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Home My WebLink About221-045MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Austin McLeod P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC S-46 MILNE PT UNIT S-46 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/22/2025 S-46 50-029-23695-00-00 221-045-0 W SPT 3988 2210450 1500 775 777 777 777 4YRTST P Austin McLeod 9/15/2025 MITIA. Monobore. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT S-46 Inspection Date: Tubing OA Packer Depth 314 1704 1642 1622IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM250915185230 BBL Pumped:0.8 BBL Returned:0.8 Wednesday, October 22, 2025 Page 1 of 1            MEMORANDUM TO: Jim Regg P.I. Supervisor I FROM: Matt Herrera Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, September 29, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC S-46 MILNE PT UNIT S-46 Src: Inspector Reviewed By: P.I. Supry JTIT Comm Well Name MILNE PT UNIT S-46 API Well Number 50-029-23695-00-00 Permit Number: 221-045-0 Insp Num: mitMFH210925135638 Rel Insp Num: Inspector Name' Matt Herrera Inspection Date: 9/25/2021 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well S46 Type Inj wVD 3988 Tubing 497 497 g 498 499 _ 0 2850 - 2210450 Type Test jTest si z500 �� IA P 2752 z7ls BBL Pumped: 5.1 BBL Returned: 4.8 OA 1 IntervalL INITAL PIF P f Notes: Initial MIT -IA performed to 2800 PSI per Operations (2500 PSI required per PTD). Monobore Completion No OA Wednesday, September 29, 2021 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23695-00-00Well Name/No. MILNE PT UNIT S-46Completion Status1WINJCompletion Date7/31/2021Permit to Drill2210450Operator Hilcorp Alaska, LLCMD14391TVD4070Current Status1WINJ9/16/2021UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF8/18/202195 14392 Electronic Data Set, Filename: MPU S-46 LWD FInal.las35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final MD.cgm35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final TVD.cgm35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 surveys.xlsx35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46_Definitive Survey Report.pdf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46_Definitive Survey Report.txt35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46_GIS.txt35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46_Plan.pdf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46_VSec.pdf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final MD.emf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final TVD.emf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final MD.pdf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final TVD.pdf35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final MD.tif35514EDDigital DataDF8/18/2021 Electronic File: MPU S-46 LWD Final TVD.tif35514EDDigital DataDF8/18/2021 Electronic File: EMFView3_1.zip35514EDDigital DataDF8/18/2021 Electronic File: Readme.txt35514EDDigital Data0 0 2210450 MILNE PT UNIT S-46 LOG HEADERS35514LogLog Header ScansThursday, September 16, 2021AOGCCPage 1 of 4PB1U S-46 LWD FInal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23695-00-00Well Name/No. MILNE PT UNIT S-46Completion Status1WINJCompletion Date7/31/2021Permit to Drill2210450Operator Hilcorp Alaska, LLCMD14391TVD4070Current Status1WINJ9/16/2021UICYes0 0 2210450 MILNE PT UNIT S-46 PB1 LOG HEADERS35515LogLog Header ScansDF8/18/202195 13525 Electronic Data Set, Filename: MPU S-46PB1 LWD FInal.las35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final MD.cgm35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final TVD.cgm35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1_Definitive Survey Report.pdf35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1_Definitive Survey Report.txt35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1_GIS.txt35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final MD.emf35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final TVD.emf35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final MD.pdf35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final TVD.pdf35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final MD.tif35515EDDigital DataDF8/18/2021 Electronic File: MPU S-46PB1 LWD Final TVD.tif35515EDDigital DataDF8/18/2021 Electronic File: EMFView3_1.zip35515EDDigital DataDF8/18/2021 Electronic File: Readme.txt35515EDDigital DataDF8/18/20215820 14354 Electronic Data Set, Filename: MPU S-46 ADR Quadrants All Curves.las35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Geosteering End of Well Report.docx35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Geosteering End of Well Report.pdf35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Geosteering EOW Plot.emf35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Geosteering EOW Plot.pdf35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Geosteering EOW Plot.tif35516EDDigital DataThursday, September 16, 2021AOGCCPage 2 of 4MPU S-46PB1LWD FInal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23695-00-00Well Name/No. MILNE PT UNIT S-46Completion Status1WINJCompletion Date7/31/2021Permit to Drill2210450Operator Hilcorp Alaska, LLCMD14391TVD4070Current Status1WINJ9/16/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud 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:7/31/2021Release Date:DF8/18/2021 Electronic File: MPU S-46 Geosteering EOW Plot300dpi.tif35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Post-Well Geosteering X-Section Summary.pdf35516EDDigital DataDF8/18/2021 Electronic File: MPU S-46 Post-Well Geosteering X-Section Summary.pptx35516EDDigital DataDF8/18/2021 Electronic File: MPU_S-46_Geosteering.dlis35516EDDigital DataDF8/18/2021 Electronic File: MPU_S-46_Geosteering.ver35516EDDigital Data0 0 2210450 MILNE PT UNIT S-46 LOG HEADERS35516LogLog Header ScansDF8/18/20215820 13486 Electronic Data Set, Filename: MPU S-46 PB1 ADR Quadrants All Curves.las35517EDDigital DataDF8/18/2021 Electronic File: MPU_S-46 PB1_Geosteering.dlis35517EDDigital DataDF8/18/2021 Electronic File: MPU_S-46 PB1_Geosteering.ver35517EDDigital Data0 0 2210450 MILNE PT UNIT S-46 PB1 LOG HEADERS35517LogLog Header ScansThursday, September 16, 2021AOGCCPage 3 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23695-00-00Well Name/No. MILNE PT UNIT S-46Completion Status1WINJCompletion Date7/31/2021Permit to Drill2210450Operator Hilcorp Alaska, LLCMD14391TVD4070Current Status1WINJ9/16/2021UICYesComments:Compliance Reviewed By:Date:Thursday, September 16, 2021AOGCCPage 4 of 4M. Guhl 9/16/2021 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 or fax to 907 564-4422. Received By: Date: Date: 8/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-46 + MPU S-46PB1 (PTD 221-045) FINAL LWD FORMATION EVALUATION LOGS (07/10/2021 to 07/27/2021) x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: Subfolders: Please include current contact information if different from above. 37' (6HW ceived By: 08/19/2021 By Abby Bell at 1:46 pm, Aug 18, 2021 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 or fax to 907 564-4422. Received By: Date: Date: 8/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-46 + MPU S-46PB1 (PTD 221-045) FINAL LWD FORMATION EVALUATION LOGS (07/10/2021 to 07/27/2021) x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: Subfolders: Please include current contact information if different from above. 37' (6HW Received By: 08/19/2021 By Abby Bell at 1:46 pm, Aug 18, 2021 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 or fax to 907 564-4422. Received By: Date: Date: 08/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-46 + MPU S-46PB1 (PTD 221-045) FINAL EOW REPORT – GEOSTEERING LOGS (07/17/2021 to 07/27/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. Received By: 08/18/2021 37' (6HW By Abby Bell at 1:43 pm, Aug 18, 2021 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 or fax to 907 564-4422. Received By: Date: Date: 08/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU S-46 + MPU S-46PB1 (PTD 221-045) FINAL EOW REPORT – GEOSTEERING LOGS (07/17/2021 to 07/27/2021) SFTP Transfer - Data Folders: Please include current contact information if different from above. 37' (6HW Received By: 08/19/2021 By Abby Bell at 1:43 pm, Aug 18, 2021 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: 37.8' 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 W indow MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 117' L-80 2,146' L-80 3,999' 6-5/8" L-80 4,070' 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 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 Slotted Liner8-1/2" TUBING RECORD Liner Top Packer 5,703'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): Stg 2 L - 623 sx / T - 270 sx 44" Surface 2,483' Stg 1 L - 448 sx / T - 400 sx 18.5 yds Concrete STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7/31/2021 3186' FSL, 663' FEL, Sec. 12, T12N, R10E, UM, AK 943' FNL, 661' FEL, Sec. 02, T12N, R10E, UM, AK 221-045 Milne Point Field / Schrader Bluff Oil Pool 64.01' 14,389' / 4,070' HOLE SIZE AMOUNT PULLED 50-029-23695-00-00 MPU S-46 565349 5999850 1843' FSL, 2584' FWL, Sec. 12, T12N, R10E, UM, AK CEMENTING RECORD 5998489 SETTING DEPTH TVD 6006235 BOTTOM TOP Surface Surface CASING WT. PER FT.GRADE 20# 563328 560014 TOP SETTING DEPTH MD Surface 5,686' Per 20 AAC 25.283 (i)(2) attach electronic information 40# 14,391' 2,146' 3,988' DEPTH SET (MD) 5,686' / 3,988' PACKER SET (MD/TVD) 129.5# 47# 117' 2,483' 5,834' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST Not on Injection Date of Test: Flow Tubing 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 ***Please see Schematic for Detail*** ROP, AGR, ABG, DGR, EWR, ADR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 7/27/2021 7/10/2021 ADL 380109 01-001 2,091' / 1,832' N/AN/A None 14,391' / 4,070' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:02 am, Aug 11, 2021 $'/ RBDMS HEW 8/12/2021 Completion Date 7/31/2021 HEW GDSR-8/16/21SFD 8/20/2021MGR16AUG2021 SFD 8/19/2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 41' 41' 2132' 1873' Top of Productive Interval 5754' 3995' 1562' 1421' 2638' 2265' 4299' 3535' 5599' 3979' 5754' 3995' 11802' 3979' 11970' 3990' 12518' 4048' 12705' 4070' SB NB (Fault) 12705' 4070' 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 NB Schrader Bluff NC Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top Schrader Bluff NA SV 5 SV 1 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. Schrader Bluff NF Formation at total depth: Ugnu LA3 LOT / FIT Data Sheet, Drilling and Completion Reports, Csg and Cmt Report, Definitive Directional Survey, 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 NB (Fault) Schrader Bluff ND 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 8.11.2021Digitally 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: 2021.08.11 08:36:08 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: JNL 8/5/21 SCHEMATIC Milne Point Unit Well: MPU S-46 PTD: 221-045 API: 50-029-23695-00-00 PLUGBACK DETAIL 4-1/2” 12.6# L-80 P&A kit ran and cemented – 12,445’ – 13,524’ in PB1 TD =14,391’(MD) / TD =4,070’(TVD) 20” Orig. KB Elev.:64.01’ / GL Elev.: 37.8’ 3-1/2” 6 2 9-5/8” 1 3/4 7 See Plugback Detail See Slotted Liner Detail PBTD =14,389’(MD) / PBTD =4,070’(TVD) 9-5/8” ‘ES’ Cementer @ 2,257’ Kickoff point @11,500’ 6-5/8” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,483’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,483’ 5,834’ 0.0758 6-5/8” Liner 20 / L-80 / Hyd 625 6.049” 5,686’ 14,391’ 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,703’ 0.0080 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,904’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,956’ XN Nipple Assy, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,693’ 8.25” No Go Locater Sub (2.16’ off No-go) 2.970” 4 5,694’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,686’ 9-5/8” SLZXP Liner Top Packer with DG slips 6.210” 6 5,707’ 7” x 6-5/8” XO 5.980” 7 14,389’ Shoe OPEN HOLE / CEMENT DETAIL 44” 18.5 yds Concrete 12-1/4"Stg 1 –Lead 448 sx / Tail 400 sx Stg 2 –Lead 623 sx / Tail 270 sx 8-1/2” Uncemented Slotted Liner WELL INCLINATION DETAIL KOP @ 245’ MD Max Hole Angle = 94° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23695-00-00 Completed by Innovation: 7/31/2021 4-1/2" 12.6# L-80 liner, Top at 12,508'MD, Shoe at 13,524' MD. Baker ECP above landing collar left at 12,430'MD. Page 2 of 2 JNL 8/5/2021 6-5/8” Slotted Liner Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 9,440’ 3,947’ 9,480’ 3,947’ 1 9,519’ 3,946’ 9,559’ 3,946’ 1 9,598’ 3,946’ 9,637’ 3,946’ 1 9,676’ 3,946’ 9,716’ 3,947’ 1 9,755’ 3,947’ 9,795’ 3,948’ 1 9,834’ 3,948’ 9,875’ 3,949’ 1 9,915’ 3,950’ 9,954’ 3,951’ 1 9,993’ 3,952’ 10,033’ 3,953’ 1 10,072’ 3,953’ 10,112’ 3,954’ 1 10,152’ 3,955’ 10,193’ 3,955’ 1 10,234’ 3,956’ 10,274’ 3,956’ 1 10,315’ 3,957’ 10,356’ 3,958’ 1 10,397’ 3,959’ 10,436’ 3,960’ 1 10,477’ 3,961’ 10,519’ 3,961’ 1 10,558’ 3,962’ 10,599’ 3,963’ 1 10,638’ 3,963’ 10,680’ 3,964’ 1 10,718’ 3,965’ 10,760’ 3,966’ 1 10,799’ 3,965’ 10,839’ 3,965’ 1 10,879’ 3,965’ 10,921’ 3,965’ 1 10,960’ 3,965’ 11,000’ 3,965’ 1 11,040’ 3,965’ 11,081’ 3,966’ 1 11,120’ 3,966’ 11,161’ 3,967’ 1 11,200’ 3,967’ 11,241’ 3,967’ 1 11,280’ 3,967’ 11,320’ 3,967’ 1 11,359’ 3,967’ 11,400’ 3,967’ 1 11,439’ 3,966’ 11,479’ 3,966’ 1 11,520’ 3,966’ 11,559’ 3,967’ 1 11,601’ 3,968’ 11,641’ 3,970’ 1 11,680’ 3,971’ 11,721’ 3,974’ 1 12,710’ 4,070’ 12,750’ 4,073’ 1 12,790’ 4,076’ 12,830’ 4,078’ 1 12,869’ 4,079’ 12,910’ 4,080’ 1 12,949’ 4,081’ 12,990’ 4,083’ 1 13,030’ 4,084’ 13,071’ 4,085’ 1 13,110’ 4,085’ 13,150’ 4,086’ 1 13,189’ 4,087’ 13,229’ 4,087’ 1 13,268’ 4,088’ 13,308’ 4,089’ 1 13,349’ 4,089’ 13,390’ 4,090’ 1 13,428’ 4,091’ 13,469’ 4,092’ 1 13,508’ 4,093’ 13,549’ 4,093’ 1 13,589’ 4,094’ 13,630’ 4,094’ 1 13,670’ 4,095’ 13,711’ 4,095’ 1 13,750’ 4,096’ 13,791’ 4,095’ 1 13,831’ 4,095’ 13,871’ 4,094’ 1 13,911’ 4,092’ 13,951’ 4,090’ 1 13,991’ 4,087’ 14,032’ 4,085’ 1 14,072’ 4,083’ 14,113’ 4,081’ 1 14,152’ 4,080’ 14,190’ 4,078’ 1 14,230’ 4,077’ 14,270’ 4,075’ 2 14,309’ 4,073’ 14,389’ 4,070’ Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 5,872’ 4,000’ 5,913’ 3,999’ 1 5,953’ 3,999’ 5,993’ 3,997’ 1 6,032’ 3,996’ 6,073’ 3,994’ 1 6,112’ 3,993’ 6,151’ 3,991’ 1 6,190’ 3,989’ 6,229’ 3,987’ 1 6,269’ 3,985’ 6,308’ 3,983’ 1 6,346’ 3,981’ 6,385’ 3,979’ 1 6,424’ 3,977’ 6,465’ 3,975’ 1 6,503’ 3,973’ 6,544’ 3,971’ 1 6,584’ 3,970’ 6,624’ 3,968’ 1 6,663’ 3,966’ 6,703’ 3,964’ 1 6,742’ 3,962’ 6,780’ 3,961’ 1 6,819’ 3,959’ 6,859' 3,958’ 1 6,899’ 3,956’ 6,938’ 3,954’ 1 6,978’ 3,953’ 7,017’ 3,951’ 1 7,056’ 3,949’ 7,096’ 3,948’ 1 7,135’ 