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Home My WebLink About219-193Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 03/23/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-34 (219-193) Halliburton LWD FINAL 24 JAN 2020 MPU M-34 Please include current contact information if different from above. PTD: 2191930 E-Set: 33714 Received by the AOGCC 08/31/2020 Abby Bell 08/31/2020 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23662-00-00Well Name/No. MILNE PT UNIT M-34Completion Status1-OILCompletion Date1/30/2020Permit to Drill2191930Operator Hilcorp Alaska, LLCMD18100TVD3798Current Status1-OIL4/7/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP/ABG/DGR/EWR/ADR 2"/5" MD...ABG/DGR/EWR/ADR 2"/5" TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC3/25/2020112 18100 Electronic Data Set, Filename: MPU M-34 LWD Final.las32256EDDigital DataC3/25/20207180 18062 Electronic Data Set, Filename: MPU M-34 ADR Quadrants All Curves.las32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final MD.cgm32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final TVD.cgm32256EDDigital DataC3/25/2020 Electronic File: MPU M-34_Definitive Survey Report.pdf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34_Definitive Survey Report.txt32256EDDigital DataC3/25/2020 Electronic File: MPU M-34_GIS.txt32256EDDigital DataC3/25/2020 Electronic File: MPU M-34_Plan.pdf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34_VSec.pdf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final MD.emf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final TVD.emf32256EDDigital DataC3/25/2020 Electronic File: MPU_M-34_Geosteering.dlis32256EDDigital DataC3/25/2020 Electronic File: MPU_M-34_Geosteering.ver32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final MD.pdf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final TVD.pdf32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final MD.tif32256EDDigital DataC3/25/2020 Electronic File: MPU M-34 LWD Final TVD.tif32256EDDigital Data0 0 2191930 MILNE PT UNIT M-34 LOG HEADERS32256LogLog Header ScansTuesday, April 7, 2020AOGCCPage 1 of 2MPU M-34 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23662-00-00Well Name/No. MILNE PT UNIT M-34Completion Status1-OILCompletion Date1/30/2020Permit to Drill2191930Operator Hilcorp Alaska, LLCMD18100TVD3798Current Status1-OIL4/7/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:1/30/2020Release Date:1/2/2020Tuesday, April 7, 2020AOGCCPage 2 of 2M. Guhl4/7/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Hacnrrn Alwka, UA; E-mail: doudean@hilcorp.com DATE 03/23/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician g 333 W 7th Ave Ste 100 RECEIVED Anchorage, AK 99501 710 MUFF M, MAR 2 5 2020 • AOGCC Halliburton LWD FINAL 24 JAN 2020 MPU M-34 _Log Viewers 3,123/202011:13 AM Filefolder CGM 3/23/202011;16 AM Filefolder Definitive Survey 3123/202011;12 AM File fotder EMF 3/23f202011:12 AM Filefolder LAS 3/23/202011; 12 AM Filefolder PDF 3123/202011:12 AM Filefolder TIFF 3./23/202011:13AM Filefolder Please include current contact information if different from above. 219193 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 u FEB 2 0 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION q WELL COMPLETION OR RECOMPLETION REPORT 1 a. Well Status: Oil ❑✓ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: 1 1 b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 1/30/2020 14. Permit to Drill Number / Sundry: 219-193 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: January 8, 2020 15. API Number: 50-029-23662-00-00 4a. Location of Well (Governmental Section): Surface: 4914' FSL, 381' FEL, Sec 14, T13N, R9E, UM, AK Top of Productive Interval: 18' FSL, 2069' FWL, Sec 13, T13N, R9E, UM, AK Total Depth: 1915 FSL, 1796 FEL, Sec 30, T1 3N, R1 OE, UM, AK 8. Date TD Reached: January 21, 2020 16. Well Name and Number: MPU M-34 9. Ref Elevations: KB: 58.8' GL: 25.4' BF: 25.4' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 18,100 MD / 3,798' TVD 18. Property Designation: , r ADL025514, ADL025515, ADL025517 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 533783 ' y- 6027765 Zone- 4 TPI: x- 536259 y- 6022881 Zone- 4 Total Depth: x- 542968 y- 6014254 Zone- 4 11. Total Depth MD/TVD: 18,100 MD / 3,798' TVD 19. DNR Approval Number: LONS 16-004 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,428' MD / 1,854' TVD 5. Directional or Inclination Survey: Yes I (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 2"/5" TVD 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20° 216# X-52 Surface 114' Surface 114' 42" ±270 ft3 9-5/8" 40# L-80 Surface 7,192' Surface 3,900' 12-1/4" Stg 1 L - 600 sx / T - 400 sx Stg 2 L - 687 sx / T - 270 sx 266 bbls 7" 26# L-80 Surface 7,019' Surface 3,890' Tieback Tieback Assy. 6-5/8" 20# L-80 1 7,005' 18,100' 3,889 3,798' 8-1/2" Cementless Slotted Liner 24. Open to production or injection? Yes ❑✓ No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 'Please see attached schematic for details' Liner run on 1/25/2020 COMPLETION �+TWas ��(j VE' -',IR E D 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" 7,027' 6,270' MD / 3,725' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. hydraulic fracturing used during completion? Yes ❑ No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 2/12/2020 Method of Operation (Flowing, gas lift, etc.): Jet Pump Date of Test: 2/14/2020 Hours Tested: 24 Production for Test Period Oil -Bbl: 1477 Gas -MCF: 528 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: 357 Flow Tubing Press. 321 Casing Press: 3259 Calculated 24 -Hour Rate Oil -Bbl: 1477 Gas -MCF: 528 Water -Bbl: 0 Oil Gravity - API (corr): 18.8 Form 10-407 Revised 5/2017, �/C *I QU ON PAGE 2 RBDMS � FEB 2 4 2020 Submit ORIGINIAL only W *-dB 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No 0 If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,428' 1,854' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 7,197' SB Oba 3,900' information, including reports, per 20 AAC 25.071. SV5 1,421' 1,288' SV1 2,506' 1,892' ' Ugnu LA3 5,093' 3,145' SB NA 6,072' 3,641' SB OA 6,542' 3,813' SB Oba 7,104' 3,894' 061 Formation at total depth: 5'60bt 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. 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. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name; Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdin er Ld9QE .COfTI AuthorizedContact Phone: 777.8389 419ZO Z., Signature: Date: 240 INSTRUCTIONS General: This f rm 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. Item 1 a: 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. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: 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. Item 30: 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. Item 31: 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. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Rilcorp Alaska, LLC 20" &98"'ES Cementer @ 2,657 SCHEMATIC Milne Point Unit Well: MPU M-34 Last Completed: 01/30/20 PTD: 219-193 TREE & WELLHEAD Elev.: 25.4' Tree Cameron 41/16" 5M 1 ) FMC 11" 5M TC -1A w/11" x 3 1/2" TC -II Top and Bottom Tubing Wellhead Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL R 5 7' �t 7 Min ID 8 2.750" s� El 9 9-5/8" 8 6-5/8" -1/2" IIIIII Shoe @ Hole 18,100 13 TD =18,100' (MD) / TD = 3,798'(TVD) PBTD =18,100' (MD) / TD = 3,798(TVD) CASING DETAIL Size Type 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4" 1st stage L— 600 sx/ T — 400 sx 12-1/4" 2nd stage L — 687 sx / T — 270 sx 8-1/2" Cementless Slotted Liner in 8-1/2" hole R 5 7' �t 7 Min ID 8 2.750" s� El 9 9-5/8" 8 6-5/8" -1/2" IIIIII Shoe @ Hole 18,100 13 TD =18,100' (MD) / TD = 3,798'(TVD) PBTD =18,100' (MD) / TD = 3,798(TVD) CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34" Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114' N/A 9-5/8" Surface 40 / L-80 / TXP 8.679" Surface 7,192' 0.0758 7" Tieback 26/ L-80 / TXP 6.151" Surface 7,019' 0.0383 6-5/8" Slotted Liner 20 / L-80 / Hydril 563 5.924" 1 7,005' 18,100' 0.0355 2.750" Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap 7,028' TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.867" Surface 1 7,027' 0.0087 WELL INCLINATION DETAIL KOP @ 316' S _ T-� Max Hole Angle = 67 @ Jet Pump Max Hole Angle = 68 @ XN profile 3 V r � Max Hole Angle = 87 @ Tubing tail Max Hole Angle = 97 JEWELRY DETAIL No. Top MD Item Drift ID 7,197' 3,900' Upper Completion 9,510' 1 28.5' 11" x 4-1/2" TC II Tubing Hanger 3.970" 3 2,493' 3.5" GLM 1" 2000 psi 2.920" 4 6,215' 3.5" XD Sliding Sleeve 2.813" 5 6,227' 3.5" Gauge Mandrel w/ A" Wire (Intake Gauge) 3.889" 6 6,248' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 6,270' 1 7" x 3.5" PHL Retrievable Packer 2.885" 8 6,296' 3.5" XN Nipple (MIN ID = 2.75") 2.750" 9 7,028' 3.5" WLEG 2.989" Lower Completion 10 7,005' BOT SLZXP Liner Top Packer w/BD Slips 7" x 9-5/8" 6.170" 11 7,019' 7" Tieback Assy. (8.25" OD No -Go) 6.151" 12 7,027' 7" Hydril 563 L-80 x 6-5/8" Hydril 563 L-80 XO 5.924" 13 18,100' Round nose float shoe - 6-5/8" SOLID LINER DETAIL its Top Top Btnn Btm (MD) (TVD) (MD) (TVD) 4 7,032' 3,891' 7,197' 3,900' 4 9,510' 3,879' 9,674' 3,881' 13 10,443' 3,896' 1 10,973' 3,845' 1 18,057' 3,799' 1 18,098' 3,798' GENERAL WELL INFO API: 50-029-23662-00-00 Drilled and Completed by Doyon 14 1/30/20 6-5/8" Slotted LINER DETAIL 4 rows. 8 slots/row. 2"x0.125" slots on 6" centers its (Mp) Top (TVD) Btm (MD) Btm (TVD) 57 ' 7,197' 3,900' 9,510' 3,879' 19 9,674' 3,881' 10,443' 3,896' 177 10,973' 3,845' 18,057' 3,799' Revised By: CJD 2/20/2019 Hilcorp Energy Company Composite Report Well Name: MP M-34 Field: Milne Point County/State: North Slope Borough, Alaska (LAT/LONG): avation (RKB): API #: Spud Date: Job Name: 2010034D MPU M-34 Drilling Contractor Doyon 14 AFE #: * AFE $: Actruity Date _p.Summary 1/6/2020 Please see M-19 for activities.;Warm front wheel wells with heaters in preparation for move. Clean and prep rig for move. Prep for rig move. Wait on peak trucks from dead horse to move rock washer and bulk tank. Milne point winch trucks broke down in -40°F and shut down.;PJSM. Move rockwasher and bulk fuel trailer. Skid rig floor into moving position. Broke a cylinder dog pin handle during operation, weld handle back into place.;Jack up rig and remove shims. Move rig off M-19 and stage in center of pad Move rig matts from M-19, spot transition matts to M-34 Move rig over M-34 spot, level and shim Ri .:Skid rig floor into drilling position. R/U rockwasher & fuel trailer. Spot service buildings. 