.34 -938.35 2.00 0.85 8815.83 End Dir : 14022.21' MD, 4101.49' TVD5314579.93 89.50 11.93 4106.40 9580.00 -823.09 0.00 0.00 9372.21 MPI-29 wp06 tgt 26 L Start Dir 2º/100' : 14579.93' MD, 4106.4'TVD5414752.24 92.94 11.90 4102.74 9748.53 -787.54 2.00 -0.46 9544.06 End Dir : 14752.24' MD, 4102.74' TVD5514781.47 92.94 11.90 4101.24 9777.10 -781.52 0.00 0.00 9573.18 Start Dir 2º/100' : 14781.47' MD, 4101.24'TVD5615053.57 87.50 11.87 4100.19 10043.26 -725.50 2.00 -179.69 9844.55 End Dir : 15053.57' MD, 4100.19' TVD5715333.57 87.50 11.87 4112.40 10317.01 -667.96 0.00 0.00 10123.64 MPI-29 wp06 tgt 28 U Start Dir 2º/100' : 15333.57' MD, 4112.4'TVD5815348.71 87.80 11.81 4113.02 10331.82 -664.86 2.00 -11.61 10138.74 End Dir : 15348.71' MD, 4113.02' TVD5915607.37 87.80 11.81 4122.97 10584.82 -611.96 0.00 0.00 10396.64 Start Dir 2º/100' : 15607.37' MD, 4122.97'TVD6015627.32 88.18 11.92 4123.67 10604.33 -607.86 2.00 16.15 10416.53 End Dir : 15627.32' MD, 4123.67' TVD61 15902.32 88.18 11.92 4132.40 10873.27 -551.09 0.00 0.00 10690.75 MPI-29 wp06 tgt 30 U Start Dir 2º/100' : 15902.32' MD, 4132.4'TVD6216060.2285.02 11.97 4141.76 11027.45 -518.47 2.00 179.07 10847.97 End Dir : 16060.22' MD, 4141.76' TVD6316105.60 85.02 11.97 4145.70 11071.68 -509.09 0.00 0.00 10893.08 Start Dir 2º/100' : 16105.6' MD, 4145.7'TVD6416315.47 89.19 11.47 4156.29 11276.87 -466.53 2.00 -6.86 11102.19 End Dir : 16315.47' MD, 4156.29' TVD6516535.47 89.19 11.47 4159.40 11492.45 -422.78 0.00 0.00 11321.77 MPI-29 wp06 tgt 32 L Total Depth : 16535.47' MD, 4159.4' TVD -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 South(-)/North(+) (1500 usft/in)-4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 West(-)/East(+) (1500 usft/in) MPI-29 Interp MPI-29 wp06 tgt 09 L MPI-29 wp06 tgt 07 L MPI-29 wp06 tgt 08 L MPI-29 wp06 tgt 06 U MPI-29 wp06 tgt 05 U MPI-29 wp07 tgt 04 U MPI-29 wp06 tgt 03 U MPI-29 wp07 tgt 02 L MPI-29 wp07 tgt 01 U MPI-29 wp07 tgt OA top MPI-29 wp06 tgt 32 L MPI-29 wp06 tgt 31 L MPI-29 wp06 tgt 30 U MPI-29 wp06 tgt 29 U MPI-29 wp06 tgt 28 U MPI-29 wp06 tgt 27 U MPI-29 wp06 tgt 26 L MPI-29 wp06 tgt 25 L MPI-29 wp06 tgt 24 L MPI-29 wp06 tgt 23 L MPI-29 wp06 tgt 22 U MPI-29 wp06 tgt 21 U MPI-29 wp06 tgt 20 U MPI-29 wp06 tgt 19 L MPI-29 wp06 tgt 18 L MPI-29 wp06 tgt 17 L MPI-29 wp06 tgt 16 U MPI-29 wp06 tgt 15 U MPI-29 wp06 tgt 14 U MPI-29 wp06 tgt 13 U MPI-29 wp06 tgt 12 L MPI-29 wp06 tgt 11 L MPI-29 wp06 tgt 10 L 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 2505007501 0 0 0 1 2 5 0 1 5 0 017 502000225025002750300032503 5 0 0 3 7 5 0 4000 4159 MPU I-29 wp08a Start Dir 3º/100' : 257.5' MD, 257.5'TVD Start Dir 4º/100' : 557.5' MD, 556.27'TVD End Dir : 1107.5' MD, 1074.64' TVD Start Dir 4.25º/100' : 1507.5' MD, 1430.73'TVD End Dir : 1918.5' MD, 1762.86' TVD Start Dir 4.5º/100' : 2818.45' MD, 2404.9'TVD Fault #1 End Dir : 5165.61' MD, 3835.65' TVD Start of ESP Pump Tangent End of ESP Pump Tangent Start Dir 4º/100' : 5465.61' MD, 3877.4'TVD End Dir : 5496.88' MD, 3881.45' TVD Start Dir 4º/100' : 6053.87' MD, 3948.25'TVD Start Dir 2º/100' : 6230.59' MD, 3960.4'TVD End Dir : 6399.49' MD, 3958.37' TVD Start Dir 2.5º/100' : 6610.16' MD, 3949.63'TVD End Dir : 6853.48' MD, 3951.6' TVD Start Dir 2.5º/100' : 6968.29' MD, 3957.45'TVD End Dir : 7143.4' MD, 3961.08' TVD Start Dir 2º/100' : 7368.4' MD, 3958.92'TVD End Dir : 7548.94' MD, 3962.87' TVD Start Dir 2º/100' : 7650.79' MD, 3968.31'TVD End Dir : 7832.94' MD, 3972.47' TVD Start Dir 2º/100' : 8232.94' MD, 3969.4'TVD End Dir : 8306.13' MD, 3969.77' TVD Start Dir 2º/100' : 8612' MD, 3975.2'TVD End Dir : 8710.28' MD, 3977.38' TVD Start Dir 2º/100' : 9160.28' MD, 3989.4'TVD End Dir : 9213.84' MD, 