3,947’ 7,175’ 3,946’ 1 7,214’ 3,945’ 7,255’ 3,945’ 1 7,294’ 3,946’ 7,334’ 3,946’ 1 7,374’ 3,947’ 7,414’ 3,947’ 1 7,453’ 3,948’ 7,492’ 3,948’ 1 7,532’ 3,948’ 7,573’ 3,948’ 1 7,613’ 3,949’ 7,652’ 3,950’ 1 7,691’ 3,950’ 7,732’ 3,951’ 1 7,772’ 3,952’ 7,812’ 3,952’ 1 7,852’ 3,952’ 7,892’ 3,952’ 1 7,931’ 3,952’ 7,971’ 3,952’ 1 8,010’ 3,952’ 8,051’ 3,952’ 1 8,091’ 3,953’ 8,132’ 3,953’ 1 8,171’ 3,953’ 8,212’ 3,953’ 1 8,251’ 3,954’ 8,292’ 3,955’ 1 8,331’ 3,956’ 8,372’ 3,958’ 1 8,412’ 3,959’ 8,453’ 3,960’ 1 8,492’ 3,961’ 8,533’ 3,962’ 1 8,571’ 3,962’ 8,612’ 3,962’ 1 8,652’ 3,962’ 8,690’ 3,962’ 1 8,729’ 3,962’ 8,769’ 3,961’ 1 8,808’ 3,961’ 8,849’ 3,960’ 1 8,888’ 3,958’ 8,927’ 3,957’ 1 8,966’ 3,956’ 9,007’ 3,954’ 1 9,046’ 3,953’ 9,085’ 3,952’ 1 9,125’ 3,952’ 9,164’ 3,951’ 1 9,203’ 3,951’ 9,243’ 3,951’ 1 9,282’ 3,950’ 9,322’ 3,949’ 1 9,361’ 3,949’ 9,401’ 3,948’ _____________________________________________________________________________________ Revised By: JNL 8/5/21 SCHEMATIC Milne Point Unit Well: MPU S-46 PTD: 221-045 API: 50-029-23695-00-00 PLUGBACK DETAIL 4-1/2” 12.6# L-80 P&A kit ran and cemented – 12,445’ – 13,524’ in PB1 TD =14,391’(MD) / TD =4,070’(TVD) 20” Orig. KB Elev.:64.01’ / GL Elev.: 37.8’ 3-1/2” 6 2 9-5/8” 1 3/4 7 See Slotted Liner Detail PBTD =14,389’(MD) / PBTD =4,070’(TVD) 9-5/8” ‘ES’ Cementer @ 2,257’ 6-5/8” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,483’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,483’ 5,834’ 0.0758 6-5/8” Liner 20 / L-80 / Hyd 625 6.049” 5,686’ 14,391’ 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 5,703’ 0.0080 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,904’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.992” 2 4,956’ XN Nipple Assy, 2.85” Bottom No-Go, 2.813” Packing Bore 2.750” 3 5,693’ 8.25” No Go Locater Sub (2.16’ off No-go) 2.970” 4 5,694’ Bullet Seals – TXP Top Box x Mule Shoe 6.160” Lower Completion 5 5,686’ 9-5/8” SLZXP Liner Top Packer with DG slips 6.210” 6 5,707’ 7” x 6-5/8” XO 5.980” 7 14,389’ Shoe OPEN HOLE / CEMENT DETAIL 44” 18.5 yds Concrete 12-1/4"Stg 1 –Lead 448 sx / Tail 400 sx Stg 2 –Lead 623 sx / Tail 270 sx 8-1/2” Uncemented Slotted Liner WELL INCLINATION DETAIL KOP @ 245’ MD Max Hole Angle = 94° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23695-00-00 Completed by Innovation: 7/31/2021 Superseded Page 2 of 2 JNL 8/5/2021 6-5/8” Slotted Liner Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 9,440’ 3,947’ 9,480’ 3,947’ 1 9,519’ 3,946’ 9,559’ 3,946’ 1 9,598’ 3,946’ 9,637’ 3,946’ 1 9,676’ 3,946’ 9,716’ 3,947’ 1 9,755’ 3,947’ 9,795’ 3,948’ 1 9,834’ 3,948’ 9,875’ 3,949’ 1 9,915’ 3,950’ 9,954’ 3,951’ 1 9,993’ 3,952’ 10,033’ 3,953’ 1 10,072’ 3,953’ 10,112’ 3,954’ 1 10,152’ 3,955’ 10,193’ 3,955’ 1 10,234’ 3,956’ 10,274’ 3,956’ 1 10,315’ 3,957’ 10,356’ 3,958’ 1 10,397’ 3,959’ 10,436’ 3,960’ 1 10,477’ 3,961’ 10,519’ 3,961’ 1 10,558’ 3,962’ 10,599’ 3,963’ 1 10,638’ 3,963’ 10,680’ 3,964’ 1 10,718’ 3,965’ 10,760’ 3,966’ 1 10,799’ 3,965’ 10,839’ 3,965’ 1 10,879’ 3,965’ 10,921’ 3,965’ 1 10,960’ 3,965’ 11,000’ 3,965’ 1 11,040’ 3,965’ 11,081’ 3,966’ 1 11,120’ 3,966’ 11,161’ 3,967’ 1 11,200’ 3,967’ 11,241’ 3,967’ 1 11,280’ 3,967’ 11,320’ 3,967’ 1 11,359’ 3,967’ 11,400’ 3,967’ 1 11,439’ 3,966’ 11,479’ 3,966’ 1 11,520’ 3,966’ 11,559’ 3,967’ 1 11,601’ 3,968’ 11,641’ 3,970’ 1 11,680’ 3,971’ 11,721’ 3,974’ 1 12,710’ 4,070’ 12,750’ 4,073’ 1 12,790’ 4,076’ 12,830’ 4,078’ 1 12,869’ 4,079’ 12,910’ 4,080’ 1 12,949’ 4,081’ 12,990’ 4,083’ 1 13,030’ 4,084’ 13,071’ 4,085’ 1 13,110’ 4,085’ 13,150’ 4,086’ 1 13,189’ 4,087’ 13,229’ 4,087’ 1 13,268’ 4,088’ 13,308’ 4,089’ 1 13,349’ 4,089’ 13,390’ 4,090’ 1 13,428’ 4,091’ 13,469’ 4,092’ 1 13,508’ 4,093’ 13,549’ 4,093’ 1 13,589’ 4,094’ 13,630’ 4,094’ 1 13,670’ 4,095’ 13,711’ 4,095’ 1 13,750’ 4,096’ 13,791’ 4,095’ 1 13,831’ 4,095’ 13,871’ 4,094’ 1 13,911’ 4,092’ 13,951’ 4,090’ 1 13,991’ 4,087’ 14,032’ 4,085’ 1 14,072’ 4,083’ 14,113’ 4,081’ 1 14,152’ 4,080’ 14,190’ 4,078’ 1 14,230’ 4,077’ 14,270’ 4,075’ 2 14,309’ 4,073’ 14,389’ 4,070’ Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 1 5,872’ 4,000’ 5,913’ 3,999’ 1 5,953’ 3,999’ 5,993’ 3,997’ 1 6,032’ 3,996’ 6,073’ 3,994’ 1 6,112’ 3,993’ 6,151’ 3,991’ 1 6,190’ 3,989’ 6,229’ 3,987’ 1 6,269’ 3,985’ 6,308’ 3,983’ 1 6,346’ 3,981’ 6,385’ 3,979’ 1 6,424’ 3,977’ 6,465’ 3,975’ 1 6,503’ 3,973’ 6,544’ 3,971’ 1 6,584’ 3,970’ 6,624’ 3,968’ 1 6,663’ 3,966’ 6,703’ 3,964’ 1 6,742’ 3,962’ 6,780’ 3,961’ 1 6,819’ 3,959’ 6,859' 3,958’ 1 6,899’ 3,956’ 6,938’ 3,954’ 1 6,978’ 3,953’ 7,017’ 3,951’ 1 7,056’ 3,949’ 7,096’ 3,948’ 1 7,135’ 3,947’ 7,175’ 3,946’ 1 7,214’ 3,945’ 7,255’ 3,945’ 1 7,294’ 3,946’ 7,334’ 3,946’ 1 7,374’ 3,947’ 7,414’ 3,947’ 1 7,453’ 3,948’ 7,492’ 3,948’ 1 7,532’ 3,948’ 7,573’ 3,948’ 1 7,613’ 3,949’ 7,652’ 3,950’ 1 7,691’ 3,950’ 7,732’ 3,951’ 1 7,772’ 3,952’ 7,812’ 3,952’ 1 7,852’ 3,952’ 7,892’ 3,952’ 1 7,931’ 3,952’ 7,971’ 3,952’ 1 8,010’ 3,952’ 8,051’ 3,952’ 1 8,091’ 3,953’ 8,132’ 3,953’ 1 8,171’ 3,953’ 8,212’ 3,953’ 1 8,251’ 3,954’ 8,292’ 3,955’ 1 8,331’ 3,956’ 8,372’ 3,958’ 1 8,412’ 3,959’ 8,453’ 3,960’ 1 8,492’ 3,961’ 8,533’ 3,962’ 1 8,571’ 3,962’ 8,612’ 3,962’ 1 8,652’ 3,962’ 8,690’ 3,962’ 1 8,729’ 3,962’ 8,769’ 3,961’ 1 8,808’ 3,961’ 8,849’ 3,960’ 1 8,888’ 3,958’ 8,927’ 3,957’ 1 8,966’ 3,956’ 9,007’ 3,954’ 1 9,046’ 3,953’ 9,085’ 3,952’ 1 9,125’ 3,952’ 9,164’ 3,951’ 1 9,203’ 3,951’ 9,243’ 3,951’ 1 9,282’ 3,950’ 9,322’ 3,949’ 1 9,361’ 3,949’ 9,401’ 3,948’ Superseded PB1 TD 13,524' MD / 4,142' TVD KOP 11,500' MD / 3,966' TVD Date 7/25/2021 MPU S-46 OH Sidetrack Summary PTD: 221-045 / API: 50-029-23695-70-00 Activity Date Ops Summary 7/8/2021 Continue to clean mud pits. Disconnect interconnects. Swap to cold starts. Continue to prep rig for move. NES on location at 03:00 Jack up and spot pipe shed, gen mod, mud mod and catwalk. Hook up D8 to sub. Jack up sub and pull off well (MP S-44). Lay mats and spot Sub over MP S-46. 7/9/2021 Spot Sub over well S-46 check for Level, spot cattle Chute, pipe shed and pit Mod check for level, spot gen mod, install out riggers and rig up Inner-connects. Trucks released @ 11:30. Rig up inner connects between gen and pit mod. Plug in electrical inner-connects and swap to gen power. Bring Air water and steam online, scope Derrick, R/D Bridle lines f/Top Drive, C/O Hyd filter and lube filter on Top Drive. Check for oil in J-Box on Top Drive.(Thin Film in Btm of J-Box) Work on rig acceptance checklist. Continue to work on rig acceptance checklist. NU Stack: Clean ring grooves, install new gaskets and torque to spec. Install companion flange on Kill line and plug valve. Install riser and bell nipple and center stack. Nipple up Diverter system: Install knife valve and 3 sticks of 16" diverter line. Bring on Spud mud to pits. Function test both mud pumps and pump through all centrifugal pumps. Rig accept checklist complete and rig accepted at 23:00 hrs. MU and rack back 93 stands of 5" drill pipe in derrick. Crane on location to place diverter anchor and last 70' of diverter vent line at 02:30 Strap 5" HWDP in shed. MU 7 stands of HWDP and jar stand and rack back in derrick. Make up Cleanout assy per DD: Bit, Motor, XO and 5" HWDP. 7/10/2021 Fill surface lines and PT to 250/3500 psi - no leaks. Function test diverter system while waiting for AOGCC rep to arrive. Grease crown and top drive. Troubleshoot and repair electrical issue with top drive. Repair damaged wires for the grid resister pressure switch. Perform diverter test with AOGCC rep Adam Earl witnessing. Knife valve open @ 5 sec, Annular close @10 sec. Preform Accumulator draw down. Test fire and gas alarms. Hold pre-spud meeting with rig crew Fill conductor with water and verify no leaks. Drill out conductor 10' and swap to spud mud. Drill from 107' md to 219' md with cleanout assy. 300-400 gpm, 500 psi, 40 rpm, 1.8k TRQ, 5k WOB. Control drill and very flow rate to manage thick mud. BROOH from 219' md to 97' md: 400 gpm, 450 psi, 40 rpm, 1k TRQ. Pull and inspect bit and motor assembly. Make up 12.25" Surface BHA per DD / MWD / Gyro: MU GWD, DM, EWR-M5, and TM - download tools and perform confidence test. MU 2 NM flex collars and std of HWDP and wash to bottom. Attempt to shallow hole test MWD/GWD tools - adjust pump parameters to manage thick mud - good detection. Slide / Rot 12.25" Surface hole per DD F/219' md to 1150' md (1101' TVD). Total 931' (AROP 77.6 fph). 500 GPM, 1414 psi, 40-60 rpm, TRQ on 4-5K, TRQ off 3K, F/O 63%, WOB 6-10K, MW in 8.9 ppg, ECD 9.67. P/U 76K, SLK 72K, ROT 74K. Jet flowline every stand. Daily Disposal to G&I = 342 bbls, total = 342 bbls. Daily Water from A-Pad Creek = 290 bbls. Total Water from A-Pad Creek = 580 bbls. Daily Water from S-Pad Creek = 190 bbls. Total Water from S-Pad Creek = 270 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 7/11/2021 Drill 12.25" surface hole per DD and WP09a F/1150' md T/1860' MD (1656' TVD), Total 710' (AROP 118.3 fph). 500 GPM, 1450 psi, 60 rpm, TRQ on 5-6K, TRQ off 3-4K, F/O 60%, WOB 5-10K, MW in 9.1 ppg, ECD 9.77, Max gas 176 units. P/U 88K, S/O 74K, ROT 84K. Backream full std prior to connections. Jet flow line with mud pumps at each connection. Drill 12.25" surface hole per DD and WP09a F/1860' md T/2552' MD (2199' TVD), Total 692' (AROP 115.3 fph). 500 GPM, 1380 psi, 60-80 rpm, TRQ on 5-7K, TRQ off 4-5K, F/O 65%, WOB 1-5K, MW in 9.4 ppg, ECD 10.11, Max gas 685 units. P/U 108K, S/O 81, ROT 91K. Backream full std at connections. Drill 12.25" surface hole per DD and WP09a F/2552' md T/3134' MD (2654' TVD), Total 582' (AROP 97 fph). 500 GPM, 1600 psi, 80 rpm, TRQ on 6-8K, TRQ off 5-7K, F/O 61%, WOB 3-6K, MW in 9.4 ppg, ECD 10.25, Max gas 337 units. P/U 118K, S/O 84, ROT 99K. Backream full std at connections. Drill 12.25" surface hole per DD and WP09a F/3134' md T/3720' MD (3125' TVD), Total 586' (AROP 97.7 fph). 500 GPM, 1650 psi, 80 rpm, TRQ on 8-9K, TRQ off 6-8K, F/O 64%, WOB 8-15K, MW in 9.2 ppg, ECD 10.11, Max gas 276 units. P/U 135K, S/O 90, ROT 106K. Backream full std at connections. Last Survey at 3651.48 MD, 3071.96' TVD, 39.38° Inc, 237.55° AZI. Distance from WP09a: 15.77' total, 15.21' high and 4.17' right of plan Daily disposal to G&I: 1368 bbl. Total disposal to G&I: 1725 bbl. Daily H2O from S-Pad Creek: 1300 bbl. Total H2O from S-Pad Creek: 1570 bbl . Daily H2O from A-Pad: 0. Total H2O from A-Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl Total . Fluid Loss Surface: 0 bbl. 7/12/2021 Drill 12.25" surface hole per DD and WP09a F/3720' md T/4213' MD (3479' TVD), Total 493' (AROP 82.2 fph). 500 GPM, 1730 psi, 80 rpm, TRQ on 10K, TRQ off 9K, F/O 64%, WOB 5-12K, MW in 9.2 ppg, ECD 10.0, Max gas 251 units. P/U 145K, S/O 95, ROT 115K. Backream full std at connections. Drill 12.25" surface hole per DD and WP09a F/4213' md T/4969' MD (3759' TVD), Total 756' (AROP 126 fph). 500 GPM, 1730 psi, 80 rpm, TRQ on 10K, TRQ off 9K, F/O 64%, WOB 5- 12K, MW in 9.2 ppg, ECD 10.0, Max gas 251 units. P/U 145K, S/O 95, ROT 115K. Backream full std at connections. Drill 12.25" surface hole per DD and WP09a F/4969' md T/5103' MD (3915' TVD), Total 134' (AROP 22.3 fph). 500 GPM, 1630 psi, 60 rpm, TRQ on 10-12K, TRQ off 12.5K, F/O 68%, WOB 5-9K, MW in 9.2 ppg, Vis 73, ECD 9.81, Max gas 1887 units. P/U 156K, S/O 89, ROT 121K. Backream full std at connections. Drill 12.25" surface hole per DD and WP09a F/5103' md T/5358' MD (3958' TVD), Total 255' (AROP 102 fph). 500 GPM, 1800 psi, 60 rpm, TRQ on 13-14K, TRQ off 12-13K, F/O 63%, WOB 7-18K, MW in 9.2 ppg, Vis 73, ECD 10.0, Max gas 837 units. P/U 161K, S/O 89, ROT 114K. Backream full std at connections. Change out shaft seal on rod wash pump for MP #2 Drill 12.25" surface hole per DD and WP09a F/5358' md T/5550' MD (3974' TVD), Total 1915' (AROP 79.8 fph). 500 GPM, 1775 psi, 80 rpm, TRQ on 13-16K, TRQ off 12-14K, F/O 66%, WOB 7-18K, MW in 9.3 ppg, Vis 90, ECD 10.06, Max gas 628 units. P/U 155K, S/O 82, ROT 112K. Backream full std at connections. Last Survey at 5430.18 MD, 3964.45' TVD, 86.67° Inc, 301.48° AZI . Distance from WP09a: 12.70' total, 0.99' low and 12.66' right of plan Daily disposal to G&I: 1026 bbl. Total disposal to G&I: 2751 bbl. Daily H2O from S-Pad Creek: 1400 bbl. Total H2O from S-Pad Creek: 2970 bbl. Daily H2O from A-Pad: 0. Total H2O from A- Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Fluid Loss Surface: 0 bbl. 7/10/2021Spud Date: Well Name: Field: County/State: MP S-46 Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-23695-00-00API #: 7/13/2021 Drill 12.25" surface hole per DD and WP09a F/5547' md T/5844' MD (3999' TVD), Total 297' (AROP 66 fph). 500 GPM, 1870 psi, 80 rpm, TRQ on 14-15K, TRQ off 12-13K, F/O 66%, WOB 8-18K, MW in 9.3 ppg, Vis 90, ECD 10.06, Max gas 337 units. P/U 155K, S/O 82, ROT 112K. Backream full std at connections. Obtain final Survey. BROOH 2 stds to 5735'. Pump 40 bbld nut plug sweep @ 500 GPM/1600 PSI, 60 RPM, 12K TQ. Sweep back on time w/minimal increase at shakers. Cont circ and condition mud lower YP~20. Last Survey at 57.91 MD, 3997.76' TVD, 87.05° Inc, 300.38° AZI . Distance from WP09a: 28.47' total, 21 TIH on elevators back to Bottom, Tag on depth @ 5844'. Monitor Well, Static. BROOH from 5844' to 3006' @ 500 GPM/1475 PSI, 80 RPM, 10.5K TQ, PUW 144K, SOW 90K, Rot 114K. No issues BROOH to 3006'. Continue to BROOH from 3006' to 718' @ 500 GPM/1186 PSI, 60 RPM, 4K TQ, 20-35 fpm, PUW 87K, SOW 69K, Rot 79K. No issues BROOH. Swap to Gen power at 18:30. LD 7 jts of HWDP F/718' MD T/532' MD. 10K overpull at 650' MD. Work and wipe pipe w/ up to 14K over. POH at 3-4 bpm, 135-185 psi. and pull through with 10-15k overpull. Rotate through with 10 rpm, 1.5K TRQ. P/U 71K, S/O 70K. LD 12.25" Surface BHA. Rack back 5 stands of 5" HWDP and jars in derrick. LD 2 NM flex collars. Plug in and download per MWD. LD TM, DM, GWD and M5 collar per DD/MWD. Break bit and LD motor. Dull bit grade: 1-2-WT-A-X-1-CT-TD Clean and clear rig floor. Rig down tongs and place in storage position. RU to run 9-5/8" Surface casing. RD hydraulic elevators and swing ST-80 into storage position. Make up Volant CRT to top drive and RU bail extensions w/ side door elevators. Rig up power tongs and bring up centralizers to rig floor. MU and RIH with 9-5/8", 40#, L-80 Surface casing to 125' MD. MU shoe track and check floats - good. Fill casing and drop baffle by-pass. Daily disposal to G&I: 1086 bbl. Total disposal to G&I: 3837 bbl. Daily H2O from S-Pad Creek: 1120 bbl. Total H2O from S-Pad Creek: 4090 bbl. Daily H2O from A-Pad: 0. Total H2O from A-Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Fluid Loss Surface: 0 bbl. 7/14/2021 Continue RIH with 9-5/8", 40#/47# TXP BTC, L-80 Surface casing from 125' to 4630' MD @ 15-30 fpm. Tripped clean, minimal lossess. Wash down every 10 jts. Circulated btms up just below permafrost and @ 4515' MD to condition mud and mitigate potential losses. 