1/7/2020 Work on rig acceptance checklist. Spot out buildings, Water pump house, Water tanks, Work on N/U Diverter line. -40 Below. Put BHA in pipe shed & start testing, Load HWDP, Jars and NMFDC. Change out broken water pump on rig. repair broke lines in pits from freezing.; Scientific drilling and AK eline test Gyro tools and take starting measurements on rig floor. Strap BHA tools.;lnstall 20" riser on bag, start loading spud mud to pits, troubleshoot TopDrive power problems. Install mouse holes in rig floor.;Cut and slip 53' drilling line. Service TopDrive, Replace DC power supply in TopDrive VFD house.;Change out TopDrive saver -sub, Perform Derrick Inspection.; Pick up and rack 6 stands 5" HWDP and jars in Derrick. Work on aettina H2O into tank upright. 1/8/2020 Finish Rig Acceptance checklist, Thaw frozen water pump lines and wrap with steam and herculite. Prep DP pipe in shed for drilling.; Perform diverter function test with AOGCC rep Austin McLeod to witness. Good test and review of Knife valve open, 10 sec. Annular Closed in 24 sec. Accumulator draw down- 3000 Starting pressure. 1750 after shut in, 35 sec 200 psi Increase 158 sec full pressure. N2- 6 btls at 1916 psi average.;Pre spud meeting, P/U BHA, Bit motor & one stand of HWDP. Flood stack. Test lines to rig floor. Find leaking Kill isolation valve, TD IBOP, 1002 Rig floor connection. Replace Oring, Rebuild Kill line demco & warm up TD IBOP. Re test to 3500 psi. Good.;Spud well with H2O & drill to 219' while displacing to spud mud. Back ream out of the hole and inspect Bit. Clean off clay. 400 GPM, 40 RPM.;PJSM, P/U MWD as per dd & scribe to UBHO.;Attempt to adjust UBHO & super tight. Break tool to adjust. Replace Gyro tool to adjust UBHA. Adjust UBHO to MWD as per DD.;Initialize MWD tools. M/U 3 non -mag flex collars to 173'. R/U Scientific gyro with Pollard e -line. Wash down from 173' to 219' with 420 GPM, 750 PSI, 40 RPM, 1 K TQ.;Drill 12-1/4" surface hole f/ 219't/ 555', 336' drilled, 747/hr AROP. 420 GPM, 1040 PSI, 40 RPM, 2K TQ, 15K WOB. MW 8.9 ppg in, 290 vis in / 8.95 ppg out, 300 vis out, 9.6 ECD, max gas 26u. 78K PU / 80K SO / 74K ROT.;Kicked off well at 240' with 3°/100' build rates and increased to 4'/100' at 400'.;Drill 12-1/4" surface hole f/ 555't/ 1394', 839' drilled, 139.8'/hr AROP. 550 GPM, 1490 PSI, 50 RPM, 6K TQ, 5-10K WOB. MW 9.1 ppg in, 200 vis in / 9.2 ppg out, 300+ vis out, 9.9 ECD. 90K PU / 89K SO / 89K ROT.;Closest approach to well M- 15 at 595.79' was 19.60'. No interference observed, no gyro surveys required. R/D Scientific gyro and Pollard a -line at 1014'. Continue with 4°/100' build rates. Last survey at 1355.69' MD / 1243.23' TVD, 45.07° inc, 154.14° azm, 28.14' from plan, 26.84' high, 8.44' right.;Daily losses = 0 bbls, cumulative losses = 0 bbls. Hauled 535 bbls H2O from 6 -Mile Lake for total = 535 bbis Hauled 260 bbls H2O from L -Pad for total = 260 bbls Hauled 568 bbis cuttings/mud/cement for total = 568 bbis 1/9/2020 Drill 12-1/4" surface hole f/ 1394'V 2251', 857' drilled, 142.8'/hr AROP. 540 GPM, 1620 PSI, 60 RPM, 6K TQ, 10K WOB. 9.35 ppg MW in, 140 vis in / 9.4 ppg MW out, 195 vis out, 10.3 ECD, max gas 121 u. 103K PU / 81 K SO / 91 K ROT.;Drill 12-1/4" surface hole f,' 2251' t/ 3042', 791' drilled, 131.8'/hr AROP. 565 GPM, 1950 PSI, 60 RPM, 8K TQ, 12K WOB. 9.25 ppg MW in, 112 vis in / 9.4 ppg MW out, 220 vis out, 10.5 ECD, max gas 48u. 112K PU / 87K SO / 98K ROT.;Drill 12-1/4" surface hole f/ 3042'V 3965', 923' drilled, 153.87hr AROP. 550 GPM, 2040 PSI, 60 RPM, 12K TQ, 15-20K WOB. 9.2 ppg MW in, 120 vis in / 9.3 ppg MW out, 173 vis out, 10.4 ECD, max gas 74u. 134K PU / 78K SO / 103K ROT.;Drill 12-1/4" surface hole f/ 3965't/ 4706', 741' drilled, 148.27hr AROP. 565 GPM, 1940 PSI, 60 RPM, 12K TQ, 5-15K WOB. 9.3 ppg MW in, 104 vis in / 9.4 ppg MW out, 210 vis out, 10.5 ECD, max gas 34u. 160K PU / 85K SO / 114K ROT.;Last survey at 4591.31' MD / 2892.27' TVD, 60.87° inc, 154.03° azm, 23.99' from plan, 20.21' high, 12.91' Iow.;Difficulty syncing #3 generator, drilling with two generators. Overloaded generators & kicked #2 generator off-line. MCC panel tripped off shutting down boilers, air compressors, shakers, air heater, etc. Troubleshooting electrical problem.;Able to hoist drillstring off bottom and circulate 2 BPM to keep top drive from freezing. Blow down rig floor steam lines & put external air heater on the cellar. Utilize Innovation rig electrician & motorman to troubleshoot and blow down Iines.;Hauled 580 bbis H2O from 6 -Mile Lake for total = 1115 bbls Hauled 1550 bbls H2O from L -Pad for total = 1810 bbls Hauled 1798 bbis cuttings/mud/cement for total = 2366 bbis 1/10/2020 Circulate 2 BPM, 300 PSI and reciprocate pipe while troubleshooting rig power. Found faulty sensor on #3 generator which was causing MCC to go offline. Bypass sensor & power up MCC. Both #1 & #2 generators on-line. Locate replacement sensor for #3 generator. Will drill with 2 generators.; Drill 12-1/4" surface hole f/ 4706't/ 5106', 400' drilled, 100'/hr AROP. 520 GPM, 2100 PSI, 80 RPM, 15K TQ, 20K WOB. 9.3 ppg MW in, 120 vis in / 9.45 ppg MW out, 200 vis out, 11.2 ECD, max gas 25u. 165K PU / 89K SO / 118K ROT. 30 bbl hi vis sweep @ 4820' back on time w/ 15% increase.;Drill 12-1/4" surface hole f/ 5106' t/ 5968', 862' drilled, 107.87hr AROP. 470 GPM, 1560 PSI, 80 PRM, 16K TQ, 5-15K WOB. 9.3 ppg MW in, 70 vis in / 9.5 ppg MW out, 159 vis out, 10.1 ECD, max gas 522u. 195K PU / 93K SO / 127K ROT Ugnu MB at 5619' and MF at 5907'. #3 generator online @ 20:OO.;Ugnu heavy oil blinded off shaker screens and filled the rock washer. Shut down & blow down top drive. Change to 80 & 100 mesh screens. Pump mud back from rock washer across the shakers to the mud pits. Stage up pumps to 450 GPM, screens blinded off. Remove 100 mesh screens and install 80s.;Stage up and blinded off at 350 GPM. Shut down & clean screens. Sim -ops: #2 boiler shut down. Turn off steam heater fans and mobilize air heaters to rig cellar & centrifugal room. Electrician changed control box & re -started boiler.;Stage pumps up to 300 GPM, 730 PSI, 30 RPM, 15K TQ. Reciprocate pipe while circulating a bottoms up while increasing ScreenKleen to 1 %. Mud out flow to the end of the shakers at 300 GPM. Shut down and clean shaker screens. Stage up pumps to 450 GPM - good. Make connection a resume drilling.;Drill 12-1/4" surface hole f/ 5968't/ 6438', 470' drilled, 85.57hr AROP. 570 GPM, 2300 PSI, 80 RPM, 18K TQ, 8-20K WOB. 9.4 ppg MW in, 97 vis in / 9.5 ppg MW out, 295 vis out, 10.5 ECD, max gas 157u. 195K PU / 90K SO / 126K ROT.;Began 4° build & turn for final landing at 6057'. Entered Schrader Bluff NA sand at 6072'. Last survey at 6399.40' MD / 3770.19' TVD, 70.92° inc, 146.64° azm, 13.10' from plan, 6.15' lownd 11.56' right.;Daily losses = 0 bbis, Cumulative losses = 0 bbis Hauled 580 bbls H2O from 6 -Mile Lake for total = 1115 bbis Hauled 1275 bbis H2O from L -Pad for total = 3085 bbis Hauled 1264 bbis cuttings/mud/cement for total = 3630 bbis 1/11/2020 Drill 12-1/4" surface hole f/ 6438't/ 7010', 572' drilled, 95.3'/hr AROP. 550 GPM, 2100 PSI, 80 RPM, 18K TQ, 10K WOB. MW in 9.45 ppg, vis in 78 / MW out 9.65 ppg, vis out 215, 10.4 ECD, max gas 257u. 190K PU / 90K SO / 120K ROT. OA base at 6710' MD / 3856' TVD.;Drill 12-1/4" surface hole f/ 7010' t/ 7199', 189' drilled, 94.57hr AROP. 550 GPM, 2290 PSI, 80 RPM, 18K TQ, 5-15K WOB. MW in 9.6 ppg, vis in 72 / MW out 9.7 ppg, vis out 300, 10.7 ECD, max gas 341 u. 190K PU / 80K SO / 125K ROT. OBA sand at 7108' MD / 3895' TVD, TD drilled to fit casing tally.;Last survey at 7159.91' MD / 3897.83' TD, 86.26° inc, 140.21° azm, 45.88' from plan, 44.26' low and 12.06' right.; Pump 30 bbls high vis sweep, 550 GPM, 2100 PSI, 80 RPM, 17K TQ. Back ream to 7012'. Sweep back 400 strokes late w/ 10% increase. Blow down top drive and TIH f/ 7012't/ 7199'.;Monitor well - static. BROOH f/ 7199' U 4251' at 5 min/stand, slowing as necessary for torque or pressure increases. Start 550 GPM, 1980 PSI, 60 RPM, 16K TQ . End 550 GPM, 1700 PSI, 60 RPM, 20K TQ, max gas 441 u. 160K PU / 75K SOW / 110K ROT.;BROOH f/ 4251't/ 1873' at 5 min/stand, slowing as necessary for torque or pressure increases. 