3991.24' TVD Start Dir 2º/100' : 9467.68' MD, 4001.95'TVD End Dir : 9486.61' MD, 4002.7' TVD Start Dir 2º/100' : 9836.61' MD, 4015.4'TVD End Dir : 10069.2' MD, 4015.02' TVD Start Dir 2º/100' : 10099.29' MD, 4013.83'TVD End Dir : 10327.84' MD, 4013.58' TVD Start Dir 2º/100' : 10697.84' MD, 4027.4'TVD End Dir : 10839.7' MD, 4031.9' TVD Start Dir 2º/100' : 10923.98' MD, 4034.1'TVD End Dir : 11109.59' MD, 4037.39' TVD Start Dir 2º/100' : 11759.59' MD, 4043.4'TVD End Dir : 11836.89' MD, 4045.01' TVD Start Dir 2.04º/100' : 12273.11' MD, 4059.19'TVD End Dir : 12516.43' MD, 4057.08' TVD Start Dir 2.04º/100' : 12537.84' MD, 4056.02'TVD End Dir : 12731.37' MD, 4053.04' TVD Start Dir 2.5º/100' : 13381.37' MD, 4065.4'TVD End Dir : 13594.13' MD, 4079.31' TVD Start Dir 2.5º/100' : 13624.47' MD, 4082.69'TVD End Dir : 13814.42' MD, 4096.05'TVD Start Dir 2º/100' : 13964.42' MD, 4100.4'TVD End Dir : 14022.21' MD, 4101.49' TVD Start Dir 2º/100' : 14579.93' MD, 4106.4'TVD End Dir : 14752.24' MD, 4102.74' TVD Start Dir 2º/100' : 14781.47' MD, 4101.24'TVD End Dir : 15053.57' MD, 4100.19' TVD Start Dir 2º/100' : 15333.57' MD, 4112.4'TVD End Dir : 15348.71' MD, 4113.02' TVD Start Dir 2º/100' : 15607.37' MD, 4122.97'TVD End Dir : 15627.32' MD, 4123.67' TVD Start Dir 2º/100' : 15902.32' MD, 4132.4'TVD End Dir : 16060.22' MD, 4141.76' TVD Start Dir 2º/100' : 16105.6' MD, 4145.7'TVD End Dir : 16315.47' MD, 4156.29' TVD Total Depth : 16535.47' MD, 4159.4' TVD CASING DETAILS TVD TVDSS MD Size Name 3960.41 3893.01 6231.00 9-5/8 9 5/8" x 12 1/4" 4159.40 4092.00 16535.47 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt I Pad Well: Plan: MPU I-29 Wellbore: MPU I-29 Plan: MPU I-29 wp08a WELL DETAILS: Plan: MPU I-29 33.70 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 6009442.87 551717.42 70° 26' 11.558 N 149° 34' 42.021 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU I-29, 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Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU I-29 NAD 1927 (NADCON CONUS)Alaska Zone 0433.70+N/-S+E/-W NorthingEastingLatitudeLongitude0.000.006009442.87551717.4270° 26' 11.558 N149° 34' 42.021 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 D14 as built RKB @ 67.40usftMeasured Depth Reference:MPU I-29 D14 as built RKB @ 67.40usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-01-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1125.00 MPU I-29 wp08a (MPU I-29) GYD_Quest GWD1125.00 6231.00 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+Sag6231.00 16535.47 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)MPU I-22 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(NADCON CONUS)Alaska Zone 0433.70+N/-S +E/-W Northing EastingLatitude Longitude0.000.006009442.87551717.4270° 26' 11.558 N 149° 34' 42.021 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 D14 as built RKB @ 67.40usftMeasured Depth Reference:MPU I-29 D14 as built RKB @ 67.40usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-01-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1125.00 MPU I-29 wp08a (MPU I-29) GYD_Quest GWD1125.00 6231.00 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+Sag6231.00 16535.47 MPU I-29 wp08a (MPU I-29) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500Measured Depth (1100 usft/in)MPU I-22 wp03MPJ-08AMPJ-08GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 16535.47Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-29Wellbore: MPU I-29Plan: MPU I-29 wp08aCASING DETAILSTVD TVDSS MD Size Name3960.41 3893.01 6231.00 9-5/8 9 5/8" x 12 1/4"4159.40 4092.00 16535.47 4-1/2 4 1/2" x 8 1/2"Ladder / S.F. 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