114k dn, 235k up, 6 bpm, 260 psi Continue RIH with 9- 5/8", 40#/47# TXP BTC, L-80 Surface casing from 4630' to 5834' MD @ 15-30 fpm. Break circulation every 10 jts. MU last jt and wash down 6 bpm, 260 psi. 115k dn, 266k up. Total losses during trip: 55 bbls. Circulate and condition mud prior to cementing. Stage pumps up to 6 bpm, ICP 275 psi. FCP 165 psi. MW in/out =9.6 ppg. PU 268K, SO 114 K. Pumped a total of 818 bbls. Monitor well for 30 min prior to breaking diverter section for cement trucks - well static. Remove diverter section to get cement trucks spotted on other side of rig. Re-install diverter section and torque to spec after getting trucks through. Rig up cement hoses to Volant CRT, and break circulation staging up to 6 bpm, 405 psi through the cement line. Hold PJSM with rig crew, HES crew, Baroid & ASRC on 1st stage cement job. PU 266 K, SO 117 K. 1-3 rpm, 15 K TRQ. HES pump 5 bbls fresh water, 2 BPM, 80 PSI. PT lines to 1000 PSI low / 4000 PSI high. Mix & pump 62 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 5.7 BPM, 295 PSI. Drop by-pass plug. Mix & pump 188 bbls of 12.0 ppg lead cmt (448 sks @ 2.347^3/sk yield), 5.4 BPM, 403 PS Mix & pump 82 bbls of 15.8 ppg tail cmt (400 sks @ 1.15^3/sk yield), 5.4 BPM, 1034 PSI. Drop shut-off plug. Pump 20 bbls fresh water, 7.9 BPM, 537 PSI. Displace cmt with 231 bbls, 9.4 ppg spud mud with rig pumps 5.8 BPM, 485 PSI HES pump 95.8 bbls 9.4 ppg tuned spacer, 4.6 BPM, 559 PSI. Cont displace from rig 80.3 bbls, 4.8 bpm, 1000 psi. Reduce rate to 3 bpm, 970 psi. Plug bumped on @ 5270 stks FCP 1019 psi. CIP @ 05:10 Rot and recip string until 104 bbls into displacement. Work string down and set on depth. Pick up 60-80k over and unable to move up. Slack off and put string on depth, 5834' md. No losses recorded. Pressure to 1500 psi, hold for 5 min, Check floats - Holding. Verify able to Un-sting Volant CRT. Pressure to 2800 psi and observe ESC tool open. Establish circulation through ESC tool at 4 bpm, 1909-2500 psi. Reduce rate to 3 bpm, 855 psi and CBU. Daily disposal to G&I: 885 bbl. Total disposal to G&I: 4722 bbl. Daily H2O from S-Pad Creek: 420 bbl. Total H2O from S-Pad Creek: 4510 bbl. Daily H2O from A-Pad: 0. Total H2O from A-Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 55 bbl. Total Fluid Loss Surface: 55 bbl. 7/15/2021 Flush surface equipment with black water. Prep pits for 2nd stage cement job. WOC to ~500 psi. Circulate and condition mud via ES Cementer @ 2257' MD. 6 bpm, 250 psi, 43% flow. Surge rate to periodically to 7.5 bpm with no coagulated mud back to surface. String parked w/ 205k up. B/O and M/U CRT to ensure proper functioning prior to starting cement job. Stage call out trucks and ready HES cmt equipment. Perform 2nd stage cmt job. Mix & pump 60 bbls of of 10.0 ppg Tuned Spacer 4.6 BPM, 300 PSI. Mix & pump 320 bbls of 10.7 ppg ArcticCem Lead Cement 2.88 ft^3/sk yield, 623 sks, 5.3 BPM, 620 PSI. Interface back @ 300 bbls, dump to cutting box. Good cmt back @ 330 bbls" Mix and pump 56 bbls 15.8 ppg Premium G Tail Cement 1.169 ft^3/sk yield, 270 sks, 4.5 BPM, 650 PSI. Drop closing plug. HES pump 20 bbls water 7 BPM, 530 PSI. Displace w/ 144.1 bbls 9.4 ppg spud mud @ 6 BPM, 500 ICP / 1145 psi FCP. Slow to 3 BPM, 850 PSI for last 10 bbls. Bump plug at 2323 stks (22 stks early). Pressure up, ESC shifted close at 2200 PSI. CIP at 16:38. 221 bbls of cement, 30 bbls of interface with spacer returned to surface. Full returns throughout 2nd stage PJSM R/D cement lines and blow down to pits. R/D L/D CRT. Drain stack and flush W/ black H2O. Disconnect knife valve. Function Annular 3X. Flush stack again. SIMOPS Begin 4 bolt stack. Remove 20' diverter sections to allow Halliburton cementers Equip to leave location. PJSM R/D diverter section F/ Tee to catwalk. Bleed down Koomey. Loosen speed head. P/U stack W/ bridge cranes and center 9.625" Csg in conductor. Set emergency slips W/ 105K. Cut and L/D 9.625" Csg. (cut 29.43') Set down stack and Johnny whack W/ 50 bbls black H2O 8 bpm. 10 rpm. B/D TD. Drain stack. Pull mouse hole, riser, knife valve and disconnect floor drain hoses. Unbolt stack F/ Diverter Tee. and rack back. Clean solids out of Tee. SIMOPS Clean shakers, possum belly and TT 1 & 2. Clean suction pods on MP #1 & 2. Went on Gen power at 19:00. PJSM Remove Diverter Tee and speed head F/ conductor. Install RCD to BOP and torque. PJSM install T-103 and fill W/ plastic as per NOS rep. PT to 3,760 psi for 10 min. Install tubing spool and test plug. PT 500 psi/ 5 min, 5,000 psi/ 10 min. SIMOPS C/O Wash pipe on TD. PJSM Install riser spool. Bring BOP to well center and install 4" hard line to MPD. Daily to G&I: 2037 bbl. Total to G&I: 6759 bbl. Daily H2O S-Pad Creek: 980 bbl. Total H2O S-Pad Creek: 5490 bbl. Total H2O from A-Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Surface Loss: 55 bbl. 7/16/2021 Cont N/U BOPE. Set stack and trq. Secure turn buckles and install drip pan. Hook up koomey lines. Install choke and kill lines. Press koomey. Install 1502 flange on IA. RKB LDS 24.1, LPR 20.1, Blind 16.30, UPR 14.8, Ann 12.25. SIMOPS C/U Saver Sub. Fill all surface lines and pump through MPD. PT MPD 250/ 1,500 psi, good. Install test cap for RCD. PJSM Install RCD riser, air boot, flood stack and check for leaks, good. PJSM Perform BOPE test W/ 3.5" & 5" to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold 1-15, 5" Dart, 5" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, manual and Super Choke to 1,600 PSI (F/P), Upper and lower VRB Rams (2.875" X 5.5") Blind Rams (F/P) & Annular. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey draw drown Initial System 3,000 PSI, Manifold 1,500 PSI, Annular 1,200 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,300 PSI. 200 PSI increase 23 Sec, full charge 98 sec. Nitrogen 6 bottle bottle average 2,308 PSI. Witnessed by AOGCC Rep Adam Earl. F/P Blinds has slow leak refunction, good. Super Choke replaced key stock on actuator. PJSM Pull test plug and install wear ring (10.75" OD ID 9" Lng 38"). R/D test joint and blow down. PJSM P/U M/U RR 8.5" Tri Cone, 1.5° Mud Motor 6 ea 5" HWDP, SLB 6.75" Jar & 3 ea 5" HWDP as per DD. (342.24') PJSM Cont singe in hole W/ 5" D.P. F/ 342' to 2,248' MD. Tag cement stringer at 2,248' MD. Wash down F/ 2,248' to ES 2,258' MD. Pump 400 gpm, 600 psi, 40 rpm, trq 3.9K. P/U 91k SLK 70k ROT 80k. Drift 3.125" OD PJSM Drill ES F/ 2,258' to 2,261' MD 400 gpm 550 psi 40 rpm Trq 4K WOB 1-6K. F/O 55%. P/U 91k SLK 70k ROT 80k. PJSM Drill up closing plug chasing it down F/ 2,261' to 2,471' MD. 400 gpm, 645 psi 40 rpm Trq 3-4k F/O 55%. P/U 92k SLK 76k ROT 82k Cont single in hole W/ 5" D.P. 2,471' to 5,676' MD 168 jnt total. Wash down F/ 5,676' to TOC 5,701' MD tag W/ 3k. 400 gpm 740 psi P/U 174k SLK 78k. Circ surf to surf Rot Rec F/ 5,700' to 5,660' MD 400 gpm 800 psi 20 rpm Trq 12-14k PJSM R/U test Equip. Flood kill, choke and manifold working air out. Daily to G&I: 321 bbl. Total to G&I: 7080 bbl. Daily H2O S-Pad Creek: 140 bbl. Total H2O S-Pad Creek: 5630 bbl. Total H2O from A-Pad: 580. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Surface Loss: 55 bbl. 7/17/2021 Test 9-5/8" 40#/47# TXP BTC casing to 2500 psi w/ 30 min hold. Pump @ ~1/4 bpm, 2661 psi final, 2627 psi @ 15 min, 2611 psi @ 30 min hold. 4 bbls pumped, 4 bbls bled back. Chart and record. B/D choke and kill line. Lineup for drilling operations. Cut and slip drill line.(2249' left on drum). Inspect deadman, breaks, sheaves and associated traveling equipment. Calibrate blocks. Wash down from 5701' to 5708' MD. Drill shoe track F/ 5708' to 5832' MD. BFL, FC and FS all found on depth as per tally. 3-5k WOB, 400 gpm, 665 psi, 40 rpm, 6-7k tq. Displace on the fly @ 5832' to 8.9 Baradril. Wash down from 5832' to 5844' and drill 20' new formation F/ 5844' - T/ 5864' MD. Tripped thru shoe clean. Circulate and condition mud 8.9 In/Out. 3-5k WOB, 400 gpm, 660 psi, 40 rpm, 6-8k tq, 111k rot, 139k up, 95k dn. Pull into casing @ 5807' MD. R/U test equipment. Perform 12 EMW FIT. Pump 1.25 bbls/1 bbl bled back. 645 psi w/ 8.9 MW @ 4000' TVD. Dropped to 546 psi over 10 min. Chart and record. R/D test equipment. B/D choke and kill lines. Monitor well (Static). Obtain SPR's, Pump dry job and B/D TDS. POOH F/ 5807' - T/ 324' racking back 5" S-135, 19.5# DP. 60k Dn, 62k Up. Lost 19 trip. PJSM Rack back 2 stands 5" D.P. and Jar. L/D 6 ea 5" HWDP. P/U inspect mu motor, drain motor and break off 8.5" Tri Cone. Bit Grade 1-1-WT-A-E-I-NO-BHA. Clean and clear rig floor. PJSM P/U M/U BHA 3 8.5" RSS. 8.5" SK616M-J1D (6X14 TFA 0.902) 8.5" Hyc NRP, GeoPilot 7600 XL, 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75" PWD. 6.75" DM. 6.75" TM HOC. 8.375" IB. Plug into ADR and down load as per MWD. P/U 6.75" FS (non ported plunger) 6.75" NM FC, 6.75" FS (non ported plunger) , NM FC, 2 stands 5" HWDP W/ SLB 6.5" Jars total 282.12'. Perform shallow hole test and break in seals. 2 bph static loss. PJSM Single in hole RSS BHA 3 W/ 5" D.P. F/ 282' to 3,780' MD. (110 Jnts) (Drift 3.125) Cont stands F/ 3,780' to 5,686' MD. P/U 135k SLK 90k. Lost 3.8 bbls. PJSM Pull rotary bushings. Drain stack and pull flow nipple. R/U RCD bearing stand and install RCD bearing to stand. Install RCD bearing and clamp. Install rotary bushings. RIH F/ 5,686' to 5,813' MD. Gather parameters prior to exiting shoe 450 gpm 1,070 psi 80 rpm Trq 7k clean ECD 9.87 ppg. Cont RIh to 5,864' MD. P/U 138k SLK 91k, Daily to G&I: 778 bbl. Total to G&I: 7858 bbl. Daily H2O S-Pad Creek: 140 bbl. Total H2O S-Pad Creek: 5770 bbl. Total H2O from A-Pad: 580. Daily Metal: 5 lbs. Total Metal: 5 lbs. Daily Fluid Loss: 19 bbl. Total Production Loss: 19 bbl. Surface Loss: 55 bbl. 7/18/2021 Drill 8.5" Hole F/ 5,864' to 6,192' MD ( 3,989' TVD) Total 328’ (AROP 54.7’) 500 GPM/ MPD 483 1,460 PSI, 100-120 RPM, TRQ on 6-8K, TRQ off 6K, WOB 10- 18K. P/U 145K, SLK 74K, ROT 101K. ECD 10.05 Max Gas 435U. MPD 100% open. Back ream full stand. Start2°/100 at 6,600' MD. Drill 8.5" Hole F/ 6,192' to 6,768' MD ( 3,958' TVD) Total 576’ (AROP 96’) 525 GPM/ MPD 515 1,485 PSI, 120 RPM, TRQ on 8-10K, TRQ off 6-10K, WOB 2-10K. P/U 122K, SLK 86K, ROT 100K. ECD 10.12 Max Gas 662U. MPD 100% open. Back ream full stand. Cont 2°/100 at 6,600' MD. Drill 8.5" Hole F/ 6,768' to 7,371' MD ( 3,948' TVD) Total 603’ (AROP 100.5’) 525 GPM/ MPD 515 1,732 PSI, 130 RPM, TRQ on 8-12K, TRQ off 10K, WOB 6-18K. P/U 135K, SLK 73K, ROT 101K. ECD 10.50 Max Gas 717U. MPD 100% open. Back ream full stand. Cont 2°/100 at 6,600' MD. Drill 8.5" Hole F/ 7,371' to 8,035' MD ( 3,952' TVD) Total 664’ (AROP 110.7’) 550 GPM/ MPD 540 1,830 PSI, 120 RPM, TRQ on 10-12K, TRQ off 10-11K, WOB 4-16K. P/U 134K, SLK 69K, ROT 95K. ECD 10.7 Max Gas 723U. MPD 100% open. Back ream full stand. End 2°/100 at 7,660' MD. Distance to WP9A: 9.30', 9.12' Low 1.86' Right No Faults. 11 concretions for a total thickness of 72' (3.5% of the lateral). Footage NB Sand 2,076'. Daily to G&I: 456 bbl. Total to G&I: 8314 bbl. Daily H2O S-Pad Creek: 280 bbl. Total H2O S-Pad Creek: 6050 bbl. Total H2O from A-Pad: 580. Daily Metal: 7 lbs. Total Metal: 12 lbs. Daily Fluid Loss: 4 bbl. Total Production Loss: 23 bbl. Surface Loss: 55 bbl. 7/19/2021 Drill 8.5" Hole F/ 8,035' to 8,479' MD ( 3,960' TVD) Total 444’ (AROP 74’) 550 GPM/ MPD 537 1,990 PSI, 120 RPM, TRQ on 13-15K, TRQ off 13K, WOB 8-16K. P/U 144K, SLK 66K, ROT 95K. ECD 10.88 Max Gas 831U. MPD 100% open. Back ream full stand. Drill 8.5" Hole F/ 8,479' to 9,048' MD ( 3,952' TVD) Total 569’ (AROP 94.8’) 550 GPM/ MPD 533 1,975 PSI, 120-130 RPM, TRQ on 10-15K, TRQ off 10-13K, WOB 3-18K. P/U 133K, SLK 73K, ROT 94K. ECD 10.94 Max Gas 998U. MPD 100% open. Back ream full stand. Drill 8.5" Hole F/ 9,048' to 9,627' MD ( 3,948' TVD) Total 579’ (AROP 96.5’) 550 GPM/ MPD 533 1,955 PSI, 120- 130 RPM, TRQ on 9-12K, TRQ off 7-11K, WOB 3-28K. P/U 141K, SLK 69K, ROT 99K. ECD 10.67 Max Gas 939U. MPD 100% open. Back ream full stand. Adjust para for concretion. Start 2°/100 at 9,427' MD. Drill 8.5" Hole F/ 9,627' to 10,195' MD ( 3,954' TVD) Total 568’ (AROP 94.7’) 550 GPM/ MPD 535 2,020 PSI, 120 RPM, TRQ on 10-12K, TRQ off 10K, WOB 3-14K. P/U 138K, SLK 65K, ROT 97K. ECD 10.73 Max Gas 1,052U. MPD 100% open. Back ream full stand. Adjust para for concretion. End 2°/100 at 9,989' MD. At 9,702' MD ABI showed ~21° DLS over 9' course length. Set Geo home ream 2X 120 rpm/ 200 ft/hr & 1X 120 rpm/ 60 ft/hr to a 6.6° DLS. Distance to WP9A: 10.09', 7.4' High 6.9' Left No Faults. 22 concretions for a total thickness of 149' (3.5% of the lateral). Footage NB Sand 4,236' Daily to G&I: 570 bbl. Total to G&I: 8884 bbl. Total H2O S-Pad Creek: 6050 bbl. Daily H2O A Pad: 700. Total H2O from A-Pad: 1560. Daily Metal: 6 lbs. Total Metal: 18 lbs. Daily Fluid Loss: 0 bbl . Total Production Loss: 23 bbl. Surface Loss: 55 bbl. 7/20/2021 Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 10195'-T/10768' MD ( 3,968' TVD) as per WP09a. Total 573’ (AROP 96’) 550 GPM/ MPD 535 GPM, 2150 PSI, 120 RPM, TRQ on 11-13K, TRQ off 10.5K, WOB 4-14K. P/U 146K, SLK 56K, ROT 95K. ECD 11.13 Max Gas 1063u. MPD 100% open. Back ream full stand. The formation started to knock us up aggressively and stopped drilling at 10547', ended up with a 24° dogleg over 4' and 14° over 20'. Ream twice with 120 RPM, 350'/hr reaming speed and third time with 180'/hr reaming speed. On the third pass it decreased the dogleg the most and ended up with 5.4° over 18'. Continue drilling ahead and built ST contingency point#1 @ 10,704' - 10750' MD. Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 10768'-T/11275' MD (3963' TVD) as per WP09a. Total 505’ (AROP 85’) 550 GPM/ MPD 535 GPM, 2190 PSI, 120 RPM, TRQ on 11-13K, TRQ off 10.5K, WOB 4-14K. P/U 152K, SLK N/A(11522' MD), ROT 96K. ECD 11.1 Max Gas 974u. 2% lubes by vol. 9 ppg MW Drill 8.5" Hole F/ 11,275' to 11,693' MD ( 3,963' TVD) Total 418’ (AROP 69.7’) 550 GPM/ MPD 536 2,170 PSI, 120 RPM, TRQ on 11-13K, TRQ off 12-13K, WOB 5-24K. P/U 147K, SLK 54K, ROT 96K. ECD 11.1 Max Gas 971U. MPD 100% open. Back ream full stand. Adjust para for concretion. Went to highline at 18:00 Start 2°/100 at 11,567' MD. At 11,685' MD ABI showed ~13° DLS over 10' course length. Sent Geo home, Ream one 120 RPM/ 200 ft/hr down to 11.3° DLS, second 120 RPM/ 60 ft/hr down to 3.3° DLS. Drill 8.5" Hole F/ 11,693' to 12,231' MD ( 3,946' TVD) Total 538’ (AROP 89.7’) 550 GPM/ MPD 542 2,330 PSI, 120 RPM, TRQ on 14-16K, TRQ off 12-13K, WOB 7-14K. P/U 147K, SLK 35K, ROT 93K. ECD 11.5 Max Gas 950U. MPD 100% open. Back ream full stand. Adjust para for concretion. Lost SLK 11,725' MD Distance to WP9A: 30.55', 17.1' High 27.2' Left No Faults. 