550 GPM, 1550 PSI, 60 RPM, 8K TQ. From 4211' to 4135' observed torque & pressure spikes, slowed to 3'/min.;At 2148' observe clay/wall cake over the shakers & ECD climbed from 10.0 to 11.0. Slow pulling speed to 10 min/stand to allow to clean up. Slowed flow rate to 400 GPM due to shakers running over. Back to normal parameters at 1896' with a 10.2 ECD.;Daily losses = 0 bbis, Cumulative losses = 0 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Hauled 1200 bbis H2O from L -Pad for total = 4285 bbis Hauled 1177 bbis cuttings/mud/cement for total = 4807 bbls 1/12/2020 Back Ream out of the hole F/ 1873'T/ 825'. Pull last stand of 5" Dp to 728' with no rot getting two btm up. Cleaned up good. Blowdown TD.;POOH on elevators with HWDP F/ 728'T/ 77'. Stand back HWDP. UD 3 NMFDC.;Down load MWD. UD MWD, Bit & Motor. Bit Grade 1 -1 -WT -A -E -1 -NO -TD, Clean and clear the rig floor.;R/U to run 9 5/8 Casing. R/U 350 slips, Elevators & Volant tool. Install bail extensions.;PJSM, P/U & thread lock shoe joint and spacer joint to 80'. While making up joint #3 with the float collar, the threads only made up 5 turns. Back out joint 2 turns, M/U and stopped at 5 total turns in again. Back out joint, clean up, start by hand and stopped again at 5 total turns.; Back out joint and found box of joint #2 damaged. PJSM and R/U to UD casing. UD joint #3. P/U and was able to back out thread locked connection between joint #1&2. UD both joints.; Mobilize and process new shoe track. Place all casing in proper running order. Remove by-pass baffle from float collar. Removed 350T slips, will utilize hand slips for first t10 joints. 1.5 BPH static Iosses.;PJSM. P/U & M/U 9-5/8" shoe joint, threadlocked joint, float collar joint, baffle adapter joint & joint #5 to 200'. Pump through shoe track to check floats - good.;lnstall two 9- 5/8"x12-1/4" bowspring centralizers w/ 4 stop rings on shoe joint, one centralizer on jt. #2, one centralizer w/ 2 stop rings on jt. #3 & 4.; Run 9-5/8" 40# L-80 TXP BTC -SR casing f/ 200' t/ 783'. Torque to 20960 ft/lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install 9-5/8" x 12-1/4" bowspring centralizer on every joint #6 to 20. 7.1 bbis lost while running first 20 joints.; Run 9-5/8" 40# L-80 TXP BTC -SR casing f/ 783't/ 3144'. Torque to 20960 ft/lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install 9-5/8"x12-1/4" bowspring centralizer on every joint #21 to 25 then every other joint to #53.;Stage pumps up to 4 BPM, 150 PSI, while maintaining 9.4 ppg MWD in adding water at 90 BPM to treat 9.8 ppg MW out and 200 vis. Increase to 5.7 BPM, 150 PSI and finished circulating a bottoms up.;Daily losses = 28 bbls, Cumulative losses = 28 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Hauled 710 bbis H2O from L -Pad for total = 4995 bbls Hauled 766 bbis cuttings/mud/cement for total = 5573 bbis 1/13/2020 Run 9-5/8" 40# L-80 TXP BTC-SR casing f/ 3144't/ 7197'. Torque to 20960 f /lbs with Doyon Volant tool. Fill pipe on the fly & top off every 10 joints. Install 9- 5/8"x12-1/4" bowspring centralizer as per tally. 27 bbis lost while running casing.;Stage up pumps to 3 bpm while working pipe. Pipe pulled the riser up covering up the flow line. Shut down. Drain stack. Fix riser. Stager up pumps to 6 bpm while working pipe down to 7197'. Work pipe 25'. Rot at 20K tq slow ROT when working pipe. 6 BPM, 260 psi. Circ btm up.;Treat mud going in for cmt. 9.4 in and 9.7 out. 9 bbis lost while circulating.; PJSM cmt job. Circ at 6 bpm while conducting cmt job. Work pipe and ROT at 20K working pipe 20'. Shut down and R/U cmt lines to volant. Blow down TD.;Continue to circulate treated mud at 6 BPM, 280 PSI, 2 RPM, 20K TQ while reciprocating 20'. 275K PU 1120K SO. Halliburton batch up spacer.; Pump 5 bbis water & pressure test lines to 800 PSI low / 4100 PSI high. Mix & pump 60 bbis of 10 ppg Tuned Spacer @ 4 BPM, 175 PSI (4# red dye & 5# Pol-E-Flake in 1 st 10 bbls) Drop by- pass plug. Mix & pump 251 bbls 12 ppg Type 1/11 lead cement (600 sks, 2.349 ft^3/sk yield) @ 6 BPM, 405 PSI.;Mix & pump 82 bbis 15.8 ppg Premium G tai cement (400 sks, 1.158 ft^3/sk yield) @ 4.5 BPM, 525 PSI. Drop by-pass plug. Pump 20 bbls water @ 5.2 BPM, 220 PSI. No losses.; Displace with 9.4 ppg spud mud with MP #2 @ 6.1 BPM, 180 PSI. Cement out of the shoe @ 1907 stks, pressure increased to 280 PSI by 3024 stks. Pump 73 bbis 10.0 ppg Tuned Spacer w/ Halliburton @ 4.1 BPM, 335 PSI. Parked casing at 7192' set depth 20 bbis into spacer.;Continue to displace with 9.4 ppg spud mud with MP #2 @ 6.1 BPM, 790 PSI @ 4250 stks. Slow to 3 BPbumped pug 3.7 bbls early at 4362 stks. CIP @ 22:48. Conveyor loaded with sand and burnt drive belt. No losses.; Pressure up to 3300 PSI, ES cementer did not open. Continue to pressure up and cementer opened at 3460 PSI. Pump 20 bbls @ 4 BPM, 640 PSI with sand piling up in broken conveyor. Open 4" valves to cellar, drain stack then pump 25 more bbls @ 4 BPM, 640 PSI. Conveyor belts changed.; Pump 7-8 BPM, 940-1050 PSI through ES cementer at 2658'. At 1000' stks began seeing Pol-E-Flake. At 1575 stks began dumping spacer to rockwasher. Slow to 6 BPM, 520 GPM for conveyor. Observed cement from 2050 to 2662 stks (61.8 bbis cement back)._ jVo losses.; Continue to overboard spacer (from inside casing) to the rockwasher to 3046 stks (38.8 bbls) Take returns back to the mud pits, increase rate to 8 BPM, 710 PSI for a total of 4.6 bottoms up.;Drain diverter stack, disconnect knife valve and flush diverter stack w/ black water. Cycle diverter annular 3 times. Re-connect knife valve. Clean and inspect the Volant tool.;Continue to circulate through ES cementer while preparing for 2nd stage cement job. 6 BPM, 380 PSI. Empty rockwasher & haul off fluilds, haul 70' water for cement job and mix black water pill. Hold PJSM for cement job. Prime cement unit & batch up spacer. Break out & inspect Volant dies. No Iosses.;Daily losses = 36 bbls, Cumulative losses = 64 bbis Hauled 0 bbls H2O from 6-Mile Lake for total = 1115 bbls Hauled 570 bbls H2O from L-Pad for total = 5,565 bbls Hauled 650 bbls Source Water from G&I for total = 650 bbis Hauled 684 bbis cuttings/mud/cement for total = 6,257 bbis 1/14,2020 Perform 2nd stage cement job. Mix & pump 60 bbls of 10 ppg Tuned Spacer at 4 BPM, 218 PSI (4# red dye & 5# Pol-E-Flake in 1 st 10 bbls). Mix & pump 360 bbls of 10.7 ppg ArcticCem lead cement (687 sks, 2.944 ft^3/sk yield) at 5 BPM, 510 PSI.;Mix & pump 56 bbis of 15.8 ppg Premium G tail cement (270 sks, 1.166 ft^3/sk yield) at 3 BPM, 432 PSI. Drop closing plug. Pump 20 bbis fresh water at 4 BPM, 390 PSI.;Displace w/ 9.4 ppg spud mud w/ rig mud pump at 6BPM, 600 PSI ICP, 810 PSI FCP. Bump plug at 1795 stks. On calculated stks. Pressure up to 1850. ES cmt tool closed and pipe jumped. Bleed off pressure. Held. Good. CIP @ 08:30;12 bbls interface, 60 bbl mud push and 266 bbl cement returned to surface. ***AOGCC notified of upcoming BOP test at 05:40 on 14 Jan 2020***; Blow down cement lines. Disconnect accumulator lines to knife valve. Flush diverter stack with black water, functioning annular diverter 3 times.;Clean casing equipment & R/D spiders. Disconnect knife valve & diverter line. N/D diverter from adapter & hoist stack. WH rep install 9 5/8 casing slips w/ 120k on slips. Welder rough cut 9 5/8" casing, Total out joint= 19.77' Sim-ops: N/D diverter Iine.;Set diverter back down on adapter & M/U 4 bolts. N/D flow nipple, riser & diverter stack. L/D both mouse hales. Sim-ops: clean pits ***AOGCC Inspector Adam Earl waived witness of BOP test at 13:41 on 14 Jan 2010***;Dress 9 518" stump. Install FMC slip lock head, casing and tubing spools @ per WH rep. Test seals on slip lock head to 2475 PSI (80% of 9- 5/8" collapse). Torque bottom ring and perform final pressure test of 2475 PSI for 10 min. - good. Sim-ops: clean pits;Set stack on tubing spool. Elevation too high. Remove 13-5/8" spacer spool between BOP and adapter flange. N/U BOP stack, install kill line, turn buckles and accumulator lines. Sim-ops: clean pits;C/O upper pipe rams to 4-1/2" x 7" VBR. Sim-ops: C/O 4-1/2" IF saver sub on the top drive.;lnstall trip nipple, had to pull stack over with turn buckles. Difficulty closing clamp to secure trip nipple to MPD head.;R/U to test BOP equipment. Install test plug in lower casing head with 3-1/2" test joint. Fill stack & Iines.;Daily losses = 0 bbls, Surface hole losses = 64 bbls. Hauled 0 bbls H2O from 6-Mile Lake for total = 1115 bbls Hauled 310 bbls H2O from L-Pad for total = 5,875 bbls Hauled 435 bbis Source Water from G&I for total = 1,085 bbls Hauled 1,952 bbis cuttings/mud/cement for total = 8,210 bbls 1/15/2020 Perform BOP shell test - close annular on 3-1/2" test joint, purge air from lines, pressure to 3000 psi, good test.;Test BOP equipment as per PTD & AOGCC requirements. Annular tested to 250 PSI low / 2500 PSI high 5 min ea. All other tests performed to 250 PSI low / 3000 PSI high 5 min. ea. Chart all tests. Test rig gas alarms. ***AOGCC rep Adam Earl waived witness to BOP test on 1/14/2020 @ 13:45 ***.;#1: Annular on 3.5" test joint #2: 3.5" x 6" lower VBR rams on 3.5 test joint #3: 4.5" x 7" upper VBR rams w/ 5" test jt, choke valves 1, 12, 13, 14, kill line demco, upper IBOP #4: Choke valves 9, 11, HCR kill, 5" TIW #1 #5: Choke valves 5, 8, 10, manual kill, 5" TIW #1.;#6: Choke valves 4, 6, 7, 5" TIW #2 #7: Choke valve 2 & 3.5" TIW #8: HCR choke #9: Lower pipe rams w/ 5" test joint, 5" dart valve #10:Choke valve 3, blind rams, 3.5" dart valve,;#11: Upper pipe rams w/ 7" test joint, manual choke #12: Hyd choke A, #13: Manual choke B. Perform accumulator test, 3000 initial pressure, 1650 psi after closure, 36 sec to attain 200 psi, 180 sec