29 concretions for a total thickness of 201' (3.2% of the lateral). Footage NB Sand 6,256' Daily to G&I: 627 bbl. Total to G&I: 9511 bbl. Total H2O S-Pad Creek: 6050 bbl. Daily H2O A Pad: 560. Total H2O from A-Pad: 2120. Daily Metal: 4 lbs. Total Metal: 22 lbs. Daily Fluid Loss: 0 bbl . Total Production Loss: 23 bbl. Surface Loss: 55 bbl. 7/21/2021 Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 12231' - T/12498' MD ( 3,949' TVD) as per WP09a. Total 267’ (AROP 45’) 550 GPM/ MPD 535 GPM, 2420 PSI, 120 RPM, TRQ on 17K, TRQ off 15K, WOB 7-20K. P/U 161K, SLK N/AK, ROT 93K. ECD 11.3 Max Gas 902u. MPD 100% open. Back ream full stand. Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 12498' - T/12828' MD ( 3981' TVD) as per WP09a. Total 330’ (AROP 55’) 550 GPM/ MPD 535 GPM, 2420 PSI, 120 RPM, TRQ on 16-20K, TRQ off 15K, WOB 7-28K. P/U 161K, SLK N/AK, ROT 93K. ECD 11.3 Max Gas 447u. MPD 100% open. Back ream full stand. Dropped Inclination to 87° in attempt to exit btm of NB sand ~12350' MD. Appeared to be scraping btm side of NB sand and unable to exit until reaching Fault#1 @ 12564' MD. Entered MD formation (Wet) and continue drilling down in section targeting ~82° Inc to verify geological location. Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 12828' - T/13059' MD (4040' TVD) as per WP09a. Total 231’ (AROP 55’) 550 GPM/ MPD 535 GPM, 2325 PSI, 120 RPM, TRQ on 16-20K, TRQ off 16-18K, WOB 2-12K. P/U 173K, SLK N/AK, ROT 100K. ECD 11.22 Max Gas 314u. MPD 100% open. Back ream full stand. Drill 8.5" Lateral hole "geosteering" in the NB Sand F/ 13059' - T/13300' MD (4090' TVD) as per WP09a. Total 241’ (AROP 40.2’) 550 GPM/ MPD 535 GPM, 2400 PSI, 110 RPM, TRQ on 16-24K, TRQ off 16-18K, WOB 2-12K. P/U 175K, SLK N/AK, ROT 104K. ECD 11.42 Max Gas 506u. MPD 100% open. Back ream full stand. At 13062': increase in torque and vibration. Geo Pilot indicated failure. Attempted to reset tool with downlink reset, home and pump power cycle - no success. Drill ahead with no steering, holding Inc and Azi. Distance from WP09a: 16.7', 9' low, 14.1'. right. Daily disposal to G&I: 513 bbl. Total disposal to G&I: 10024 bbl. Daily H2O from A-Pad: 700. Total H2O from A-Pad: 2820. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6050 bbl. Daily Metal: 4 lbs. Total Metal: 26 lbs. Daily Fluid Loss: 0 bbl. 7/22/2021 Drill 8.5" Lateral hole "geosteering" Targeting NB Sand F/ 13300' - T/13524' MD (TD) (4142' TVD) as per GEO . Total 224’ (AROP 56’) 550 GPM/ MPD 535 GPM, 2460 PSI, 120 RPM, TRQ on 19.5K, TRQ off 17K, WOB 8-10K. P/U 168K, SLK N/A, ROT 99K. ECD 11.4 Max Gas 760u. MPD 100% open. B/R full std. Lost command function with RSS (Geopilot). Drilled ahead dropping in section with no stearability. Deflection and TF was inconsistent. Attempted several times downlink and send tool to "Home" with no success. Obtain final svy @ TD. CBU (Rot/Recip) @ 13524' - 13440' MD. 550 gpm, 2465 psi, 100 rpm, 16k tq, 11.4 ECD w/ 9.3 MW. Saw 3.4u gas at btms up then dropped to 30-40 BGG. 166k up, 101k rot, N/A rot. Drop 2.38" steel drift without wire. Obtain SPR 32/48 #1- 305/395 psi, #2-305/395 psi. BROOH F/ 13440' - T/ 13123' MD. 550 gpm, 2370 psi, 80 rpm, 16k tq. 160 BGG. Pulling speed 40 fpm max. BROOH F/ 13123' - T/ 10620' MD. 536 gpm, 2195 psi, 80 rpm, 14.5k tq. 160 BGG. Pulling speed 40 fpm max. 157k up, 97k rot, N/A dn. BROOH F/ 10620' - T/ 8092' MD. 550 gpm, 1980 psi, 80 rpm, 13.5k tq. Pulling speed 40 fpm max. 143k up, 97k rot, 64k dn. BROOH F/ 8092' - T/ 5877' MD. 550 gpm, 1980 psi, 80 rpm, 13.5k tq. Pulling speed 40 fpm max. 143k up, 97k rot, 64k dn. Pull w/o rotary F/5877' - T/5813' MD through shoe at 5834' MD with no issues. CBU at 9-5/8" shoe w/ rotation and reciprocation. F/5813 - T/5750' MD. 550 gpm, 1700 psi, 80 rpm, 9.7 k tq, 266 BGG, MW in/out 9.2 ppg, 145k up, 82k dn, 104k rot. Monitor well at shoe - static. Daily disposal to G&I: 399 bbl. Total disposal to G&I: 10423 bbl. Daily H2O from A-Pad: 420. Total H2O from A-Pad: 3240. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6050 bbl. Daily Metal: 5 lbs. Total Metal: 31 lbs. Daily Fluid Loss: 0 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 23 bbl. 7/23/2021 Monitor well (static). Pull RCD and install trip nipple. Visually monitor well from floor (Very slight losses). Pump dry job (20 bbl) and B/D TDS. POOH Laying down 62jts 5" dp from 5813' to 3843' MD to allow enough room on rig floor to work casing equipment. Continue TOH F/ 3843' - T/ BHA 282' MD. 54k up, 53k dn. Rack back HWDP w/ jars, Flex DC's. Retrieved 2.38" steel drift from top float sub. Download MWD. B/O and L/D MWD tools, Geopilot and bit. Bit graded 4,6,S,X,I,BT,FM. 10 bbl loss for trip. Cleaned and cleared rig floor. Mob tools and equipment to floor. R/U elevators, double stack power tongs and handling equipment. Prep pipshed with 4.5" liner, shoe track and pkr assy. PJSM, M/U shoe track and check floats (good). RIH w/ 4.5" TXP, 12.6# liner T/ 1098' MD as per detail. C/O to 5" elevators. M/U 7" ECP crossed over to 4.5". Mix and install "Pal Mix". M/U 1 std of 5" DP out of derrick and circulate 1-1/4 string volume @ 1.5 BPM, 82 psi. 46k up, 45k dn. Continue to RIH w/ 4.5" TXP, 12.6# liner per detail on 5" DP stands out of derrick F/ 1098' MD - T/ 5732' MD at 40 fpm filling pipe every 2500'. 140k up, 87k dn. Service rig: grease crown, blocks, top drive, IBOP, wash pipe, drawworks, iron roughneck and handling equipment. Check oil in top drive. Continue to RIH w/ 4.5" TXP, 12.6# liner per detail on 5" DP stands out of derrick F/ 5732' MD - T/ 8073' MD at 40 fpm filling pipe every 2500'. 151k up, 71k dn. Continue to RIH w/ 4.5" TXP, 12.6# liner per detail on 5" DP stands out of derrick F/ 8073' MD - T/ 11,374' MD at 40 fpm filling pipe every 2500'. 167k up, 40k dn. Unable to move down at 11,374' MD, break circulation and wash down 3 bpm, 364 psi. Cont. to RIH and lost weight again at 12 ,161' MD. Break circulation and wash down and work pipe at 4 bpm, 440 psi, 170k up, all available weight down. Rotate string with 4k tq and continue to wash and work down to 12,383' MD per Baker rep. Daily disposal to G&I: 471 bbl. Total disposal to G&I: 10,894 bbl. Daily H2O from A-Pad: 280. Total H2O from A-Pad: 3,520. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl Daily Metal: 1 lbs. Total Metal: 32 lbs. Daily Fluid Loss: 21 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 44 bbl. 7/24/2021 Continue wash and ream 4.5" TXP liner F/ 12838' - T/ tag depth 13524' MD. 4.5k - T/ 10k tq with 1-3 rpm. 1-5 bpm with max psi 550 psi. Saw minor differential sticking with pump psi over ~175 psi. Tagged btm on depth w/ 10k set down. Release tq and work out same with pumps down. 198k up/ no pump. Park in slips w/ 137k. R/U TIW, Head pin w/ cmt line. Circulate 1x string vol @ 5 bpm, 625 psi, 40% flow out. No losses. PJSM, HES cmtrs , Flood lines w/ 5 bbls H2O. P/T 600 low/3800 high (test good). Pump 50 bbls 10# tuned spacer, 85 bbls 15.8# tail cement displaced with 2 bbls H2O to clear lines then turned over to rig. Drop (BOT) "Pump Down Plug". Chase plug @ 7 bpm (caught psi @ 630 stks) Displace cmt with 9.3 mud, 7 bpm, 550 ICP. Stage rate down keeping psi @ or below 550 psi. Reduce pump rate to 2 bpm last 18 bbls. Bump @ 3305 (3400 calc). Psi up and observed plug shear @ 793 psi then land out on collar. P/U to 167k up.Psi up 800 psi w/ 5 min hold. CIP @ 15:26 Incrementally stage up to 1500 psi. S/O to blk wt (35k). Psi up to 2000 psi then pick up to 211k (no released). S/O to blk wt. Psi up to 3000 psi and work pipe. P/U to 212k and observed break over with new up wt 165k indicating liner set and released. TOL @ 12445' MD. L/D single and trip out 3 stands to 12223' MD. Drop 5" dp wiper ball and circulate 1.5x STS @ 510 gpm, 1240 psi, 56% flow out. Dump 82 bbls spacer and contaminated mud @ first BUS. Pull 5 stands and verify well not swabbing. Pump 10 bbl, 10.2 ppg dry job. Continue to POH on elevators with liner running tool, standing back DP in derrick F/ 12,240' - T/ 5755' MD, inside 9-5/8" casing shoe. 162k up, 88k dn. Calculated hole fill observed for trip. No hole issues. Continue to POH on elevators with liner running tool, standing back DP in derrick F/ 5755' to surface. LD liner running tool - running tool in good condition. Clean and clear rig floor. Mobilize BHA components to rig floor. PJSM. PU & MU BHA 4, 8.5" RSS per DD / MWD: 8.5" SK616M-J1D (6X14 TFA 0.902), 8.5" Hyc NRP, GeoPilot 7600 XL, 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75" PWD. 6.75" DM. 6.75" TM HOC. 8.375" IB. Plug into ADR and down load as per MWD. P/U 6.75" FS (non ported plunger) 6.75" NM FC, 6.75" FS (non ported plunger) , NM FC, 2 stands 5" HWDP W/ SLB 6.5" Jars. BHA length = 281.79'. Perform shallow hole test and break in seals. Daily disposal to G&I: 164 bbl. Total disposal to G&I: 11,058 bbl. Daily H2O from A-Pad: 280. Total H2O from A-Pad: 3,800. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl Daily Metal: 0 lbs. Total Metal: 32 lbs. Daily Fluid Loss: 3 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 47 bbl. 7/25/2021 RIH w/ 8.5" RSS (Geopilot) F/ 281' - T/3843' out of derrick. Single in from 3843' to 5813' MD. Drift w/ 3.125". Fill @ 2500 psi and break in bearings on new GeoPilot as per DD. 155k up, 95k dn. Calc disp. PJSM, Cut and slip 88' drilling liner (1099 ton miles). 2161' left on spool. Inspect brakes, drawworks and crown sheave wobble (EAM). Perform derrick inspection. Svc traveling equipment, Iron Roughneck and handling equipment. Install RCD bearing. Verify MPD surface working correctly (good). Establish parameters @ shoe. 450 gpm, 1122 psi, 40 rpm, 11.5k tq, 10.2 ECD. 158k up, 79k dn, 106k rot. TIH F/ 5813' - T/ 9214' MD before losing down wt. Noted:3-5k drag BHA thru shoe. 175k up with no dn wt @9214' MD. Wash and Ream down F/ 9214' - T/ 11,500' MD. 450 gpm, 1577 psi, 35 rpm, 17.4k tq. No issues wash/ream down. 181k up, 97k rot, N/A dn. PJSM. Perform OH sidetrack per DD: Trough at 200 fph F/ 11,500' - T/ 11,525' MD. Wipe and work through trough at 100 fph. Time drill F/ 11,525' - T/ 11,545' MD: start at 5 fph and stage up to 60 fph w/ 1-3k WOB. Backream out and confirm good entry back into sidetrack. Drill 8.5" Lateral hole per WP15 F/ 11,545' - T/11,721' MD ( 3973' TVD). Total 176’ (AROP 88’) 550 GPM/ MPD 550 GPM, 2205 PSI, 120 RPM, TRQ on 22-24K, TRQ off 20K, WOB 3-12K. 202k up, N/A dn, rot 93K. MW in 9.3 ppg, ECD 11.2 Max Gas 634u. MPD 100% open. Back ream full stand. Drill 8.5" Lateral hole per WP15 F/ 11,721' - T/12,300' MD ( 4020' TVD). Total 579’ (AROP 96.5’) 550 GPM/ MPD 550 GPM, 2230 PSI, 120 RPM, TRQ on 22-24K, TRQ off 22K, WOB 5-12K. 218k up, N/A dn, rot 98K. MW in 9.25 ppg, ECD 11.45 Max Gas 1014u. MPD 100% open. Back ream full stand. Distance from WP15: 14.98', 3.51' low, 14.57' right. Daily disposal to G&I: 394 bbl. Total disposal to G&I: 11,452 bbl. Daily H2O from A-Pad: 0. Total H2O from A-Pad: 3,800. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl Daily Metal: 0 lbs. Total Metal: 32 lbs. Daily Fluid Loss: 26 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 73 bbl. 7/26/2021 Drill 8.5" Lateral hole per WP15 F/ 12300' - T/12805 MD ( 4077' TVD). Total 505’ (AROP 84’) 550 GPM/ MPD 550 GPM, 2335 PSI, 120 RPM, TRQ on 22-24K, TRQ off 22K, WOB 10-12K. 225k up, N/A dn, rot 101K. MW in 9.25 ppg, ECD 11.6 Max Gas 518u. MPD 100% open. Back ream full stand. Drilled fault #1 @ 12640'(~4064' TVD). Reaquired NB sand @ 12705' MD. Dump and dilute 290 bbls "Baradril" after reentering sand. Increase lube from 2% to 2.5% due to high tq with no significant change in tq.. Continue Drill 8.5" Lateral hole per WP15 F/ 12805' - T/13288 MD ( 4088' TVD). Total 483’ (AROP 81’) 550 GPM/ MPD 550 GPM, 2320 PSI, 90-120 RPM, TRQ on 24.5K, TRQ off 23K, WOB 10-12K. 232k up, N/A dn, rot 92K. MW in 9.25 ppg, ECD 11.6 Max Gas 883u. MPD 100% open. Back ream full stand. Drilled Fault #2 @ 13,184' MD (~4064' TVD). Continue Drill 8.5" Lateral hole per WP15 F/ 13,288' MD - T/ 13,662' MD (4093' TVD), Total 374’ (AROP 62.3’). 550 GPM/ MPD 526, 2275 PSI, 90-120 RPM, TRQ on 23-27K, TRQ off 22-23K, WOB 5-14K. 228k up, N/A dn, rot 92K. MW in 9.25 ppg, ECD 11.4 Max Gas 800u. MPD 100% open. Back ream full stand. Increase lubes to 3% with no noticeable decrease in torque observed. Continue Drill 8.5" Lateral hole per WP15 F/ 13,662' MD - T/ 14,050' MD (4081' TVD), Total 388’ (AROP 64.7’). 550 GPM/ MPD 526, 2275 PSI, 90-120 RPM, TRQ on 23-27K, TRQ off 22-23K, WOB 5-19K. 228k up, N/A dn, rot 97K. MW in 9.3 ppg, ECD 11.4 Max Gas 596u. MPD 100% open. Back ream full stand. Distance from WP15: 5.63', 4.78' Low, 2.97' Left Daily disposal to G&I: 684 bbl. Total disposal to G&I: 12,136 bbl. Daily H2O from A-Pad: 840. Total H2O from A-Pad: 4,640. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 1 lbs. Total Metal: 33 lbs. Daily Fluid Loss: 0 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 73 bbl. 7/27/2021 Continue Drill 8.5" Lateral hole per WP15 F/ 14050' - T/ 14298' MD (4073' TVD), Total 248’ (AROP 42’). Flow 475 In/MPD 402 Out(84%), 1850 PSI, 110 RPM, TRQ on 27K, TRQ off 25K, WOB 5-12K. 228k up, N/A dn, rot 95K. MW in 9.3 ppg, ECD 11.5 Max Gas 757u. MPD 100% open. Back ream full stand. Drilled thru loss zone @ 14,177' MD. 72-90 bph initial loss rate. Pump 2x 40 bbls LCM pills with slight increase in returns (50 ppb baracarb). Continue Drill 8.5" Lateral hole per WP15 F/ 14298' to TD @ 14391' MD (4069' TVD), Total 103’ (AROP 69’). Flow 475 In/MPD 415 Out(87%), 1935 PSI, 110 RPM, TRQ on 27K, TRQ off 25K, WOB 5-12K. 232k up, N/A dn, rot 93K. MW in 9.3 ppg, ECD 11.2 Max Gas 214u. MPD 100% open. Back ream full stand. No differential sticking observed during connections. Obtain final svy @ TD. TD called early by Geo team. Circulate and condition mud @ TD 14391' MD (Rot/Recip). Reduce pump rate to 450 gpm and slowed losses to 25 bph (430 gpm out). 110 rpm, 25k tq, Continue seeing losses slowly heal up during cleanup cycle. Circulate and total of 4x btms up. 70u BGG w/ 11.1 ECDs (9.25 MW). PJSM. Displace well to 9.1 ppg lubricated brine. pump 3ea 40 bbl Sapp pills, each chased with 20 bbls 9.3 ppg lubricated (2.25%) QuickDril Brine. Continue to displace with 9.1 ppg lubricated(2.25% )QuickDril Brine: Flow in 475 gpm / MPD out 463 gpm, 1420 psi, 110 rpm, Tq 20-22k, ECD 10.3, 185k up, 98k rot, N/A dn. Monitor well through MPD choke after displacement - finger print and observe pressure decreasing trend from 16 psi over 10 min over 2 cycles. BROOH F/ 14,391' - T/ 13,417' MD: Flow in 450 gpm / MPD out 425 gpm, 1222 psi, 120 rpm, Tq 18-20k, MW 9.15 ppg, ECD 10.38 ppg, 195k up, N/A dn, 105k rot. pulling at 15-25 fph as hole dictates. Loss rate 10-15 bph BROOH F/ 13,417 - T/ 11, 360' MD: Flow in 475 gpm / MPD out 470 gpm, 1270 psi, 120 rpm, Tq 14k, ECD 10.32 ppg, 163k up, 64 dn, 105k rot. Pick up to 11,478' MD and drift through sidetrack with no rotation/pump to 11593' MD and verify correct wellbore with ABI - no issues. No losses while BROOH. Daily disposal to G&I: 2134 bbl. Total disposal to G&I: 14,270 bbl. Daily H2O from A-Pad: 560. Total H2O from A-Pad: 5,200. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 4 lbs. Total Metal: 37 lbs. Daily Fluid Loss: 358 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 431 bbl. 7/28/2021 Continue to BROOH F/ 11,360' - T/ 8799' MD. Flow/MPD 525/490 gpm, 1335 psi, MW 9.1 ppg, ECD 10.12 ppg, max gas 253u, 120 rpm, Tq 10-12k, 142k up, 75k dn, 99k rot. pull at 20-30 fpm as hole dictates: no hole issues noted Continue to BROOH F/ 8799' - T/ 5955' MD. Flow/MPD 550/525 gpm, 1288 psi, MW 9.1 ppg, ECD 10.12 ppg, max gas 215u, 120 rpm, Tq 6-8k, 127k up, 89k dn, 106k rot. pull at 30-40 fpm as hole dictates: Pull through shoe F/ 5955 - T/ 5813' MD with no rotation or pump. 5-10k drag with each stabilizer/bit. Circulate hole clean at 9-5/8" shoe: Flow/MPD 550/555 gpm, 1305 psi, MW 9.1 ppg, max gas 199u, 80 rpm, Tq 6k, 127k up, 89k dn, 106k rot. Pump 40 bbl High-vis 9.2+ sweep - on time w/ minimal increase in cuttings. Circulate total of 3x bottoms up. Monitor well for 10 min: static Pull and LD MPD bearing. Install trip nipple. Service top drive, crown, blocks, wash pipe, IBOP, iron roughneck and drawworks. Check welds on extend frame cradle . Check oil in top drive. Open coffin lid, clean oil and tighten loose fitting. PJSM. Pull 5 and verify no swabbing. Pump 25 bbl 10.5 ppg dry job and POOH with 8.5" RSS assembly, laying down 5" drill pipe to shed F/ 5813' - T/ 281' MD. PJSM. LD 8.5" RSS assy per DD/MWD F/ 281'. Download MWD tools. Dull Bit grade: 1-1-CT-A-X-I-NO-TD RU to run 6-5/8", 20#, HYD563 slotted liner. Verify pipe in shed. RU Weatherford tongs and 6-5/8" handling equipment. MU 6- 5/8" x 5" safety joint and stage on ODS of catwalk. PJSM. MU and RIH with 6-5/8", 20#, HYD563 slotted liner per tally to 679' MD. Daily disposal to G&I: 228 bbl. Total disposal to G&I: 14,498 bbl. Daily H2O from A-Pad: 140. Total H2O from A-Pad: 5,340. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 5 lbs. Total Metal: 42 lbs. Daily Fluid Loss: 129 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 560 bbl. 7/29/2021 PJSM. Continue RIH with 6-5/8", 20#, HYD563 slotted liner per tally F/ 679' - T/ 8679' MD. 115k up, 82k dn @ shoe. M/U BOT 9-5/8" SLZXP packer assy (pinned 1988-2197 psi w/ 5% brass). R/D WOT casing equipment and R/U 5" handling equipment (hydraulic elevators). Single in hole w/ 5" NC50 49.3# HWDP T/ 8718' and pump thru assy. 3 bpm, 77 psi. Rotate @ 1-3 rpm w/ 7k. No rotation without reciprocation. Continue run 6-5/8" slotted injection liner conveyed on 5" HWDP F/ 8718' to tag depth 14391' MD. Rotate down past sidetrack point @ 11500 with 1-3 rpm, 7k tq until 11550' then killed rotary and slipped by sidetrack without issue. Nothing noted on wt indicator. 240k up, 116k dn @ 11400' MD. No issues running in, tagged TD on depth at 14391' MD. 259k up, 133k dn. at 14391'MD. Drift HWDP - 2.75". Establish parameters with Baker rep. Drop 1.25" phenolic setting ball and pump down at 3 bpm, 220 psi, slowing to 1 bpm at 500 stks. Ball landed on seat at 615 stks. Increase pressure to 2300 psi and hold for 15 min, observe shear at 2180 psi. Slack off and set down 60k lbs to set packer. Pressure up to 4700 psi and shear out ball seat, observe setting tool neutralize at 3391 psi. Pick up 1' and confirm free: 230 k up. Pressure test annulus to 1500 psi for 10 charted min: good test. TOL - 5686' MD, Shoe depth - 14,391' MD Pull and lay down 3 jts of HWDP T/ 5635' MD and circulate bottoms up: 450 gpm, 1520 psi. Monitor well - static. Pump 10 bbl, 10.5 ppg corrosion inhibited brine dry job. Blow down surface equipment. Pull and lay down 5" HWDP F/ 5635' MD. Lay down liner running tool per Baker. Run in the hole with 5" drill pipe stands from the derrick T/ 4500' MD. Daily disposal to G&I: 150 bbl. Total disposal to G&I: 14,639 bbl. Daily H2O from A-Pad: 0. Total H2O from A-Pad: 5,340. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 0 lbs. Total Metal: 42 lbs. Daily Fluid Loss: 53 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 613 bbl. Activity Date Ops Summary 7/30/2021 Trip in hole out of derrick with 5" dp F/ 2414' - T/ 4639' MD. 116k up, 85k dn. POOH laying down drill pipe F/ 4639' to surface (73 stands). RIH out of derrick to 5081' MD (80 stands). 118k up, 96k dn. POOH laying down drill pipe F/ 5081' to surface (80 stands). PU 5" safety joint and break down. Clear rig floor.,Pull and lay down wear bushing. Install test plug and RILDS.,PJSM. Make up BOPE test tools: MU test sub to top drive. PU 3-1/2" test joint and MU FOSV, dart and pump-in sub. Rig up test equipment. Flood lines and purge air from system. Perform initial body test - Mezzanine Kill leaking. Grease and re-test: good test.,PJSM. Test BOPE 250/3000 psi for 5/5 charted min with 3-1/2" test joint on annular, upper & lower 2-7/8"x5-1/2" rams. Test Super Choke and manual choke to 1700 psi. Test all gas alarms, pit level sensors and flow paddle. Perform drawdown test on accumulator: Accumulator Initial 3050 psi, Final 1500 psi. Manifold Initial 1600 psi, Final 1500 psi. Time to 200 psi 25 sec, Time to full recharge 95 seconds,Fail / Pass on choke manifold valve #13, Super Choke and #3 Kill valve. Replace valve #13, retest - pass. Flush Super Choke, retest - pass, Grease #3 Kill Valve, retest - pass. 24 hr notice sent 7/29/21 @05:50. AOGCC rep Bob Noble waived witness 7/29/21 @07:07,Rig down BOPE test equipment, pull test plug and blow down surface lines,Service top drive, wire tie J-box, close coffin and secure.,Rig up to run 3-1/2", 9.3#, L-80 EUE upper completion. Verify pipe in shed, rig up tongs and handling equipment on rig floor. Rig up Centralift spooler on rig floor. Bring up Cannon clamps and stage on rig floor.,PJSM. RIH with 3-1/2" upper completion per tally: Baker Seal assembly with no-go, 3-1/2", 9.3#, L-80 EUE tubing, XN assembly and gauge carrier assembly to 112' MD,Daily disposal to G&I: 285 bbl. Total disposal to G&I: 14,924 bbl. Daily H2O from A-Pad 110. Total H2O from A- Pad: 5,450. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 0 lbs. Total Metal: 42 lbs. Daily Fluid Loss: 29 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 642 bbl. 7/31/2021 Continue RIH with 3-1/2", 9.3#, L-80 EUE upper completion per tally F/112' - T/ 788' MD. M/U gauge carrier w/ tech wire and test same (test good). Continue RIH to 3282' MD. Tq connections 3.1k tq. 55k up, 51k dn. Test tech wire every 1000' (good). Lost 5 bbls from calc.,Continue RIH with 3-1/2", 9.3#, L-80 EUE upper completion per tally F/ 3382' - T/ 5686' MD. Tq connections 3.1k tq. 69k up, 56k dn. Test tech wire every 1000' (good). Lost 8.7 bbls total trip. 84 cannon clamps total.,Tag on No/GO 5695' MD w/ 7k set dn (2x). Saw 4-6k seal drag after entering liner top. 69k up, 56k dn (21k string wt). L/D excess joint. M/U 15.17' pup jt below first full jt. C/O elevators, M/U landing jt w/ xo. M/U hanger assy and terminate tech wire. Test same (test good). Landout hanger on detph 2.16' off no/go.,R/U to reverse circulate. Close annular (500 psi) and psi up IA ~250 psi. Strip up and locate circ ports on bullet seal assy + 1'. Observe psi dump @ ~5.5' up.,PJSM, Reverse circulate 280 bbls CI 9.1 brine @ 4 bpm, 220 ICP, 321 FCP. Chase with 145 bbls diesel down IA @ 4 bpm, 285 ICP, 480 FCP. Clear lines with 10 bbls water. R/D and L/D WOT casing equipment. L/D mousehole.,PJSM. Strip through the bag and land tubing hanger. Bleed off pressure and RILDS per wellhead rep. LD landing joint and rig up to test seals and IA. Pressure up to 2500 psi and hold for 30 charted min - good test. Blow down and rig down test equipment. Set BPV per wellhead rep.,PJSM. Flush diesel from both mud pumps, pop-offs, Kelly hose, Choke and Kill lines, BOPE stack and bleeder/flow line with heated soap pill. Blow down all surface equipment. Offload mud from pits.,PJSM. De-energize accumulator and disconnect lines from stack. Remove riser and install cap plug on MPD. Remove choke and kill lines from BOPE. Remove BOPE studs - 4 bolt connections. Remove hole fill line. SIMOPS: Cuck out and clean pits. Load and process 5" drill pipe in shed.,Rack back stack and secure on stump. ND DSA and stage in cellar. install CTS in BPV. Simops: Continue to clean pits.,Mobilize tree into cellar and NU same. Install TWC and test 500/5000 (test good) with 5/10 min hold on each.. Pull TWC. BOT perform final test on Tech wire (test good). Secure well and release from S-46 @ 06:00 8/1/2021. Last report for S-46. Moving to MPU S-47. Simops: Continue to clean pits. Bridle up and prep to scope derrick down.,LRS - Freeze protect 3.5" x 9.625". Inside Annulus w/ 25 bbls diesel. 0 ICP, 710 FCP @ 2 bpm. 0 psi OA, 560 psi IA.,Daily disposal to G&I: 922 bbl. Total disposal to G&I: 15846 bbl. Daily H2O from A-Pad 0. Total H2O from A-Pad: 5,450. Daily H2O from S-Pad Creek: 0 bbl. Total H2O from S-Pad Creek: 6,050 bbl. Daily Metal: 0 lbs. Total Metal: 42 lbs. Daily Fluid Loss: 18 bbl. Total Fluid Loss Surface: 55 bbl. Total Fluid Loss Production: 660 bbl. 7/10/2021Spud Date: Well Name: Field: County/State: MP S-46 Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-23695-00-00API #: CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU S-46 Date:7/17/2021 Csg Size/Wt/Grade: 9.625 40#/47# L-80 Supervisor:S Barber / O Amend Csg Setting Depth:5,834 4,000 TVD Mud Weight:8.9 ppg LOT / FIT Press =645 psi LOT / FIT =12.00 ppg Hole Depth =5344 md Fluid Pumped=1.3 Bbls Volume Back =1.1 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->268 ->00 ->4111 ->8290 ->6180 ->16 585 ->8260 ->24 885 ->10 340 ->32 1180 ->12 420 ->40 1475 ->14 500 ->48 1770 ->16 565 ->56 2065 ->18 593 ->64 2360 ->20 652 ->72 2661 ->24 -> ->24 -> ->26 -> ->28 -> Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0652 ->02661 ->1638 ->52640 ->2621 ->10 2635 ->3607 ->15 2627 ->4593 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helsea Wright Digitally signed by Chelsea Wright Date: 2021.07.28 09:41:57 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.07.28 10:55:19 -08'00' TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 2 1 1 1 5 1 1 1 34 X Yes No X Yes No 6.48 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 No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X 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:Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns? Yes X 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: Casing (Or Liner) Detail Shoe RKB 10 K55 398 19325.43SECOND STAGEHES Rotate Csg Recip Csg Ft. Min. PPG9.6 Shoe @ 5834 FC @ Top of Liner5,750.00 Floats Held 30 646 248 398 H2O CASING RECORD County State Alaska Supv.J Lott / B Anderson Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP S-46 Date Run 14-Jul-21 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TXP BTC Innovex 1.59 5,834.00 5,832.41 25.80 25.80 Csg Wt. On Hook:266,000 Type Float Collar:Innovex No. Hrs to Run:15 8.34 7.9 0 10 10.7 320 5.3 100 537 Bump Plug?FIRST STAGE10Tuned Spacer 4# Red 5# Pol-E-Flake 62 15.8 530 4.5 8.34 7 20/20 20/0 0 HES 15.8 82 Bump pressBump Plug? Y 0 2257 5,834.005,844.00 CEMENTING REPORT Csg Wt. On Slips: Spud Mud Tuned Spacer 4# Red 5# Pol-E-Flake 623 2.88 Stage Collar @ 60 Bump press 100 0 ES Closure OK 56 12 188 26.21 RKB to CHF Type of Shoe:Innovex Casing Crew:Weatherford No. Jts. Delivered 150 No. Jts. Run 145 5 Length Measurements W/O Threads Ftg. Delivered 6,043.00 Ftg. Run 5,838.00 Ftg. Returned 205.00 Ftg. Cut Jt. Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 5.4 Arctic Cem Type Shoe Jnt 2 ea 10' F/ end, 1 ea 2 nd & 3rd jnt, 1 ea F/ jnt 4 to 26, every other jnt F/ 27 to 84, 5 before and 5 after ES, /C// / Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 80.63 5,832.41 5,751.78 Float Collar 10 K55 TXP BTC Innovex 1.28 5,751.78 5,750.50 Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 40.73 5,750.50 5,709.77 Baffle Adapter 10 40.0 TXP BTC Halliburton 1.42 5,709.77 5,708.35 Casing 9 5/8 47.0 L-80 TXP BTC Tenaris 3,430.64 5,708.35 2,277.71 Pup 9 5/8 40.0 L-80 TXP BTC 17.66 2,277.71 2,260.05 ESC 10 3/4 40.0 L-80 TXP BTC Halliburton 2.81 2,260.05 2,257.24 Pup 9 5/8 40.0 L-80 TXP BTC 18.09 2,257.24 2,239.15 Casing 9 5/8 47.0 L-80 TXP BTC Tenaris 2,239.15 2,239.15 25.80 Arctic Cem 448 2.35 Premium G 400 1.15 5.4 Premium G 270 1.17 0 H2O No losses recorded, plug bumped, volumes calculated 05:10 7/14/2021 221 bbls of cement, 30 bbls of interface returned to surface, no losses 7/15/202116:38 20 bbls fresh water, 231 bbls of 9.4 spud mud STATE OF ALASKA Reviewed By: OIL AND GAS CONSERVATION COMMISSION P.I. Supry j 73 f-, BOPE Test Report for: MILNE PT UNIT S-46 " Comm Contractor/Rig No.: Hilcorp Innovation PTD#: 2210450 - DATE: 7/16/2021 - Inspector Adam Earl Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Shane Barber Rig Rep: Matt COUrson Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopAGE210719192546 Rams: Annular: Valves: NIASP: Type Test: INIT 250/3000- 250/3000- 250/3000 - 1352 , Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank P P System Pressure _ _ 3000 _ P Housekeeping: P Pit Level Indicators P P Pressure After Closure 1500 P " PTD On Location P - Flow Indicator P P 200 PSI Attained 23 P Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 98 - P ' Well Sign P - H2S Gas Detector P P Blind Switch Covers: All Stations P Drl. Rig P MS Mise 0 NA Nitgn. Bottles (avg): 6(a)2308 P ` Hazard Sec. P ACC Misc _ 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 1 - P - Stripper 0 NA No. Valves 15 - P Lower Kelly 1 P Annular Preventer 1 13 5/8 - P Manual Chokes 1 - P Ball Type 2 P #1 Rams 1 2 7/8 X 5 1/2 P Hydraulic Chokes 1 FP Inside BOP l P #2 Rams 1 Blind FP CH Misc 0 NA FSV Misc 0 NA #3 Rams l 2 7/8 X 5 1/2 P #4 Rams 0 N_A _ _ _ #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 _ 3 1/8 - P - Quantity P/F HCR Valves 2 -3 1/8 - P Inside Reel Valves - 0 NA Kill Line Valves 2 " 3 1/8 P ' Check Valve 0 NA BOP Misc 0 NA Number of Failures: 2 ✓ Test Results Test Time 6 Remarks: Blinds had to be functioned FP. Actuator on super choke keeper key failed, replaced w new, FP C- T'ATE OF ALASKA � Reviewed ey: OIL ANu GAS CONSERVATION COMMISSION P.1. Supry ! T '_ DIVERTER Test Report for: MILNE PT UNIT S-46 _ Comm Contractor/Rig No.: Hilcorp Innovation - PTD#: 2210450 — DATE: 7/10/2021 Inspector Adam Earl Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: J. Lott Rig Rep: M Courson Inspector Well Class: DEV Inspection No: divAGE210711160331 Related Insp No: M ISC. INSPECTIONS: P/F Location Gen.: -P Housekeeping: P " Warning Sign P 24 hr Notice: P " Well Sign: P " Drlg. Rig. P Misc: NA GAS DETECTORS: Visual Alarm Methane: P P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA TEST DATA MUD SYSTEM: Visual Alarm Trip Tank: P - ----- P " — ----- Mud Pits: - P_- -_ P- Flow Monitor: P P Mud System Misc: 0 NA ACCUMULATOR SYSTEM: Time/Pressure P/F Systems Pressure: 3100 P Pressure After Closure: 2000 P 200 psi Recharge Time: 16 P Full Recharge Time: 57 P Nitrogen Bottles (Number of): 6 P Avg. Pressure: 2241 P ' Accumulator Misc: 0 NA DIVERTER SYSTEM: Size P/F Designed to Avoid Freeze-up? P " Remote Operated Diverter? P No Threaded Connections? P Vent line Below Diverter? P Diverter Size: 13.62 P Hole Size: 12.25 P Vent Line(s) Size: 16 P Vent Line(s) Length: 211 P Closest Ignition Source: 81 P Outlet from Rig Substructure: 199 P " Vent Line(s) Anchored: P " Turns Targeted / Long Radius: NA Divert Valve(s) Full Opening: P Valve(s) Auto & Simultaneous: Annular Closed Time: 9 - P - Knife Valve Open Time: 5 P Diverter Misc: 0 NA Number of Failures: 0 Test Time: I Remarks: Good test Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU S-46 Hilcorp Alaska, LLC Permit to Drill Number: 221-045 Surface Location: 3186' FSL, 663' FEL, Sec. 12, T12N, R10E, UM, AK Bottomhole Location: 687' FSL, 803' FEL, Sec. 34, T13N, 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 AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this ___ day of June, 2021. 