to attain full pressure, 6 N2 bottle avg @ 1983 psi.; Note: 1 F/P, Quick connect fitting leaking on test stump while testing FOSV, CIO fitting, re-test, good.; R/D test equipment and blow down lines. Install 9 1/8" ID long wear bushing. Clear and clean rig floor. Install 3 1/8" x 1502 flange on upper I/A valve, Mobilize BHA components to the rig floor.;PJSM, Install mouse hole, M/U 8%" tri cone bit, 1.5 deg motor, TIH w/ 4 stands HWDP, jar stand, 1 stand HWDP to 588'. TIH w/ drill pipe out of the derrick f/ 588't/ 2587'.;Wash down to f/ 2587' t/ 2650' @ 415 GPM, 960 PSI. Thick aired up mud returns w/ shakers running over. Slow to 210 GPM, 350 PSI while adding water, de-foamer and ScreenKleen until mud was thinned back. Increase flow to 415 GPM & wash down f/ 2650't/ 2653' and tagged cement w/ 10K. 112K PU 1 75K SO.;Drill cement from 2653' to 2657' then ES cementer f/ 2657' t/ 2659'w/ 415 GPM, 1020 PSI, 60 RPM, 8K TQ, 10K WOB. Ream down to 2682' (took weight @ 2665 & 2669' briefly) then ream through 3 times. Stop rotary & pumps and work through with no problems. RIH stand f/ 2682' t/ 2778', no drag observed.;Well control drill - simulate gas underneath ES cementer. Stab FOSV & well secure in 1 min 40 sec, all responded in 3 min 30 sec. Perform AAR with crew members about positions and responsibilities, then tabletop well kill scenario. Blow down top drive.;TIH fl 2778't/6965', filling pipe every 2000'. 215 PU / 70K SO.;Wash down f/ 6965't/ 7056', tag cement w/ 5K. 210 GPM, 610 PSI. Rack back stand to 6965'& blow down top drive.;R/U test equipment. Close upper 4-1/2" x 7" VBR on 5" drill pipe. Pressure test casing to 2600 PSI for 30 min. - good test. 5.7 bbls pumped, 5.7 bbis bled back. R/D test equipment & blow down Iines.;With no drill pipe in the derrick and 70K hookload and minimal mud in the mud pits, attempt to level substructure. PJSM. Loosen turn buckles on BOP, bleed air pressure off riser boot and loosen MPD lines. Jack driller's side of substructure, started shift forward away from well. Set back down.;Attempt to jack up off driller's side, but did not move at maximum jacking pressure. Could possibly make alignment worse if continued. Stop. Tighten turnbuckles, inflate riser boot & tighten MPD Iines.;Drill cement & shoe track f/ 7056' t/ 7154'. 450 GPM, 1150 PSI, 60 RPM, 17K TQ, 15K WOB. Baffle adapter on depth at 7069' and float collar at 7109'.; Daily losses = 0 bbis, Cumulative losses = 64 bbis. Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbls Hauled 200 bbis H2O from L-Pad for total = 6,075 bbls Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 189 bbls cuttings/mud/cement for total = 8,399 bbis 1/16/2020 Drill cement & shoe track f/ 7154't/ 7190' exiting shoe, cleanup rathole and drill 20' new 8 1/2" hole to 7219'. 450 GPM, 1150 PSI, 60 RPM, 17K TQ, 15K WOB. PU/SO/ROT 215K/70K/120K.;Pul1 into 9 5/8" casing just above the shoe 7188', condition for FIT 450 gpm, 1450 psi, 60 rpm, 16k TQ, reciprocate f/ 7188' to 7156' until 9.3 mw in/out, flow check the well, static. BD TD. Rack back std to 7156'.;R/U test equipment, head pin, FOSV and circ hose, close upper pip ram, purge air from lines, Perform FIT to 12 ppg EMW using existing 9.3 ppg mud, apply 540 psi, good test, bleed off pressure, open UPR, R/D test equip. BD lines. .9 bbis pumped, .89 bbls bled back.; Parked at 7156' w/ FOSV installed, monitor well with trip tank while W/O storm packer to arrive, unload DP from shed, packer arrived on location @ 13:00, load same into pipe shed.;PJSM, P/U to 7057', break out stand, M/U BOT 9 5/8" model B retrievable storm packer. RIH 1 std, set storm packer and release from same as per BOT rep w/ top of packer @ 94.23', center of element @ 108.52', pull stand.;R/U test equipment, Close blind ram, R/U and test above packer to 1000 psi for 10 min charted, good, bleed off, open blind ram, blow down lines, R/D test equipment.;PJSM for leveling rig. Empty mud pits to rock washer. Loosen turnbuckles on stack & release air from riser boots. Jack rig up. Add shims to ODS and remove shims from DS to level rig. Set rig down. Stand of drillpipe hanging in the elevators moved 4" back towards the stump.;Tighten turnbuckles, inflate air boots on riser and load mud back to pits. Fill stack, no leaks on air boots. Prime mud pumps.;M/U storm packer retrieval tool on stand of drill pipe w/ 5" FOSV. TIH, close FOSV & engage storm packer at 94' with 18 turns which also opened the unloader valve. Open FOSV, no pressure observed. Close annular, P/U to 245K to release packer - no pressure observed on choke. Open annular.; Rack back stand to 7057'. Monitor well on trip tank - static. UD storm packer as per Baker rep.;Excessive metal to metal hole drag observed. Circulate surface to surface & add 0.5% 776 lube to reduce metal to metal friction. 550 GPM, 2050 PSI, 40 RPM, 22K TQ. Torque reduced to 18K after lube around. PU weight remained the same at 245K Perform flow check - static. Pump 20 bbls 11.4 ppg dry job.;POOH f/ 7057' t/ 586'. Observed casing drag f/ 7057't/ 6584'. UD 15 joints of HWDP f/ 586'& rack back jar stand. Drain motor, UD bit & motor. Bit graded same as in hole grade: 1 -1 -WT -A -E -1 -NO -BHA Clear rig floor. Remove master bushings & install split bushings. Mobilize MPD bearing to rig floor.;M/U 8.5" SK616M-J1 D bit, 7600 Geo -Pilot, MWD tools w/ ADR, DGR, PWD & directional to 83'. Confidence test & initialize MWD tools. P/U 2 float sub & 3 NMFDC to 181'. TIH w/ HWDP/jar stand & 5" drill pipe to 274'.;Shallow pulse test MWD, 500 GPM, 1120 PSI. Break-in Geo -Pilot bearings. Pressure test Geo - Span. Blow down top drive.;TIH out of the derrick with 5" drill pipe from 274' to 557'.;Daily losses: 0 bbls, Cumulative losses: 0 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total = 1115 bbls Hauled 230 bbls H2O from L -Pad for total = 6,305 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbls Hauled 164 bbls cuttings/mud/cement for total = 8,563 bbis 1/17,2020 RIH w/ BHA 3 on stds 5" DP from 577' to 6938', fill pipe every 2000' Load 580 bbls 8.8 ppg flo pro mud in pits 1, 2, 3, and 5.. Correct displacement on TIH.;Single in w/ 6 jts 5" DP N 6938' to 7128'. PU/SO 225K/65K.;BD choke line, pull bushing, PJSM, remove trip nipple, install RCD bearing as per MPD rep.;PJSM, M/ U stand f/ mousehole. Pump 30 bbl hi vis spacer, Displace w/ 530 bbls 8.8 ppg flow pro mud 6 bpm, 830 psi. wash f/ 7128' to bttm @ 7219' when spacer near bit.;With mud out bit, P/U into 9 5/8" casing rack back std, rotate 40 rpm, 18k tq working pipe at start, 12k tq final,Dump spud mud returns to rock washer. Shut down, close MPD and monitor pressure, No increase. Obtain new SPRs. Blow down MPD Iines.;Blow down top drive, PJSM, hang blocks, slip and cut 53' drilling line, re -calibrate block height. Service top drive. Simops: clean pit 4 and under shakers, mix 200 bbis makeup brine in pit 5.;Drill 8-1/2" production lateral f/ 7219' U 7887', 668' drilled, 102.87hr AROP. 550 GPM, 1780 PSI, 120 RPM, 15K TQ, 8-1 OK WOB. 163K PU / 75K SO / 115K ROT. 8.85 ppg MW in, 47 vis in, 10.6 ECD, max gas 360u.;OB A-2 was logged at 7197'. Steer down at 88` and entered OBa-3 at 7426'. At 7730', begin building up to 91.5°. MPD choke full open while drilling, 40 PSI observed with choke shut on connections.; Drill 8-1/2" production lateral f/ 7887't/ 8562', 675' drilled, 112.57hr AROP. 550 GPM, 1880 PSI, 120 RPM, 16K TQ, 12-16K WOB. 165K PU / 65K SO / 110K ROT. 8.85 ppg MW in, 50 vis in, 10.7 ECD, max gas 353u. Pumped high vis sweep at 8268', back 500 strokes early with 100% increase of cuttings.; Drilled 5 concretions for a total thickness of 17' (1.5% of the lateral). Entered OBa-2 @ 8281'. Maintaining 92°. MPD choke full open while drilling, 52 PSI observed with choke shut on conn Last survey at 8484.77' MD / 3903.26' TVD, 91.56° inc, 143.16' azm, 59.32' from plan, 57.8' low, 13.31' right.;Daily losses = 0 bbis, Lateral losses = 0 bbis Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbls Hauled 410 bbis H2O from L -Pad for total = 6,715 bbls Hauled 0 bbls Source Water from G&I for total = 1,085 bbis Hauled 858 bbls cuttings/mud/cement for total = 9,257 bbis 1/18/2020 Drill 8-1/2" lateral f/ 8562't/ 9220', 658' drilled, 109.6'/hr AROP. 500 GPM, 1890 PSI, 120 RPM, 18-20K TO, 10-12K WOB. 9 ppg MW, 53 vis, 11.3 ECD, max gas 455u. 175K PU / 55K SO / 11 OK ROT.;MPD choke full open while drilling, 60 PSI observed with choke shut on connections. Pump 30 bbl high vis sweep at 8744', on time w/ 100% increase. Continue w/ 92 deg inc, enter OBA-1 @ 9064', enter shale @ 9143', target 88.5 deg.;Drill 8-1/2" lateral f/ 9220' U 9916', 696' drilled, 116'/hr AROP. 500 GPM, 1980 PSI, 120 RPM, 13K TQ, 5-15K WOB. 8.9 ppg MW, 46 vis, 11.2 ECD, max gas 480u. 150K PU / 80K SO / 112K ROT. Pump 30 bbl high vis sweep at 9220', back on time w/ 50% increase.; Encountered fault #1 @ 9220'w/ 3-5' DTN throw putting us in OBA-1: 77' out of zone. Drilled into shale above OBa from 9520' to 9682': 162 out of zone. Increase lubes .5% to 1% adding 4 drums 776 to system @ 9300' lower tq f/ 20k to 15k.;MPD choke full open while drilling, 70 PSI observed with choke shut on connections. Pump 30 bbl hi vis sweep @ 9693', back 300 stks early w/ 50% increase.;Drill 8-1/2" lateral f/ 9916't/ 10552', 636' drilled, 106'/hr AROP. 500 GPM, 1910 PSI, 80 RPM, 12K TQ, 5-15K WOB. 8.9 ppg MW, 45 vis, 11.1 ECD, max gas 496u. 145K PU / 83K SO / 11 OK ROT. Pump 30 bbl high vis sweep @ 10266', back 500 stks early w/ 50% increase.;MPD choke full open while drilling, 60 PSI observed with choke shut on connections. Encountered fault #2 with 57' DTN throw at 10454' placing the wellbore in shale below OBb.;Drill 8- 1/2" lateral ft 10552' t/ 11217', 665' drilled, 110.8'/hr AROP. 455 GPM, 1730 PSI, 120 RPM, 14K TQ, 5-14K WOB. 8.95 ppg MW, 44 vis, 11.27 ECD, max gas 283u. 150K PU / 75K SO / 106K ROT. Perform 190 bbl new mud dump & dilute @ 10794'.; Pump 30 bbl high vis sweep @ 10837', back 200 stks early w/ 50% increase. Logged OBa base at 10567': 113' drilled in OBb. OBa pay at 10702': 135' drilled OAb-base. OBA pay at 10966'. Currently drilling in OBa with 91' inc target. MPD element lower seals failed. Stop drilling to change out.;Last survey @ 11054.61' MD / 3840.47' TVD, 93.60° inc, 142.61 ° azm, 28.41' from plan,10.60' low & 26.36' right.;Daily losses = 0 bbls, Cumulative losses = 0 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total = 1115 bbls Hauled 1,090 bbls H2O from L -Pad for total = 7,805 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbls Hauled 1,444 bbls cuttings/mud/cement for total = 10,834 bbls 1/19/2020 RCD Bearing failure- Mobilize B/U RCD element and tools to the rig floor. PJSM for changing out element. Circulate 400 GPM, 1410 PSI & reciprocate pipe. Rack stand back to 11125'.;Pumping 400 gpm, 1400 psi, work double to ensure hole is in good condition, park @ 11075', shut off pump with MPD holding 100 psi trapped pressure, with double above rotary table breakoff and blow down top drive, M/U double and TD, lower bag to 500 psi and close bag.;S/O to 11056' with tool joint just thru MPD bearing. Remove bearing clamp, P/U string pulling bearing to rig floor, break out double, strip off old bearing and install new bearing. M/U double, SIO stabbing bearing into head, install clamp. equalize well pressure to MPD surface lines. Open Bag.; Establish circulation 350 gpm, 1150 psi, no leaks, rotate 40 rpm, good, M/U stand from derrick, wash down, M/U stand in mousehole. Note: 250 hrs on old bearing, 101 hrs rotating time.;Drill 8-1/2" lateral f/ 11217't/ 11599', 382' drilled, 109.1'/hr AROP. 480 GPM, 1890 PSI, 120 RPM, 14K TO, 11 K WOB. MW in/out 8.9+/9.05, vis in/out 44/47, 11.4 ECD, max gas 404u. 152K PU / 70K SO / 105K ROT.;MPD choke full open while drilling, 65 PSI observed with choke shut on connections. Pump 30 bbl hi vis sweep @ 11314', back 200 stks early w/ 50% increase. Drill in the OBa sand, target 89.5 deg inc.;Drill 8-1/2" lateral f/ 11599' t/ 12300', 701' drilled, 116.8Yhr AROP. 500 GPM, 1990 PSI, 110 RPM, 15K TO, 5-15K WOB. MW in/out 8.8/8.9., vis in/out 40/44, 11.4 ECD, max gas 759u. 155K PU / 65K SO / 110K ROT.;MPD choke full open while drilling @ 54 psi line press. 85 PSI observed with choke shut on connections. Pump 30 bbl hi vis sweep @ 11790', back 200 stks late w/ 75% increase, pump 30 bbl hi vis sweep @ 12265'. At 11990' perform dump and dilute w/ 290 bbis new 8.8 ppg flo pro mud. Drill in OBA sand.;Drill 8-1/2" lateral f/ 12300't/ 12930', 630' drilled, 1057hr AROP. 500 GPM, 2080 PSI, 110 RPM, 15K TO, 5-15K WOB. MW in/out 8.9/9.0, vis in/out 43/48, 11.4 ECD, max gas 524u. 158K PU / 60K SO / 112K ROT. Pump 30 bbl high vis sweep @ 12835', back 400 stks early w/ 50% increase.;Drill in OBa sand with 92.5° inclination.; Drill 8-1/2" lateral f/ 12930't/ 13501', 571' drilled, 95.2'/hr AROP. 500 GPM, 2100 PSI, 100 RPM, 14K TO, 7-13K WOB. MW in/out 8.919.0, vis in/out 39/42 , 11.25 ECD, max gas 455u. 155K PU / 60K SO / 11 OK ROT. Pump 30 bbl high vis sweep @ 13312', back 100 stks early w/ 50% increase.;Drill in OBa sand with 91.5° inclination. Drilled 18 concretions for a total thickness of 65' (1.0% of the lateral). At 13242', the closest approach to M-19 PB1 was 81.29'& M-19 was 97.64'. Last survey @ 13432.78' MD / 3806.66' TVD, 92.49° inc, 141.24° azm, 10.74' from plan, 5.0' high, 9.5' right.;Daily losses = 0 bbls, Cumulative losses = 0 bbis Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbls Hauled 1,025 bbls H2O from L-Pad for total = 8,830 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 1,619 bbls cuttings/mud/cement for total = 12,453 bbls 1/20/2020 Drill 8-112" lateral f/ 13501't/ 14073', 572' drilled, 95.37hr AROP. 490 GPM, 1980 PSI, 120 RPM, 17K TO, 15K WOB. MW in/out 8.9/9.0, vis in/out 40141 , 11.34 ECD, max gas 403u. 175K PU / 40K SO / 110K ROT. Pump 30 bbl high vis sweep @ 13695', back on time w/ 50% increase.;MPD monitor for pressure build during connections, 120 psi, wide open drilling @ 50 psi line press. At 13700' perform dump and dilute w/ 290 bbls new 8.8 ppg flo pro mud. Drill in OBa sand at 89 deg inc.;Drill 8-1/2" lateral f/ 14073't/ 14740', 667' drilled, 111.2'/hr AROP. 500 GPM, 2170 PSI, 110 RPM, 15K TO, 5-15K WOB. MW in/out 8.818.9, vis in/out 38/44 , 11.38 ECD, max gas 643u. 175K PU / 40K SO / 11 OK ROT. Pump 30 bbl hi vis sweep @ 14169', back on time w/ 75% increase.;MPD trap 150 psi during connections, drilling @ 100 psi line press. Drill in OBa- Target 90.5 deg, inc. Lost slack off weight at 14740'.;Drill 8-1/2" lateral f/ 14740't/ 15356', 616' drilled, 102.7'/hr AROP. 500 GPM, 2150 PSI, 110 RPM, 15K TO, 5-15K WOB. MW in/out 8.8/8.9, vis inlout 41/43, 11.3 ECD, max gas.453u. 170K PU / 40K SO / 112K ROT. Pump 30 bbl hi vis sweep @ 14740', back 300 stks early w/ 75%. increase.; Pump 30 bbl hi vis sweep @ 15311', back 200 stks late w/ 50% increase. Perform 290 bbl dump & dilute at 14807'. Drill in OBa- Target 91° inc.;Drill 8-112" lateral f/ 15356't/ 15950', 594' drilled, 997hr AROP. 500 GPM, 2150 PSI, 110 RPM, 16K TO, 16-18K WOB. MW in/out 8.8/8.9, vis in/out 40/44 , 11.43 ECD, max gas 409u. 165K PU / 40K SO / 105K ROT. Pump 30 bbl hi vis sweep @ 15787, back 100 stks late w/ no increase.; Drilled 31 concretions for a total thickness of 129' (1.5% of the lateral). Drill in OBa- Target 88.5° inc. Last survey @ 15812.97' MD / 3807.05' TVD, 89.09° inc, 141.85° azm, 28.51' from plan, 27.79' low & 6.37' Ieft.;Daily losses = 0 bbls, Interval losses = 0 bbls Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbls Hauled 960 bbls H2O from L-Pad for total = 9,790 bbls Hauled 0 bbls Source Water from G&I for total = 1,085 bbls Hauled 1,599 bbis cuttin s/mud/cement for total = 14,052 bbl 1/21/2020 Drill 8-112" lateral f/ 15950't/ 16549', 599' drilled, 99.87hr AROP. 490 GPM, 2090 PSI, 110 RPM, 20K TO, 6-81K WOB. MW in/out 8.8+/8.9, vis in/out 40/45 , 11.6 ECD, max gas 433u. 175K PU / 40K SO / 105K ROT. Pump 30 bbl hi vis sweep @ 16265', back 300 stks late w/ no increase.;At 16450' Perform 290 bbl dump and dilute w/ new 8.8 flo pro mud. MPD trap 150 psi during connections, drilling w/ 50- 100 psi line press. Drill in OBa- Target 90° inc.;Drill 8-1/2" lateral f/ 16549' tt 17257',708' drilled, 118'/hr AROP. 500 GPM, 2130 PSI, 110 RPM, 19K TO, 5-14K WOB. MW in/out 8.8/8.9, vis in/out 40/44 '11.4 ECD, max gas 882u. 175K PU / 40K SO / 110K ROT.;Drill in OBa- Confirmed past MPJ-23 with bit @ 16765'(27.44'f/J-23) Did see magnetic interference with survey @ 16765'. MPD trap 150 psi during connections, drilling w/ 50- 100 psi line press. Pump 30 bbl hi vis sweep @ 17025' 250 stks late w/ 40% increase;Drill 8-1/2" lateral f/ 17257't/ 17883', 626' drilled, 1047hr AROP. 500 GPM, 2050 PSI, 110 RPM, 21 K TO, 5-15K WOB. MW in/out 8.8/8.9, vis in/out 42/43, 11.48 ECD, max gas 456u. 195K PU / 40K SO / 110K ROT.;Drill in OBa-Target 90-91' inc. MPD trap 150 psi during connections, drilling w/ 50- 100 psi line press. Pump 30 bbl hi vis sweep @ 17025' 250 stks late w/ 40% increase.;Drill 8-1/2" lateral f/ 17883't/ 18100', 217' drilled, 1087hr AROP. 500 GPM, 2200 PSI, 120 RPM, 20K TO, 10K WOB. MW in/out 8.8/8.9, vis in/out 39/42 , 11..50 ECD, max gas 386u. 185K PU / 40K SO / 105K ROT.;Projection to TD: 18100' MD / 3798.36' TVD, 90.76° inc, 140.51' azm, 50.25 from plan, 49.96' low and 5.40' right. 40 concretions were drilled in the lateral, for a total thickness of 172'(1.6%). 2 faults were crossed in the Iateral.;Obtain final survey & slow pump rates. Pump tandem low vis / high vis sweeps. 510 GPM, 2300 PSI, 110 RPM, 21 K TO. Sweeps back 100 strokes late with no observed increase. Circulate a total of 3x bottoms up, racking back a stand every BU to 17845'.;Daily losses = 0 bbls, Interval losses = 0 bbls Hauled 0 bbls H2O from 6-Mile Lake for total = 1115 bbis Hauled 730 bbis H2O from L-Pad for total = 10,520 bbis Hauled 0 bbls Source Water from G&I for total = 1,085 bbls Hauled 1,609 bbis cuttings/mud/cement for total = 15,661 bbis 1/22/2020 Circulate 500 gpm, 2250 psi, 110 rpm, 21k torque, Circulate final BU for a total of 4 BU racking a stand back after ea BU TO 17725', wash back to T_ D @_ _ 18100'. 75 bbl losses circulating 4 BU.;Continue pumping and working pipe 350 gpm, 1100 psi, 120 rpm, PJSM for Pumping SAPP train and displacing to brine, Ready pits and trucks.; Pump SAPP pill treatment. Pump 30 bbl hi vis spacer, 3- 30 bbl SAPP pills with 40 bbl seawater spacer, chase with 280 bbis seawater. pump 30 bbl hi vis spacer 7 bpm, 1120 psi, 50 rpm, 25k tq.;Displace well w/1750 bbis 8.5 vissed brine w/ 4% lube, 6-7 bpm, 1000 psi, 100 rpm, 21 k tq, work pipe, divert mud, SAPP trains/seawater to rock washer, w/ 8.5 ppg at returns MPD line @ 25 psi line pressure (9.77 ppg ECD ) pump until clean brine returns. 