22 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.06.22 21:05:18 -04'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 16,020' TVD: 4,001' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 64.3' 15. Distance to Nearest Well Open Surface: x-565349 y- 5999850 Zone- 4 37.8' to Same Pool: 630' 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 129.5# X-52 80' Surface Surface 110' 110' 47# L-80 TXP 2,500' Surface Surface 2,500' 2,159' 40# L-80 TXP 3,100' 2,500' 2,159' 5,600' 3,978' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 10,570' 5,450' 3,962' 16,020' 4,001' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Nathan Sperry Monty Myers Contact Email:nathan.sperry@hilcorp.com Drilling Manager Contact Phone:777-8450 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 1688' July 13, 2021 12-1/4" 9-5/8" 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Uncemented Screen Liner Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Conductor/Structural LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Stg 1 L - 840 ft3 / T - 458 ft3 5120 18. Casing Program: Top - Setting Depth - BottomSpecifications 1750 Total Depth MD (ft): Total Depth TVD (ft): 22224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Sgt 2 L - 1935 ft3 / T - 313 ft3 1352 1721' FSL, 2527' FEL, Sec. 12, T12N, R10E, UM, AK 687' FSL, 803' FEL, Sec. 34, T13N, R10E, UM, AK 01-001 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 3186' FSL, 663' FEL, Sec. 12, T12N, R10E, UM, AK ADL 380109 & 025906 MPU S-46 Milne Point Field Schrader Bluff Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. ooo oo oo oo oo oo oo Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 6.4.2021 By Samantha Carlisle at 1:46 pm, Jun 04, 2021 Digitally 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: 2021.06.04 13:23:13 -08'00' Monty M Myers X XX DLB 06/22/2021 MGR09JUN21 221-045 DSR-6/7/21 SFD 6/22/2021 50-029-23695-00-00 X X X*BOPE test to 3000 psi. Annular to 2500 psi. *State witness MIT-IA to 2500 psi. 855 X X dts 6/22/2021 6/22/21 6/22/21Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.06.22 21:02:36 -04'00' Area of Review MPS-46PTDAPIWELL STATUSTop of SBNB (MD)Top of SBNB (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader NBstatusZonal Isolation195-198 50-029-22572-00-00 MPU H-05 Kup C Producer 6,229' 4,013' 5,289' 3,684' Closed2 stage cement job to isolateSchrader stage collar @ 7,104' MD,cement top calculated at 5,289'195-115 50-029-22580-00-00 MPU H-06 Kup C Injector 6,087' 3,983' Surface Surface ClosedCement to Surface 9-5/8" casing ranto 7,304' MD207-066 50-029-23358-00-00 MPU H-17 NB / NE Injector 7,203 4,067' N/A N/A OpenOpen to Injection Support202-009 50-029-23065-00-00 MPU S-21Shut-InNB / NE / OAInjector8,925' 4,064' Surface Surface ClosedAll Sands squeezed, pending sundryto re-open NB Sands202-085 50-029-23084-00-00 MPU S-27 OA Producer 7,567' 3,939' Surface Surface ClosedCement to Surface202-086 50-029-23084-60-00 MPU S-27L1 OB Producer 7,567' 3,939' Surface Surface ClosedCement to Surface203-092 50-029-23157-00-00 MPU S-32 Shut-In NB Producer 7,719' 3,944' N/A N/A OpenOpen to Injection Support202-236 50-029-23131-00-00 MPU S-30 Dual OA / OBa Injector 6,851' 3,956' 4,900' 3,241' Closed7" casing ran to 7,459' MD SCMTestimated top ~4,900'202-103 50-029-23089-00-00 MPU S-25 OB Producer5,746' 3,993'Surface SurfaceClosedCement to Surface202-104 50-029-23089-60-00 MPU S-25L1 OA Producer 5,746' 3,993' Surface Surface ClosedCement to Surface203-104 50-029-23162-00-00 MPU S-14Shut-In Ugnu / NBInjector6,540' 3,935' N/A N/A OpenOpen to Injection Support202-212 50-029-23123-00-00 MPU S-33 P&A'd 4,827' 3,999' N/A N/A ClosedP&A'd206-172 50-029-23123-01-00 MPU S-33A Dual OA / OB Injector 4,975' 3,982' 2,171' 2,070' Closed7" casing ran to 5,496' MD andcement top calculated at 2,171'203-038 50-029-23142-00-00 MPU S-24 Shut-In NB Producer 4,876' 4,029' 2,784' 2,624' Open7-5/8" casing ran to 5,024' MD andcement top calculated at 2,784'203-061 50-029-23150-00-00 MPU S-26 Dual OA / OB Injector 5,450' 3,989' 3,553' 2,890' Closed7" casing ran to 5,943' MD andcement top calculated at 3,553'221-042 50-029-23693-00-00 MPU S-45 NB Producer (not drilled) ~5,842' ~4,045' N/A N/A TBD - OpenOpen to Injection Support onceDrilledTBD TBD MPU S-47 NB Producer (not drilled) ~6,200' ~3,918' N/A N/A TBD - OpenOpen to Injection Support onceDrilled Milne Point Unit (MPU) S-46 Drilling Program Version 1 6/2/2021 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 RU and Preparatory Work ...................................................................................................... 10 10.0 NU 13-5/8” 5M Diverter Configuration .................................................................................. 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 NU BOP and Test..................................................................................................................... 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 33 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37 18.0 Innovation Rig Diverter Schematic ......................................................................................... 39 19.0 Innovation Rig BOP Schematic ............................................................................................... 40 20.0 Wellhead Schematic ................................................................................................................. 41 21.0 Days Vs Depth .......................................................................................................................... 42 22.0 Formation Tops & Information............................................................................................... 43 23.0 Anticipated Drilling Hazards .................................................................................................. 45 24.0 Innovation Rig Layout ............................................................................................................. 48 25.0 FIT Procedure .......................................................................................................................... 49 26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 50 27.0 Casing Design ........................................................................................................................... 51 28.0 8-1/2” Hole Section MASP ....................................................................................................... 52 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 53 30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 54 Page 2 Milne Point Unit S-46 SB Injector Drilling Procedure 1.0 Well Summary Well MPU S-46 Pad Milne Point “S” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff Nb Sand Planned Well TD, MD / TVD 16,020’ MD / 4,001’ TVD PBTD, MD / TVD 16,020’ MD / 4,001’ TVD Surface Location (Governmental) 2093' FNL, 663' FEL, Sec 12, T12N, R10E, UM, AK Surface Location (NAD 27) X= 565,349 Y=5,999,850 Top of Productive Horizon (Governmental)1721' FSL, 2527' FEL, Sec 12, T12N, R10E, UM, AK TPH Location (NAD 27) X= 563,498 Y=5,998,368 BHL (Governmental) 687' FSL, 803' FEL, Sec 34, T13N, R10E, UM, AK BHL (NAD 27) X= 559,863 Y=6,007,864 AFE Number AFE Drilling Days 17 days AFE Completion Days 3 days AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 1,353 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,749 psig Work String 5”, 19.5#, S-135, DS-50 & NC 50 KB Elevation above MSL: 26.5 ft + 37.8 ft = 64.3 ft GL Elevation above MSL: 37.8 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit S-46 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit S-46 SB Injector 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” 19.250”---X-52Weld 12-1/4”9-5/8” 8.835”8.679”10.625”40.0 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 8-1/2” 4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9,020 8,540 279 Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80 EUE 8 RD 10,160 10,535 207 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 GPDS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit S-46 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x 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. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x 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 x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp,com nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer David Gorm 907.777.8333 505.215.2819 dgorm@hilcorp.com Geologist John Salsbury 907.777.8481 907.350.1088 jsalsbury@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit S-46 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit S-46 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU S-46 is a grassroots injector planned to be drilled in the Schrader Bluff Nb sand. S-46 is part of a multi well program targeting the Schrader Bluff sand on S-pad The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff Nb sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” screened injection liner will be run in the open hole section. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately July 13th, 2021, pending rig schedule. Surface casing will be run to 5,600’ MD / 3,974’ 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 Innovation to well site 2. NU & Test 13-5/8” 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. ND diverter, NU & test 13-5/8” x 5M BOP. 5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner. 6. Run 3-1/2” tubing. 7. ND BOP, NU 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) GR + Res GR + ADR Page 8 Milne Point Unit S-46 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU S-46. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x 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 from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to Abhijeet.tambe@hilcorp.com for submission to AOGCC. x Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AAC 25.412 (d) through cement job operational reports of a complete two stage cement job on the 9-5/8” surface casing. Planned surface cement volumes and cement returns to surface seen during both stages will indicate placement of cement in the entire surface casing annulus. A successful FIT after surface casing drill out will demonstrate isolation of injection fluid. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AACppp 25.412 (d) through cement job operational reports o Page 9 Milne Point Unit S-46 SB Injector Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit 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: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x 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 S-46 SB Injector Drilling Procedure 9.0 RU and Preparatory Work 9.1 S-46 will utilize a newly set 20” conductor on S-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 landing 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 RU. 9.6 Rig mat footprint of the rig. 9.7 MIRU Innovation Rig. 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 (<80qF). 9.10 Set test plug in wellhead prior to NU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 5” liners in mud pumps. x White Star Quattro 1300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 11 Milne Point Unit S-46 SB Injector Drilling Procedure 10.0 NU 13-5/8” 5M Diverter Configuration 10.1 NU 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x NU 20” x 13-5/8” DSA x NU 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. 24 hour notice to AOGCC. Page 12 Milne Point Unit S-46 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: Page 13 Milne Point Unit S-46 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x 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. x 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 TD x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x 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. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x Adjust MW and viscosity as necessary to maintain hole stability. x Perform GWD surveys until MWD surveys are clean. Take MWD surveys every stand drilled as well. x Gas hydrates may be present on S-pad. Historically encountered hydrates are typically around 2,100’-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x 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 Gas hydrates may be present Page 14 Milne Point Unit S-46 SB Injector Drilling Procedure zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x 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 surface x A/C: x There are no wells with a clearance factor < 1.0 11.4 12-1/4” hole mud program summary: x 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+ x PVT System: 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, and mud loggers office. x 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. x 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 losses and strengthen the wellbore. x 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. x 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). 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 Page 15 Milne Point Unit S-46 SB Injector Drilling Procedure 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, CBU and condition the mud until the hole is clean while BROOH. Rack back stands but do not trip to bottom until the hole is clean. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 FPM, as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x 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 S-46 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and MU to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Top 2000’ of casing 47# drift 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & 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 with stop rings 1 joint –9-5/8” TXP, 1 Centralizer mid joint with 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 x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle 2500' Page 17 Milne Point Unit S-46 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit S-46 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POOH 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 (roughly ~ 2,500’ MD). x Install centralizers over couplings on 5 joints below and 10 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x 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 MU 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 2,3820 ft-lbs 26,200 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joint 1000’ above Shoe –2000’ above Shoe (Top of Ugnu)1/ 2 joints Page 19 Milne Point Unit S-46 SB Injector Drilling Procedure Page 20 Milne Point Unit S-46 SB Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing x 9-5/8” 47# from 2000’ to surface x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. 2500' Page 21 Milne Point Unit S-46 SB Injector Drilling Procedure 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 PU landing joint and MU 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. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit S-46 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct 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: 855 363 sx152.3 395 sx 5600' Page 23 Milne Point Unit S-46 SB Injector 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 top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x 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. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,000’ x 0.0732 BPF + (5,565’ – 120’ - 2,000’) x .0758 BPF = 407.6 bbls 80 bbls of tuned spacer to be left behind stage tool,confirm fluid is compatible with cement behind stage tool 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. 13.14 If plug is not bumped, consult 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 if the plugs are not bumped. 13.15 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 Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk (2500 * .0732) + ((5600 - 120 - 2500)* .0758) = 408.9 bbls Page 24 Milne Point Unit S-46 SB Injector Drilling Procedure 13.16 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. 13.17 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 components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit S-46 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2 nd 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. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd stage. 13.23 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 cement 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): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2,500’ x .0758 bpf = 190 bbls mud Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 437 sx 270 sx .0731 183 bbls Page 26 Milne Point Unit S-46 SB Injector Drilling Procedure 13.27 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. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 200 bbls of cement slurry to surface. 13.29 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 13.30 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: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 S-46 SB Injector Drilling Procedure 14.0 NU BOP and Test 14.1 ND the diverter T, 16” knife gate, 16” diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M CTI BOP as follows: x 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 x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in bottom cavity. x Single ram should be dressed with 2-7/8” x 5-1/2” VBRs or 5” Solid Body Rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5” BOP test plug (if not installed previously). x Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.4 RD BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 24 hour notice to AOGCC. Page 28 Milne Point Unit S-46 SB Injector 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 with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on morning 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 for 30 minutes charted. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = ~3500 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. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x 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. Casing and FIT digital data to AOGCC. Page 29 Milne Point Unit S-46 SB Injector Drilling Procedure x 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. x 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 x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N 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 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid Page 30 Milne Point Unit S-46 SB Injector Drilling Procedure 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations. x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart 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. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ x 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. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x 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. x Use ADR to stay in section. x 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. x Schrader Bluff Nb Concretions: 4-6% of lateral x A/C, wells with < 1.0 clearance factor: x H-17 has a clearance factor of 0.427. H-17 is a Schrader water injector that is shut-in and scheduled to be P&A’d. x S-24 has a clearance factor of 0.909. S-24 is a long term shut-in Schrader producer that is scheduled to be P&A’d. x S-34L2 has a clearance factor of 0.975. S-34 is a long term shut-in Schrader producer that does not pose an HSE risk. x S-35 has a clearance factor of 0.362. S-35 is a Schrader producer that is scheduled to be P&A’d. 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. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up.NOTE: In Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse. Page 31 Milne Point Unit S-46 SB Injector Drilling Procedure x 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. x 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 FPM AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x Ensure mud has necessary lube % for running liner x 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. Displace 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. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5 pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. x Record SO, PU weights and rotating torque to compare to pre-brine values in report. 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). x Rotate at maximum rpm that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe Page 32 Milne Point Unit S-46 SB Injector Drilling Procedure 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 for flow / pressure build up with MPD. Increase fluid weight if necessary x 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 15.23 POOH laying down DP. Only rack back the length needed to run the liner. 15.24 Continue to POOH and LD BHA. Rabbit DP on TOOH, 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. Only LWD open hole logs (GR + Res) p treat all flow as an influx until proven otherwise Page 33 Milne Point Unit S-46 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) 16.1. Confirm VBR’s have been tested on 3-1/2” and 5” test joints to 250/3,000 psi. 16.2.Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” production screens, the following well control response procedure will be followed: x PU & MU 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 MU and available prior to running the first joint of 4-1/2” screen. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. x Proceed with well kill operations. 16.3. RU 4-1/2” liner running equipment. x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. 16.4. Run 4-1/2” screen injection liner – Reference screen handling and running procedure. x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound will plug the screens. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run packoff and float shoe on bottom. x 4-1/2” Screens should auto–fill, top off with completion brine if needed x Swell packers will not be required on this completion unless the well is drilled out of zone x If needed, install swell packers as per the lower completion tally. x Remove protective packaging on swell packers just prior to picking up x Do not place tongs or slips on the packer element 4-1/2”, 13.5#, L-80, Hydril 625 MU Torques Casing OD Minimum Optimum Maximum Operating Torque Yield Torque 4-1/2”8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 34 Milne Point Unit S-46 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger/packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. Page 35 Milne Point Unit S-46 SB Injector Drilling Procedure 16.8. MU Baker SLZXP liner hanger/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 FPM – this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during 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. 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 ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to neutralize and release running tools. 16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Contingency (if suspected not released from running tool) - 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. Page 36 Milne Point Unit S-46 SB Injector Drilling Procedure 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. POOH laying down DP/HWDP. LD and inspect the liner running tools. Once running tools are LD, swap to the Completion AFE. Page 37 Milne Point Unit S-46 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to abhijeet.tambe@hilcorp.com for submission to AOGCC. 17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 FPM. x Ensure wear bushing is pulled. x Ensure 3-1/2” EUE 8rd x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” Upper Completion Running Order: x 7.30” Baker Ported Bullet Nose seal (stung into the tie back receptacle, crossover to 3-1/2”, 9.3#, EUE 8rd) x 3 joints (minimum, more as needed), 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” “XN” nipple at TBD (less than 70° hole angle) x 1 joints, 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” Baker gauge mandrel o Cross collar clamps: Every joint for first 10 joints, every other joint beyond this to surface x XX Joints, 3-1/2”, 9.3#, EUE 8rd tubing x Space out pup(s), 3-1/2”, 9.3#, EUE 8rd tubing x 1 joint, 3-1/2”, 9.3#, EUE 8rd tubing x Tubing hanger with 3-1/2” EUE 8rd pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 500 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (±2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 38 Milne Point Unit S-46 SB Injector Drilling Procedure 17.5 MU the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with corrosion inhibited brine. 17.8 Freeze protect the IA to ~2,000’ TVD (base on actual well deviation) with diesel. 17.9 Land hanger and RILDS. 17.10 PT the IA to 2,500 psi for 30 minutes charted. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. 17.12 ND BOPE and install the plug off tool into the BPV. 17.13 NU the tubing head adapter and NU the tree. 17.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 17.15 Pull the plug off tool from the BPV. 17.16 Bullhead diesel down the tubing to ~2,000’ TVD (base on actual well deviation). 17.17 Install all tree gauges. Secure the tree and cellar. Release the rig. 17.18 RDMO the Innovation Rig. 17.19 Turn the well over to operations via handover form. 24 hour notice. Page 39 Milne Point Unit S-46 SB Injector Drilling Procedure 18.0 Innovation Rig Diverter Schematic Page 40 Milne Point Unit S-46 SB Injector Drilling Procedure 19.0 Innovation Rig BOP Schematic Page 41 Milne Point Unit S-46 SB Injector Drilling Procedure 20.0 Wellhead Schematic Page 42 Milne Point Unit S-46 SB Injector Drilling Procedure 21.0 Days Vs Depth Page 43 Milne Point Unit S-46 SB Injector Drilling Procedure 22.0 Formation Tops & Information Page 44 Milne Point Unit S-46 SB Injector Drilling Procedure Page 45 Milne Point Unit S-46 SB Injector Drilling Procedure 23.0 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 hyrates have been seen on S-Pad. Remember that hydrate gas behave 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. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. 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 stream. 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 hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well Specific A/C: x 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 between 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 46 Milne Point Unit S-46 SB Injector Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 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. Page 47 Milne Point Unit S-46 SB Injector 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. Maintain 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 is one mapped fault crossing. If an unmapped fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 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: Abnormal pressure can be seen on S-Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. x H-17 has a clearance factor of 0.427. H-17 is a Schrader water injector that is shut-in and scheduled to be P&A’d. x S-24 has a clearance factor of 0.909. S-24 is a long term shut-in Schrader producer that is scheduled to be P&A’d. x S-34L2 has a clearance factor of 0.975. S-34 is a long term shut-in Schrader producer that does not pose an HSE risk. x S-35 has a clearance factor of 0.362. S-35 is a Schrader producer that is scheduled to be P&A’d. Take directional surveys every stand, Utilize MPD to mitigate any abnormal pressure seen. Page 48 Milne Point Unit S-46 SB Injector Drilling Procedure 24.0 Innovation Rig Layout Page 49 Milne Point Unit S-46 SB Injector Drilling Procedure 25.0 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 test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 50 Milne Point Unit S-46 SB Injector Drilling Procedure 26.0 Innovation Rig Choke Manifold Schematic Page 51 Milne Point Unit S-46 SB Injector Drilling Procedure 27.0 Casing Design Page 52 Milne Point Unit S-46 SB Injector Drilling Procedure 28.0 8-1/2” Hole Section MASP Page 53 Milne Point Unit S-46 SB Injector Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 54 Milne Point Unit S-46 SB Injector Drilling Procedure 30.