60 bbl losses pumping SAPP and displacing.;PU/SO/ROT in mud 175k/none/l04k . PU/SO/ROT in brine 180k/none/114k, obtain new SPRs , Shut down pumps with MPD chokes open. bleed MPD pressure to 10 PSI, shut choke and pressure built to 50 PSI in 5 min , perform 2 times w/ same results.; BROOH f/ 181 00't/ 17026' pulling 10/15 min/std pumping 480 GPM, 1600 psi, 100 RPM, 19K TQ, 10.59 ECD . UD stands DP using mousehole while BROOH. MPD wide open BR with 40 psi line pressure, trap 90 psi during connections. 20-25 bph loss rate, 17500' slow to 450 gpm, 1450 psi 5 min/std.;BROOH f/ 17026't/ 14724' pulling 5 min/std pumping 450 GPM, 1450 psi, 100 RPM, 20K TO, 10,01 ECD . UD stands DP using mousehole while BROOH. MPD wide open BR with 40 psi line pressure, trap 90 psi during connections. 5-15 bph loss rate, 15500' slow to 400 gpm, 1220 psi.; BROOH f/ 14724't/ 12500' pulling 5-8 min/std, 400 GPM, 1450 psi, 100 RPM, 20K TQ, 9.85 ECD. UD stds DP using mousehole while BROOH. 15 bph avg loss rate, MPD wide open BR with 40 psi, trap 90 psi during conn. 13150' increase to 430 gpm, 1400 psi loss rate 5-8 bph. 128 bbl total loss on BROOH.;Daily losses (Midnight) = 196bbls, Interval losses = 196 bbls Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbls Hauled 445 bbis H2O from L-Pad for total = 10,965 bbls Hauled 0 bbls Source Water from G&I for total = 1,085 bbls Hauled 2,686 bbis cuttings/mud/cement for total = 18,347 bbls 1/23/2020 Continue to BROOH f/ 12500't/ 10935' pulling 5-15 min/std, 400 GPM, 1250 psi, 110 RPM, 16-18K TQ, 10.1 ECD . UD stds DP using mousehole while BROOH. MPD wide open BR with 40 psi, trap 90 psi during conn. Loss rate 10-14 bph.;At 12458', and 11980' slight packing off, 11953' seen increase in cuttings at shakers, slow pulling speed and let cleanup before continuing.; Continue to BROOH f/ 10953't/ 7128' pulling 5-10 min/std, 400 GPM, 1250 psi ICP, 900 psi FCP, 100-110 RPM, 8-13K TQ, 9.82 ECD. UD stds DP using mousehole while BROOH. MPD wide open BR with 40 psi, trap 90 psi @ conn. 143 PU/ 105 SO/ 125ROT. Loss rate 8-14 bph. 256 total bbis loss on BROOH.; Pump 2x high viscosity pill and circulate 9-5/8" casing clean. 3x total bottoms up pumped. 500 GPM, 1430 PSI, 100 RPM, 6K TQ, 9.85 ECD. Reciprocate f/ 7120't/ 7033'. Sweeps back on time w/ minimal increase in cuttings. Shakers cleaned up after second sweep around and maintained just slight sand.;Shut down pumps and monitor flow, slowing f/ 24 gpm to 13 gpm in 5 min. Shut in and monitor pressure build f/ 15 psi to 67 psi in 5 min, bleed off 2 more times with last f/ 15 psi to 47 psi in 10 min and leveling out.;PJSM, wt up brine in active pit f/ 8.7 ppg to 9.0 ppg and circulate around @ 500 gpm, 1280 psi, 35 rpm, 5k tq. Cap well f/ shoe up. Shut down pumps, bleed off to 11 psi, shut in, built to 35 psi in 5 min, bleed off to 11 psi, shut in, build to 17 psi.;Open up and monitor flow at possum belly. Initial slight trickle slowing to static after 10 min.;PJSM, Hold kick while tripping drill. Install FOSV, Slip and cut drilling line. Service Topdrive, drawworks and roughneck. Circulate over top of well on isolated pit to monitor well. No Iosses.;Remove RCD Bearing and install trip nipple, check for leaks, good. Monitor well, slight losses.; Daily losses (Midnight) = 195bbls, Interval losses = 391 bbls Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbis Hauled 475 bbis H2O from L-Pad for total = 11,440 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 518 bbis cuttings/mud/cement for total = 18,865 bbis 1/24/2020 Continue to monitor well, slight losses, TOOH f/ 7120' to 6651', 1 bbl under talc displacement, trip tank foaming up, add de-foam, monitor well for 10 min, continue seeing slight losses, TOOH to 6175'.;Monitor well, slight losses, Pump dry job, drop 2.43" drift on wire on stand # 62, blow down TD and geo span.;TOOH on elevators racking 5" stands DP in derrick f/ 6175' to 274' at the HWDP, flow check well jst before HW, continues w/ slight losses. 8.5 bbl losses on TOOH f/ shoe.;Crew change, PJSM, L/D 2 joints HWDP, recover drift and wire, UD jars, 3 NM drill collars, 2 float subs to 83'. Read MWD tools, UD remaining BHA. Bit grade= 1-1-WT-A-X-I-NO-TD. Note: Visible wear on PWD stab and ILS.;Monitor well with trip tank, 1 bph loss rate. Clear and clean rig floor. Mobilize 6-5/8" casing equipment to rig floor & R/U. Load tallied 6 5/8 liner and safety joint into pipe shed and ready same. Loss rate 1 BPH.; Hold PJSM with rig & casing crew. P/U shoe joint, P/U and RIH w/ 6-5/8", 20#, L-80, Hydril 563, Slotted liner as per tally t/ 5504'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Loss rate running liner 2 bph, 13 bbls total loss while running liner. At 5504', 108K PU / 87K SO.;Continue RIH w/ 6-5/8". 20#. L.80, Hydril 563, Slotted liner as per tally f/ 5504' t/ 9402'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Loss rate running liner 2.5 bph, 27 bbis total loss while running liner. At 7126' 127k PU 1 90K SO. At 9402', 140K PU / 80K SO.;Daily losses (Midnight) = 27 bbls, Interval losses = 418 bbls Hauled 0 bbis H2O from 6-Mile Lake for total = 1115 bbis Hauled 270 bbis H2O from L-Pad for total = 11,710 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 314 bbis cuttings/mud/cement for total = 19,179 bbis 1/25/2020 Continue RIH w/ 6-5/8", 20#, L-80, Hydril 563, Slotted liner as per tally f/ 9402' t/ 11068'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Verify pipe count, 253 jts slotted liner, 22 jts solid liner ( includes solid shoe jt ) 271 centralizers ran.; Loss rate 2.5 bph, 32 bbls losses running liner at this point.;C/O handling equip to 5", M/U Baker 7"x9-5/8" LTP assy and running tool f/ 11068" t/ 11104' as per Baker rep, 8 pins in pusher tool, set at 2648 psi, packer- 9 pini set @ 44100 ft/lbs. M/U stand DP RIH to 11190'.;M/U TD, set TD tq @ 10k,Obtain parameters: 20 RPM, 1 OK with pipe moving only. 150K PU / 80K SO, pump 5 bbis at 4 bpm, 300 psi to ensure clear flow path, BD TD.;TIH with 6 5/8" liner conveyed on 51 stands of drifted 5" DP f/ 11190' to 15958', single in w/ 68 jts drifted 5" HWDP to 18056', TIH no faster than 30 fpm, easy in/out slips, fill on the fly and top off every 5 stands ran.;Note: set down @ 13736', work thru easily, seeing slight bobble every 40' to 14200'. Loss rate 2.5 bph RIH w/ llner.;UD bttm single on std 52, M/U same, pull 400k unable to get P/U wt, SO wt 110k, RIH and tag up on depth @ 18100'.;Break circulation, pump 4 bpm, 520 psi, circulate DP volume. Break out TD, Drop .9062" composite ball as per BOT rep, pump ball down 5 bpm 690 psi 800 stks, slow to 3 bpm, 440 psi, ball hit @ 971 stks, 74 stks early.;Pressure up to 2800 psi, see pusher tool set, pressure to 3800 psi, line up to test pump, pressure to 4000 psi, no solid surface indication of packer or pusher tool neutralize, burst disk sub. Pressure bled to 0 psi. P/U 350k, running tool not free. Set down t/ 80k and P/U 350k, still not free.; Put 1 turn t/ left and work string 125k down, 250k up 2x. Put another turn to left in and slack off, at 140k see indication of release. P/U and free @ 175k. TOL @ 7005'.;R/U t/ Test LPT. Pump 2 bbis down DP while R/U to ensure Kelly hose does not freeze up. Shut annular, test 9 5/8" x packer to 1500 psi for 10 min charted, good test. Bleed off pressure, open annular. BD lines. R/D test equipment.;POOH f/ 7005' t/ 6397'. Rack " 1st drillpipe in erric ay own P to shed. Hole took 3 bbis over calculated displacement.; Pump dry job and TOOH f/ 6397' to surface. UD 5" HWDP to 5131'. Rack back 3 stands 5" HWDP & 51 stands of 5" drill pipe in the derrick. 14 bbis lost on TOOH.;Service rig and TopDrive.;UD liner running tool. Liner running tool in good condition. Remove split bushing. Drain stack and pull wear bushing. Perform dummy run with 7" hanger on landing joint Re-install wear bushing and master bushings Bring orange peel jt to rig floor and M/U to first stand of drillpipe.;Daily losses (Midnight) = 48 bbls, Interval losses = 466 bbis Hauled 0 bbls H2O from 6-Mile Lake for total = 1115 bbis Hauled 50 bbis H2O from L-Pad for total = 11,760 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 42 bbls cuttings/mud/cement for total = 19,221 bbls Hilcorp Energy Company Composite Report Well Name: MP M-34 Field: Milne Point County/State: North Slope Borough, Alaska (LAT/LONG): above TOL @ 7003', pump 30 bbl hi vis sweep around 450 gpm, 600 psi, 30 rpm. Sweep back 100 stks early w/ no increase. Simops: prep pits for :vation (RKB): displacing., Crew change, Parked at 6990' circulate 3 bpm, 290 psi Prep pits for displacing, PJSM, pump 30 bbl spacer, Displace with 487 bbis 9 ppg brine 6 -7 API #: bpm, 300 psi, 30 rpm, 4k tq working pipe just above TOL., flow check well, static, BD TD. No losses.,PJSM, TOOH f/ 7003' to surface LID 216 jts DP, 9 jts Spud Date: HWDP and wash tool. 12 bbis loss over calculated displacement on TOH.,Pull wear bushing, M/U XO on FOSV. R/U handling equipment and power tongs to Job Name: 2010034C MPU M-34 Completion Contractor Doyon 14 AFE #: 496 bbis AFE $: Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Activity Date: bps Summary 1/26/2020 TIH w/ 3 1/2" flush tool and 8.31" no go on 5" stands DP to 6957' M/U last std and top drive, PU 145K, SO 120K. Wash down to 7026' at 2 bpm, 210 psi, no go out on TOL @ 7012' DPM with flush tool @ 7026', observe pressure increase, No losses RIH.,PU 1', pump 7 bpm, 370 PU slowly flushing sealbore to just above TOL @ 7003', pump 30 bbl hi vis sweep around 450 gpm, 600 psi, 30 rpm. Sweep back 100 stks early w/ no increase. Simops: prep pits for displacing., Crew change, Parked at 6990' circulate 3 bpm, 290 psi Prep pits for displacing, PJSM, pump 30 bbl spacer, Displace with 487 bbis 9 ppg brine 6 -7 bpm, 300 psi, 30 rpm, 4k tq working pipe just above TOL., flow check well, static, BD TD. No losses.,PJSM, TOOH f/ 7003' to surface LID 216 jts DP, 9 jts HWDP and wash tool. 12 bbis loss over calculated displacement on TOH.,Pull wear bushing, M/U XO on FOSV. R/U handling equipment and power tongs to run 7" casing. Hold PJSM w/ Baker Rep, Doyon casing & Rig crews.,P/U Baker Bullet seal tie -back assembly to 15'. Run 7" 26# L-80 TXP casing f/ 15' U 3890'. Torque to 14750 ft/lbs with Doyon casing double stack tongs. 