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW -XQH 3ODQ0386LZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 3ODQ0386L 0386L -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 South(-)/North(+) (1500 usft/in)-7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 West(-)/East(+) (1500 usft/in) MPU S-46 wp05 toe MPU S-46 wp06 CP4a MPU S-46 wp05 CP3 MPU S-46 wp03 CP2 MPU S-46 wp03 CP2 (±) MPU S-46 wp03 CP1 MPU S-46 wp07a Heel 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 750 1250 1750 2250 2750 3250350037504 0 0 0 4 0 0 1 MPU S-46i wp08 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 550' MD, 548.77'TVD End Dir : 1301.2' MD, 1227.06' TVD Start Dir 4º/100' : 2882.82' MD, 2455.38'TVD End Dir : 5409.61' MD, 3958.23' TVD Start Dir 4º/100' : 5559.61' MD, 3971.3'TVD End Dir : 5707.1' MD, 3976.67' TVD Start Dir 3º/100' : 5948.8' MD, 3973.17'TVD Start Dir 2º/100' : 6585.96' MD, 3957.3'TVD End Dir : 7658.3' MD, 3941.76' TVD Start Dir 2º/100' : 9427.59' MD, 3952.84'TVD End Dir : 9987.81' MD, 3957.13' TVD Start Dir 2º/100' : 11566.33' MD, 3969.44'TVD End Dir : 12660.79' MD, 3996.45' TVD Start Dir 2º/100' : 13185.82' MD, 4055.62'TVD Start Dir 2.5º/100' : 13350.1' MD, 4069.9'TVD End Dir : 14302.09' MD, 4077.86' TVD Total Depth : 16019.89' MD, 4001.3' TVD CASING DETAILS TVD TVDSS MD Size Name 3974.26 3909.96 5600.00 9-5/8 9 5/8" x 12 1/4" 4001.30 3937.00 16019.89 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-46i Wellbore: MPU S-46i Plan: MPU S-46i wp08 WELL DETAILS: Plan: MPU S-46i 37.80 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 5999849.76 565348.54 70° 24' 36.154 N 149° 28' 4.412 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU S-46i, True North Vertical (TVD) Reference:MPU S-46 As-built RKB @ 64.30usft Measured Depth Reference:MPU S-46 As-built RKB @ 64.30usft Calculation Method:Minimum Curvature 0650130019502600325039004550True Vertical Depth (1300 usft/in)-1950 -1300 -650 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 7150 7800 8450 9100 9750 10400Vertical Section at 330.00° (1300 usft/in)MPU S-46 wp07a HeelMPU S-46 wp03 CP1MPU S-46 wp03 CP2 (±)MPU S-46 wp03 CP2MPU S-46 wp05 CP3MPU S-46 wp06 CP4aMPU S-46 wp05 toe9 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006 000 650 0 7 000 7500 8000 8500 9000 9500 100 00 10500 11000 11500 12000 12500 1 3000 13500 14000 1 45 0 0 1 5 0 0 0 1 5 5 0 0 1 6 0 2 0MPU S-46i wp08Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 550' MD, 548.77'TVDEnd Dir : 1301.2' MD, 1227.06' TVDStart Dir 4º/100' : 2882.82' MD, 2455.38'TVDEnd Dir : 5409.61' MD, 3958.23' TVDStart Dir 4º/100' : 5559.61' MD, 3971.3'TVDEnd Dir : 5707.1' MD, 3976.67' TVDStart Dir 3º/100' : 5948.8' MD, 3973.17'TVDStart Dir 2º/100' : 6585.96' MD, 3957.3'TVDEnd Dir : 7658.3' MD, 3941.76' TVDStart Dir 2º/100' : 9427.59' MD, 3952.84'TVDEnd Dir : 9987.81' MD, 3957.13' TVDStart Dir 2º/100' : 11566.33' MD, 3969.44'TVDEnd Dir : 12660.79' MD, 3996.45' TVDStart Dir 2º/100' : 13185.82' MD, 4055.62'TVDStart Dir 2.5º/100' : 13350.1' MD, 4069.9'TVDEnd Dir : 14302.09' MD, 4077.86' TVDTotal Depth : 16019.89' MD, 4001.3' TVDBPRFUG3 CoalUG2 CoalLA3LA1UG MAUG MBUG MCUG MDUG MESB NASB_NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU S-46i37.80+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.005999849.76565348.54 70° 24' 36.154 N 149° 28' 4.412 WSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 500.00 MPU S-46i wp08 (MPU S-46i) 3_Gyro-GC_Csg500.00 5600.00 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+Sag5600.00 16019.89 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1865.30 1801.00 2123.01 BPRF2939.30 2875.00 3484.84 UG3 Coal3197.30 3133.00 3811.73 UG2 Coal3543.30 3479.00 4304.47 LA33608.30 3544.00 4411.70 LA13769.30 3705.00 4721.12 UG MA3795.30 3731.00 4780.63 UG MB3817.30 3753.00 4834.36 UG MC3851.30 3787.00 4925.42 UG MD3937.30 3873.00 5250.76 UG ME3964.30 3900.00 5479.29 SB NA3971.30 3907.00 5559.61 SB_NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-46i, True NorthVertical (TVD) Reference:MPU S-46 As-built RKB @ 64.30usftMeasured Depth Reference:MPU S-46 As-built RKB @ 64.30usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt S PadWell:Plan: MPU S-46iWellbore:MPU S-46iDesign:MPU S-46i wp08CASING DETAILSTVD TVDSS MD SizeName3974.26 3909.96 5600.00 9-5/8 9 5/8" x 12 1/4"4001.30 3937.00 16019.89 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 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 550.00 9.00 185.00 548.77 -23.42 -2.05 3.00 185.00 -19.26 Start Dir 4º/100' : 550' MD, 548.77'TVD4 1301.20 39.05 185.55 1227.06 -324.39 -30.73 4.00 0.70 -265.57 End Dir : 1301.2' MD, 1227.06' TVD5 2882.82 39.05 185.55 2455.38 -1316.08 -127.13 0.00 0.00 -1076.19 Start Dir 4º/100' : 2882.82' MD, 2455.38'TVD6 5409.61 85.00 300.00 3958.23 -1540.37 -1734.20 4.00 112.47 -466.90 End Dir : 5409.61' MD, 3958.23' TVD7 5559.61 85.00 300.00 3971.30 -1465.65 -1863.61 0.00 0.00 -337.49 MPU S-46 wp07a Heel Start Dir 4º/100' : 5559.61' MD, 3971.3'TVD8 5707.10 90.83 300.91 3976.67 -1390.97 -1990.61 4.00 8.94 -209.31 End Dir : 5707.1' MD, 3976.67' TVD9 5948.80 90.83 300.91 3973.17 -1266.80 -2197.95 0.00 0.00 1.89 Start Dir 3º/100' : 5948.8' MD, 3973.17'TVD10 6585.96 92.00 320.00 3957.30 -855.42 -2680.38 3.00 86.28 599.37 MPU S-46 wp03 CP1 Start Dir 2º/100' : 6585.96' MD, 3957.3'TVD11 7658.30 89.64 341.32 3941.76 73.84 -3202.64 2.00 96.09 1665.27 End Dir : 7658.3' MD, 3941.76' TVD12 9427.59 89.64 341.32 3952.84 1749.90 -3769.30 0.00 0.003400.11 Start Dir 2º/100' : 9427.59' MD, 3952.84'TVD13 9493.73 89.56 340.00 3953.30 1812.31 -3791.20 2.00 -93.53 3465.10 MPU S-46 wp03 CP2 (±)14 9987.81 89.55 349.88 3957.13 2288.81 -3919.41 2.00 90.08 3941.87 End Dir : 9987.81' MD, 3957.13' TVD15 11566.33 89.55 349.88 3969.44 3842.74 -4196.71 0.00 0.00 5426.27 Start Dir 2º/100' : 11566.33' MD, 3969.44'TVD16 12310.40 89.55 335.00 3975.30 4550.13 -4420.55 2.00 -90.07 6150.80 MPU S-46 wp05 CP317 12660.79 83.53331.41 3996.45 4862.14 -4578.09 2.00 -149.31 6499.78 End Dir : 12660.79' MD, 3996.45' TVD18 13185.82 83.53331.41 4055.62 5320.20 -4827.77 0.00 0.00 7021.31 Start Dir 2º/100' : 13185.82' MD, 4055.62'TVD19 13350.10 86.50 330.00 4069.90 5462.90 -4907.84 2.00 -25.32 7184.93 MPU S-46 wp06 CP4a Start Dir 2.5º/100' : 13350.1' MD, 4069.9'TVD20 14302.09 92.55 353.03 4077.86 6359.29 -5207.43 2.50 75.56 8111.02 End Dir : 14302.09' MD, 4077.86' TVD21 16019.89 92.55 353.03 4001.30 8062.70 -5415.72 0.00 0.00 9690.36 MPU S-46 wp05 toe Total Depth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eparation Factor0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-46i NAD 1927 (NADCON CONUS)Alaska Zone 0437.80+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999849.76565348.5470° 24' 36.154 N149° 28' 4.412 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-46i, True NorthVertical (TVD) Reference:MPU S-46 As-built RKB @ 64.30usftMeasured Depth Reference:MPU S-46 As-built RKB @ 64.30usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 MPU S-46i wp08 (MPU S-46i) 3_Gyro-GC_Csg500.00 5600.00 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+Sag5600.00 16019.89 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPS-39MPS-41MPS-43MPU S-203MPU S-56PB1MPU S-201 wp07MPU S-44i wp06MPU S-47 wp06MPU S-48i wp04MPU S-45MPU S-45 wp07GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 16019.89Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-46iWellbore: MPU S-46iPlan: MPU S-46i wp08Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3974.26 3909.96 5600.00 9-5/8 9 5/8" x 12 1/4"4001.30 3937.00 16019.89 4-1/2 4 1/2" x 8 1/2" &OHDUDQFH6XPPDU\$QWLFROOLVLRQ5HSRUW-XQH+LOFRUS$ODVND//&0LOQH3RLQW03W63DG3ODQ0386L0386L0386LZS5HIHUHQFH'HVLJQ03W63DG3ODQ0386L0386L0386LZS&ORVHVW$SSURDFK'3UR[LPLW\6FDQRQ&XUUHQW6XUYH\'DWD+LJKVLGH5HIHUHQFH:HOO&RRUGLQDWHV1( 1 :'DWXP+HLJKW0386$VEXLOW5.%#XVIW6FDQ5DQJHWRXVIW0HDVXUHG'HSWK*HRGHWLF6FDOH)DFWRU$SSOLHG9HUVLRQ%XLOG(6FDQ5DGLXVLV8QOLPLWHG&OHDUDQFH)DFWRUFXWRIILV8QOLPLWHG0D[(OOLSVH6HSDUDWLRQLVXVIW*/2%$/),/7(5$33/,('$OOZHOOSDWKVZLWKLQ RIUHIHUHQFH6FDQ7\SH6FDQ7\SH 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eparation Factor5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-46i NAD 1927 (NADCON CONUS)Alaska Zone 0437.80+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999849.76565348.5470° 24' 36.154 N 149° 28' 4.412 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-46i, True NorthVertical (TVD) Reference:MPU S-46 As-built RKB @ 64.30usftMeasured Depth Reference:MPU S-46 As-built RKB @ 64.30usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 MPU S-46i wp08 (MPU S-46i) 3_Gyro-GC_Csg500.00 5600.00 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+Sag5600.00 16019.89 MPU S-46i wp08 (MPU S-46i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)MPH-17MPS-24MPS-24PB2MPS-35GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 16019.89Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-46iWellbore: MPU S-46iPlan: MPU S-46i wp08CASING DETAILSTVD TVDSS MD Size Name3974.26 3909.96 5600.00 9-5/8 9 5/8" x 12 1/4"4001.30 3937.00 16019.89 4-1/2 4 1/2" x 8 1/2"Ladder / S.F. Plots2 of 2 1 Davies, Stephen F (CED) From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent:Monday, June 21, 2021 9:42 AM To:Nathan Sperry; Davies, Stephen F (CED) Cc:John Salsbury Subject:RE: [EXTERNAL] RE: MPU S-46 (PTD 221-045) - Question Steve, MPU S‐28, S‐28PB1 and S‐28PB2 are close but not in the ¼ mile area for MPU S‐46. The other wells (MPU S‐34 and MPU S‐35 plus PB’s) also do not fall within the ¼ section for MPU S‐46. Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Tuesday, June 15, 2021 3:39 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: Fwd: [EXTERNAL] RE: MPU S‐46 (PTD 221‐045) ‐ Question For you Sent from my iPhone Begin forwarded message: From: "Davies, Stephen F (CED)" <steve.davies@alaska.gov> Date: June 15, 2021 at 1:53:52 PM AKDT To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: [EXTERNAL] RE: MPU S‐46 (PTD 221‐045) ‐ Question Nathan, In addition to MPU S‐28, S‐28 PB1, S‐28PB2, could you also please check MPU S‐34, S‐34 L1, S‐34 L2, MPU S‐35, and MPU S‐35PB2 to see if any of these wellbores lie within the Area of Review for MPU S‐ 46? If so, please update the cement evaluation table provided in support of Hilcorp’s application. Thanks again and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 2 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Tuesday, June 15, 2021 1:05 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: MPU S‐46 (PTD 221‐045) ‐ Question Nathan, I’m reviewing Hilcorp’s Permit to Drill application and the attendant Area of Review for this planned injection well. Do MPU S‐28 or either of its two plugged‐back wellbores fall within one‐quarter mile of the planned S‐46 injection well? If so, please update the cement evaluation table provided in support of Hilcorp’s application. Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 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. 1 Davies, Stephen F (CED) From:Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent:Wednesday, June 16, 2021 7:07 AM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] RE: MPU S-46 (PTD 221-045) - Question Good morning Steve, There are no plans to pre‐produce for an extended period of time. We are looking into those wells you mentioned and will get back to you soon. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Tuesday, June 15, 2021 3:02 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: [EXTERNAL] RE: MPU S‐46 (PTD 221‐045) ‐ Question Nathan, One final question in addition to my requests below: Will MPU S‐46 be pre‐produced of an extended period of time or flowed back briefly for clean up? Thanks again and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Tuesday, June 15, 2021 1:54 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: RE: MPU S‐46 (PTD 221‐045) ‐ Question Nathan, 2 In addition to MPU S‐28, S‐28 PB1, S‐28PB2, could you also please check MPU S‐34, S‐34 L1, S‐34 L2, MPU S‐35, and MPU S‐35PB2 to see if any of these wellbores lie within the Area of Review for MPU S‐46? If so, please update the cement evaluation table provided in support of Hilcorp’s application. Thanks again and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Davies, Stephen F (CED) Sent: Tuesday, June 15, 2021 1:05 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: MPU S‐46 (PTD 221‐045) ‐ Question Nathan, I’m reviewing Hilcorp’s Permit to Drill application and the attendant Area of Review for this planned injection well. Do MPU S‐28 or either of its two plugged‐back wellbores fall within one‐quarter mile of the planned S‐46 injection well? If so, please update the cement evaluation table provided in support of Hilcorp’s application. Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) 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 Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. 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. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 221-045 Milne Point, Schrader Bluff Oil X Milne Point X X Milne Point Unit S-46 :(//3(50,7&+(&./,67&RPSDQ\+LOFRUS$ODVND//&:HOO1DPH0,/1(3781,76,QLWLDO&ODVV7\SH6(53(1'*HR$UHD8QLW2Q2II6KRUH2Q3URJUDP6(5)LHOG 3RRO:HOOERUHVHJ$QQXODU'LVSRVDO37'0,/1(32,176&+5$'(5%/))2,/1$ 3HUPLWIHHDWWDFKHG<HV 6XUIDFHORFDWLRQDQGWRSSURGLQWHUYDOLQ$'/7'LQ$'/ /HDVHQXPEHUDSSURSULDWH<HV 8QLTXHZHOOQDPHDQGQXPEHU<HV 0LOQH3RLQW6FKUDGHU%OXII2LO3RROJRYHUQHGE\&2DPHQGHGE\&2 :HOOORFDWHGLQDGHILQHGSRRO<HV &2VSHFLILHV³7KHUHDUHQRUHVWULFWLRQVDVWRZHOOVSDFLQJH[FHSWWKDWQRSD\VKDOO :HOOORFDWHGSURSHUGLVWDQFHIURPGULOOLQJXQLWERXQGDU\<HV EHRSHQHGLQDZHOOFORVHUWKDQIHHWIURPWKHH[WHULRUERXQGDU\RIWKHDIIHFWHGDUHD´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