5 bbls total loss running 7" tie -back., Daily losses (Midnight) = 30 bbis, Interval losses = 496 bbis Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Hauled 100 bbis H2O from L -Pad for total = 11,860 bbls Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 889 bbis cuttings/mud/cement for total = 20,110 bbis 1/27/2020 Continue to Run 7" 26# L-80 TXP casing f/ 3890' t/ 6991 at jt 170, Torque to 14750 ft/lbs with Doyon casing double stack tongs. 10 bbl losses running tie back. PU 155K, SO 115K.,M/U jt 171', S/O see seals entering TOL @ 7012', no go out @ 7021' setting down 5k. P/U 3' and close bag, pressure up backside to 250 psi to verify seals engaged, bleed off pressure, open bag.,Space out as per Baker rep. LID jts 168, 169, 170 and 171, replace jt 168 with jt 181. M/U 2-8' pups, 2-6 pups and 5' pup= 35.12', M/U jt 169, M/U pup, hanger, landing joint„ drain stack, Land liner on hanger at 7020' (1.24' off no-go) R/U FOSV, circ. sub & 5' pup joint. Close annular & pressure up to 250 PSI. P/U, observe pressure bleed off through circulation ports.,PJSM with Doyon, M-1 and Peak. Reverse circulate 130 bbis corrosion inhibited 9 ppg brine @ 4 BPM, 450 PSI, Pump through injection line to the OA taking returns out of the 7" liner, Line up and reverse circ 75 bbis diesel from vac truck 4 bpm, 550 psi freeze protecting 9 5/8" x 7" annulus to 2500', Land hanger w/ 75k on Hanger.,Bleed down to cuttings box and verify seals engaged. Good. Back side dead. Open annular & drain stack. RID landing joint.. M/U Pack off running tool on jt of 5" DP. RIH & set pack off. RILD as per Wellhead rep. LID running tool. Test Void to 500/5000 psi , 5 min./10 min - good.,Line up pump with diesel Test 9-5/8" x 7" annulus to 1100 psi for 30 charted min. Good. Bleed of pressure, RID test equipment. BD kill, injection and pump lines. SimOps: Install Diverter Tee —& Annular Preventer on ear rig floor. o run 3 1/2" jet pump completion, 3.5" handling equipment, Doyon double stack power tongs, tech wire spool and sheave, cannon clamps. Monitor well on Trip Tank. Static loss rate at 1.0 bph.,PJSM, M/U 3-1/2" pup joint w/ wireline entry guide, 23 joints of 3-1/2" 9.3# L-80 EUE tubing, HES XN nipple assy, HES 3-1/2"x7" retrievable packer, HES X nipple assy and Baker gauges and sliding sleeve to 822'. Torque to 3100 ft/lbs with Doyon casing double stack tongs. Loss Rate @ 1.0 bph.,M/U gauge TEC line and test - good test. Change out pneumatic/hydraulic clamping tool. Continue to run 3-1/2" 9.3# L-80 EUE tubing f/ 822' t/ 3146' as per tally. Torque to 3100 ft/lbs with Doyon casing double stack tongs. Install Cannon clamps first 5 connections after sleeve then every other connection. Loss Rate Continues at 1.0 BPH.,Daily losses (Midnight) = 15 bbls, Interval losses = 511 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Hauled 75 bbls H2O from L -Pad for total = 11,935 bbls Hauled 0 bbls Source Water from G&I for total = 1,085 bbis Hauled 1,279 bbis cuttings/mud/cement for total = 22,389 bbis 1/28/2020 Continue to run upper completion, 3-1/2" 9.3# L-80 EUE tubing f/ 3146't/ 6994' as per tally. Torque to 3100 ft/lbs with Doyon casing double stack tongs. Loss rate cont at 1-2 bph. 18 total bbis loss while running tubing. SimOps: Cut and cap 90' mousehole, move rockwasher.,M/U 3-1/2" x 11" FMC tubing hanger and 5" landing joint. Terminate and feed Tec wire through hanger. Drain BOP Stack. Land 3-1/2" tubing on tubing hanger . Run in lock down screws. Drop ball (1.31") & rod. Lay down landing jt. 106 full cannon clamps ran. 83k PU / 68k SO, 28K on hanger. WLEG @ 7027.68'.,R/U circulating hoses & chart recorder. Fill lines, close blind rams and line up t/ pump down 3-1/2" tubing, taking returns from IA to cuttings box. Pressure up to 3500 PSI on the tubing. Set packer & test tubing for 30 min. Bleed tubing to 2100 PSI. Pressure up to 3500 PSI on the IA & test casing for 30 min. Tubing climbed to 2500 PSI due to compression. Meed tubing off, shear valve in GLM @ 2493'.,Verify communication pumping 2 bpm down IA, returns through tbg — 330 psi, 2 bpm down tbg, returns through IA - 330 psi. Blow down lines and suck out BOP stack,Set BPV, N/D BOPE and set stack on moving stump with 2' spool. Install dart in BPV.,Prep wellhead, terminate TEC wire through adaptor flange. Install and N/U tree, test void t/ 500 psi low, 5000 psi high. Clean cellar box. Rig up to test tree, test to 250/5000 psi., Pull BPV and Dart. R/U to freeze protect. Blow air through lines. Hold PJSM,PT lines, pump 87 bbis diesel freeze protect down 3-1/2" tubing taking returns through IA to cuttings tank. ICP 570 psi @ 2 BPM. FCP 2600 psi @ 2 BPM. ICP 570 psi @ 2 BPM. FCP 2600 psi @ 2 BPM. Shut down Blow down lines. 0 psi reading on tubing gauge. Line up and flush lines with 20 bbls fresh H'O.,Daily losses (Midnight) = 16 bbls, Interval losses = 527 bbis Hauled 0 bbis H2O from 6 -Mile Lake for total = 1115 bbis Hauled 0 bbis H2O from L -Pad for total = 11,935 bbis Hauled 0 bbis Source Water from G&I for total = 1,085 bbis Hauled 217 bbis cuttings/mud/cement for total = 22,606 bbis 1/29/2020 Blow down lines to cuttings tank after flushing with fresh HIO. Clean cellar box and disconnect mud lines on rig floor. Clean and clear rig floor. Mobilize new saver sub and IBOP to rig floor.,While waiting on Slick Line to finish an antecedent job; C/O upper IBOP and Saver Sub. Replace liners and swabs on pump #1. Start processing 9-5/8" casing for next well. Perform scheduled inspections on TopDrive. Install and weld new ladder in pill pit. Perform general housekeeping around rig and prepare for move. Prep M-35 location for Rig,Rig up Slickline tools, sheaves, and lubricator. Test lubricator t/ 250 psi low, 3000 psi high. R/D test equipment., Perform slickline operations. Shift sliding sleeve open. Retrieve 1.31" ball and rod. Retrieve shear valve from Mandrel at 2493'. RIH w/ DV and install in Mandrel t/ 2493'. SimOps: Dress Shakers with new screens. continue processing 9-5/8" casing. R/D and move Mud Lab. Continue pad prep M-35. 1130/2020 RIH w/ 3.5" GR tool to 6316' SLM, Removed RHC plug f/ XN-nipple. POOH C/O tools. RIH w/ X -line 3.5" 10C jet pump to 6238' SLM. Installed jet pump. POOH rigged down slickline. SIMOPS blew down steam system for the rig floor and con processing 9 5 csg to jt #47.,Prepped for skidding the rig floor, removed hand rails and grating. Disconnected com-line and spooled on the roof. Pinned up the beaver slide into rig move position. Cleaned the tree and the cellar area. Rig released @ 12:00 for M-35.,Daily losses ( Midnight) = 0, Interval losses = 527 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total = 1190 bbls Hauled 0 bbls H2O from L -Pad for total = 11,935 bbls Hauled 0 bbls Source Water from G&I for total = 1,085 bbls Hauled 0 bbls cuttings/mud/cement for total = 23,319 bbls Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-34 500292366200 Sperry Drilling Definitive Survey Report 22 January, 2020 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU NI -34 Project: Milne Point TVD Reference: MPU M-34 Actual RKB @ 58.78usft Site: M Pt Moose Pad MD Reference: MPU M-34 Actual RKB @ 58.78usft Well: MPU M-34 North Reference: True Wellbore: MPU M-34 Survey Calculation Method: Minimum Curvature Design: MPU M-34 Database: NORTH US + CANADA Iroject Milne Point, ACT, MILNE POINT lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level neo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-34 Well Position +N/ -S +E/ -W Position Uncertainty Wellbore MPU M-34 Magnetics Model Name 0.00 usft Northing: 6,027,765.77 usfl 0.00 usfl Easting: 533,783.96 usfl 0.50 usft Wellhead Elevation: usfl Sample Date Declination (°) BGGM2019 1/8/2020 Design MPU M-34 Audit Notes: Version: 1.0 Phase: Vertical Section: Depth From (TVD) (usfl) 33.38 ACTUAL +N/ -S (usft) 0.00 16.18 Latitude: 70° 29' 12.786 N Longitude: 149° 43'25.941 W Ground Level: 25.40 usft Dip Angle Field Strength (°) (nT) 80.90 57,402.77169926 Tie On Depth: +E/ -W (usft) 0.00 33.38 Direction (°) 142.40 Survey Program Date 1/22/2020 From To (usft) (usfl) Survey (Wellbore) Tool Name Description Survey Date 200.04 7,159.91 MPU M-34 MWD+IFR2+MS+Sag (1) (MF 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 01/02/2020 7,246.74 18,028.59 MPU M-34 MWD+IFR2+MS+Sag (2) (MF 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 01/13/2020 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1 (°) (usft) (usft) (usft) (usfl) (ft) (ft) (°/100') (ft) Survey Tool Name 33.38 0.00 0.00 33.38 -25.40 0.00 0.00 6,027,765.77 533,783.96 0.00 0.00 UNDEFINED 200.04 0.89 23.94 200.03 141.25 1.18 0.53 6,027,766.96 533,784.48 0.53 -0.62 3_MWD+IFR2+MS+Sag (1) 223.37 0.76 28.30 223.36 164.58 1.48 0.67 6,027,767.26 533,784.63 0.62 -0.77 3_MWD+IFR2+MS+Sag (1) 316.38 1.44 141.67 316.36 257.58 1.11 1.69 6,027,766.89 533,785.64 2.02 0.15 3_MWD+IFR2+MS+Sag (1) 409.06 4.36 159.13 408.91 350.13 -3.10 3.67 6,027,762.69 533,787.64 3.26 4.69 3_MWD+IFR2+MS+Sag (1) 503.69 7.48 159.83 503.03 444.25 -12.24 7.07 6,027,753.56 533,791.09 3.30 14.01 3_MWD+IFR2+MS+Sag (1) 595.79 11.67 162.27 593.82 535.04 -26.75 11.98 6,027,739.08 533,796.06 4.57 28.50 3_MWD+IFR2+MS+Sag (1) 689.34 16.80 169.75 684.48 625.70 -49.08 17.27 6,027,716.78 533,801.45 5.81 49.42 3_MWD+IFR2+MS+Sag (1) 784.94 21.57 170.06 774.74 715.96 -80.00 22.77 6,027,685.88 533,807.09 4.99 77.27 3_MWD+IFR2+MS+Sag (1) 879.24 26.74 167.68 860.76 801.98 -117.83 30.29 6,027,648.09 533,814.78 5.58 111.83 3_MWD+IFR2+MS+Sag (1) 973.42 31.14 166.37 943.16 884.38 -162.22 40.55 6,027,603.76 533,825.25 4.72 153.27 3_MWD+IFR2+MS+Sag (1) 1,070.73 34.53 160.47 1,024.93 966.15 -212.69 55.71 6,027,553.36 533,840.63 4.79 202.50 3_MWD+IFR2+MS+Sag (1) 1,166.07 38.48 157.41 1,101.56 1,042.78 -265.57 76.15 6,027,500.58 533,861.31 4.56 256.87 3_MWD+IFR2+MS+Sag (1) 1222020 12:18:49PM Page 2 COMPASS 5000.15 Build 91E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-34 Project: Milne Point ND Reference: MPU M-34 Actual RKB @ 58.78usft Site: M Pt Moose Pad MD Reference: MPU M-34 Actual RKB @ 58.78usft Well: MPU M-34 North Reference: True Wellbore: MPU M-34 Survey Calculation Method: Minimum Curvature Design: MPU M-34 Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,260.08 41.44 156.29 1,173.61 1,114.83 -321.07 99.90 6,027,445.19 533,885.31 3.24 315.33 3_MWD+IFR2+MS+Sag (1) 1,355.69 45.07 154.14 1,243.23 1,184.45 -380.52 127.39 6,027,385.87 533,913.07 4.10 379.21 3_MWD+IFR2+MS+Sag (1) 1,450.24 47.82 154.54 1,308.38 1,249.60 -442.28 157.06 6,027,324.26 533,943.01 2.92 446.24 3_MWD+IFR2+MS+Sag (1) 1,545.33 48.86 152.31 1,371.59 1,312.81 -505.80 188.85 6,027,260.88 533,975.08 2.07 515.96 3_MWD+IFR2+MS+Sag (1) 1,641.28 52.02 154.53 1,432.70 1,373.92 -571.95 221.91 6,027,194.89 534,008.44 3.75 588.55 3_MWD+IFR2+MS+Sag (1) 1,735.49 54.23 155.16 1,489.22 1,430.44 -640.17 253.93 6,027,126.83 534,040.77 2.41 662.13 3_MWD+IFR2+MS+Sag (1) 1,831.13 57.13 155.17 1,543.14 1,484.36 -711.84 287.11 6,027,055.31 534,074.27 3.03 739.16 3_MWD+IFR2+MS+Sag (1) 1,926.41 59.57 151.48 1,593.15 1,534.37 -784.28 323.54 6,026,983.05 534,111.02 4.17 818.78 3_MWD+IFR2+MS+Sag (1) 2,020.63 56.63 153.15 1,642.93 1,584.15 -855.09 360.71 6,026,912.41 534,148.52 3.46 897.57 3_MWD+IFR2+MS+Sag (1) 2,117.73 57.16 152.39 1,695.97 1,637.19 -927.41 397.93 6,026,840.27 534,186.06 0.85 977.57 3_MWD+IFR2+MS+Sag (1) 2,212.85 58.98 153.84 1,746.27 1,687.49 -999.41 434.42 6,026,768.44 534,222.87 2.31 1,056.89 3_MWD+IFR2+MS+Sag (1) 2,306.16 61.13 157.08 1,792.86 1,734.08 -1,072.96 467.97 6,026,695.06 534,256.75 3.79 1,135.62 3_MWD+IFR2+MS+Sag (1) 2,402.70 57.94 156.11 1,841.80 1,783.02 =1,149.31 501.01 6,026,618.86 534,290.14 3.42 1,216.28 3_MWD+IFR2+MS+Sag (1) 2,495.57 63.12 157.88 1,887.48 1,828.70 -1,223.72 532.57 6,026,544.60 534,322.03 5.82 1,294.48 3_MWD+IFR2+MS+Sag (1) 2,592.06 60.33 158.49 1,933.18 1,874.40 -1,302.60 564.15 6,026,465.87 534,353.96 2.94 1,376.25 3_MWD+IFR2+MS+Sag (1) 2,687.39 61.78 158.03 1,979.32 1,920.54 -1,380.09 595.05 6,026,388.54 534,385.21 1.58 1,456.49 3_MWD+IFR2+MS+Sag (1) 2,782.83 62.86 155.74 2,023.65 1,964.87 -1,457.81 628.23 6,026,310.98 534,418.75 2.41 1,538.32 3_MWD+IFR2+MS+Sag (1) 2,878.06 61.79 156.66 2,067.89 2,009.11 -1,534.97 662.27 6,026,233.98 534,453.13 1.41 1,620.22 3_MWD+IFR2+MS+Sag (1) 2,972.30 62.22 153.58 2,112.13 2,053.35 -1,610.44 697.27 6,026,158.67 534,488.47 2.92 1,701.37 3_MWD+IFR2+MS+Sag (1) 3,068.73 62.09 152.28 2,157.17 2,098.39 -1,686.36 736.07 6,026,082.93 534,527.61 1.20 1,785.20 3_MWD+IFR2+MS+Sag (1) 3,162.90 61.38 152.15 2,201.77 2,142.99 -1,759.74 774.74 6,026,009.74 534,566.61 0.76 1,866.93 3_MWD+IFR2+MS+Sag (1) 3,257.72 60.36 152.27 2,247.92 2,189.14 -1,833.01 813.35 6,025,936.65 534,605.55 1.08 1,948.54 3_MWD+IFR2+MS+Sag (1) 3,354.05 60.80 153.69 2,295.24 2,236.46 -1,907.76 851.47 6,025,862.08 534,644.00 1.36 2,031.02 3_MWD+IFR2+MS+Sag (1) 3,448.89 60.52 153.51 2,341.71 2,282.93 -1,981.81 888.23 6,025,788.21 534,681.10 0.34 2,112.12 3_MWD+IFR2+MS+Sag (1) 3,543.80 62.72 153.29 2,386.82 2,328.04 -2,056.47 925.62 6,025,713.73 534,718.82 2.33 2,194.08 3_MWD+IFR2+MS+Sag (1) 3,639.08 62.87 153.66 2,430.38 2,371.60 -2,132.29 963.46 6,025,638.09 534,757.00 0.38 2,277.25 3_MWD+IFR2+MS+Sag (1) 3,734.37 61.78 154.47 2,474.64 2,415.86 -2,208.18 1,000.37 6,025,562.38 534,794.25 1.37 2,359.89 3_MWD+IFR2+MS+Sag (1) 3,829.32 61.63 154.02 2,519.65 2,460.87 -2,283.48 1,036.70 6,025,487.25 534,830.92 0.45 2,441.71 3_MWD+IFR2+MS+Sag (1) 3,924.53 62.81 154.54 2,564.02 2,505.24 -2,359.37 1,073.25 6,025,411.53 534,867.81 1.33 2,524.14 3_MWD+IFR2+MS+Sag (1) 4,019.74 63.15 153.91 2,607.28 2,548.50 -2,435.75 1,110.14 6,025,335.33 534,905.04 0.69 2,607.16 3_MWD+IFR2+MS+Sag (1) 4,114.56 62.04 154.16 2,650.92 2,592.14 -2,511.43 1,146.99 6,025,259.83 534,942.23 1.19 2,689.61 3_MWD+IFR2+MS+Sag (1) 4,210.61 59.06 153.66 2,698.14 2,639.36 -2,586.54 1,183.76 6,025,184.89 534,979.34 3.14 2,771.56 3_MWD+IFR2+MS+Sag (1) 4,305.81 58.87 153.91 2,747.22 2,688.44 -2,659.72 1,219.80 6,025,111.88 535,015.71 0.30 2,851.52 3_MWD+IFR2+MS+Sag (1) 4,400.44 58.37 155.55 2,796.50 2,737.72 -2,732.77 1,254.29 6,025,038.99 535,050.52 1.57 2,930.44 3_MWD+IFR2+MS+Sag (1) 4,495.90 60.13 152.87 2,845.31 2,786.53 -2,806.62 1,289.99 6,024,965.32 535,086.56 3.04 3,010.74 3_MWD+IFR2+MS+Sag (1) 4,591.31 60.87 154.07 2,892.29 2,833.51 -2,880.91 1,327.08 6,024,891.20 535,123.98 1.34 3,092.23 3_MWD+IFR2+MS+Sag (1) 4,686.05 61.19 153.02 2,938.18 2,879.40 -2,955.12 1,364.00 6,024,817.17 535,161.24 1.03 3,173.55 3_MWD+IFR2+MS+Sag (1) 4,780.41 58.83 155.01 2,985.35 2,926.57 -3,028.56 1,399.82 6,024,743.89 535,197.38 3.10 3,253.59 3_MWD+IFR2+MS+Sag (1) 4,876.24 58.65 155.57 3,035.08 2,976.30 -3,102.98 1,434.06 6,024,669.64 535,231.96 0.53 3,333.45 3_MWD+IFR2+MS+Sag (1) 4,970.88 59.75 156.10 3,083.54 3,024.76 -3,177.15 1,467.34 6,024,595.63 535,265.57 1.26 3,412.51 3_MWD+IFR2+MS+Sag (1) 1/222020 12:18:49PM Page 3 COMPASS 5000.15 Build 91E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-34 Wellbore: MPU M-34 Design: MPU M-34 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-34 MPU M-34 Actual RKB @ 58.78usft MPU M-34 Actual RKB @ 58.78usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,067.60 59.88 156.16 3,132.17 3,073.39 -3,253.60 1,501.17 6,024,519.34 535,299.75 0.14 3,493.73 3_MWD+IFR2+MS+Sag (1) 5,162.92 58.73 154.88 3,180.82 3,122.04 -3,328.20 1,535.13 6,024,444.91 535,334.04 1.67 3,573.55 3_MWD+IFR2+MS+Sag (1) 5,258.09 58.54 155.65 3,230.36 3,171.58 -3,402.00 1,569.13 6,024,371.26 535,368.37 0.72 3,652.77 3_MWD+IFR2+MS+Sag (1) 5,352.54 58.98 155.09 3,279.34 3,220.56 -3,475.41 1,602.79 6,024,298.02 535,402.36 0.69 3,731.46 3_MWD+IFR2+MS+Sag (1) 5,447.68 58.71 155.00 3,328.56 3,269.78 -3,549.23 1,637.14 6,024,224.37 535,437.04 0.30 3,810.91 3_MWD+IFR2+MS+Sag (1) 5,542.90 59.61 156.34 3,377.38 3,318.60 -3,623.72 1,670.81 6,024,150.03 535,471.05 1.53 3,890.48 3_MWD+IFR2+MS+Sag (1) 5,638.17 58.59 156.00 3,426.30 3,367.52 -3,698.50 1,703.84 6,024,075.41 535,504.41 1.11 3,969.87 3_MWD+IFR2+MS+Sag (1) 5,733.07 58.44 157.93 3,475.87 3,417.09 -3,772.97 1,735.51 6,024,001.10 535,536.41 1.74 4,048.20 3_MWD+IFR2+MS+Sag (1) 5,828.85 61.32 158.81 3,523.93 3,465.15 -3,849.98 1,766.03 6,023,924.23 535,567.29 3.11 4,127.83 3_MWD+IFR2+MS+Sag (1) 5,923.77 60.79 156.66 3,569.87 3,511.09 -3,926.84 1,797.50 6,023,847.52 535,599.10 2.06 4,207.93 3_MWD+IFR2+MS+Sag (1) 6,017.28 60.78 154.98 3,615.52 3,556.74 -4,001.29 1,830.93 6,023,773.23 535,632.86 1.57 4,287.31 3_MWD+IFR2+MS+Sag (1) 6,113.11 64.33 153.22 3,659.68 3,600.90 -4,077.77 1,868.08 6,023,696.93 535,670.36 4.05 4,370.58 3_MWD+IFR2+MS+Sag (1) 6,208.20 66.05 152.51 3,699.58 3,640.80 -4,154.58 1,907.45 6,023,620.31 535,710.08 1.93 4,455.45 3_MWD+IFR2+MS+Sag (1) 6,302.43 68.09 151.12 3,736.29 3,677.51 -4,231.06 1,948.45 6,023,544.02 535,751.41 2.56 4,541.06 3_MWD+IFR2+MS+Sag (1) 6,399.40 70.92 146.64 3,770.26 3,711.48 -4,308.77 1,995.40 6,023,466.53 535,798.71 5.22 4,631.28 3_MWD+IFR2+MS+Sag (1) 6,494.44 73.06 146.19 3,799.64 3,740.86 -4,384.06 2,045.40 6,023,391.48 535,849.05 2.30 4,721.43 3_MWD+IFR2+MS+Sag (1) 6,590.08 73.73 145.03 3,826.97 3,768.19 -4,459.69 2,097.16 6,023,316.09 535,901.15 1.36 4,812.94 3_MWD+IFR2+MS+Sag (1) 6,684.85 77.42 143.86 3,850.58 3,791.80 -4,534.34 2,150.53 6,023,241.69 535,954.85 4.07 4,904.65 3_MWD+IFR2+MS+Sag (1) 6,780.64 80.46 141.94 3,868.95 3,810.17 -4,609.31 2,207.23 6,023,166.99 536,011.89 3.73 4,998.64 3_MWD+IFR2+MS+Sag (1) 6,874.90 84.27 139.64 3,881.47 3,822.69 -4,681.67 2,266.28 6,023,094.90 536,071.26 4.71 5,092.00 3_MWD+IFR2+MS+Sag (1) 6,971.14 87.96 138.15 3,887.99 3,829.21 -4,754.00 2,329.40 6,023,022.86 536,134.70 4.13 5,187.82 3_MWD+IFR2+MS+Sag (1) 7,066.12 86.91 138.34 3,892.24 3,833.46 -4,824.79 2,392.59 6,022,952.38 536,198.20 1.12 5,282.46 3_MWD+IFR2+MS+Sag (1) 7,159.91 86.26 140.21 3,897.83 3,839.05 -4,895.74 2,453.67 6,022,881.71 536,259.60 2.11 5,375.93 3_MWD+IFR2+MS+Sag (1) 7,246.74 87.24 140.33 3,902.75 3,843.97 -4,962.41 2,509.08 6,022,815.30 536,315.30 1.14 5,462.56 3_MWD+IFR2+MS+Sag (2) 7,342.42 89.22 143.11 3,905.71 3,846.93 -5,037.47 2,568.31 6,022,740.52 536,374.87 3.57 5,558.18 3_MWD+IFR2+MS+Sag (2) 7,437.41 87.85 143.78 3,908.14 3,849.36 -5,113.74 2,624.87 6,022,664.51 536,431.77 1.61 5,653.12 3_MWD+IFR2+MS+Sag (2) 7,532.61 87.74 144.26 3,911.80 3,853.02 -5,190.73 2,680.76 6,022,587.79 536,488.00 0.52 5,748.21 3_MWD+IFR2+MS+Sag (2) 7,628.95 87.79 145.33 3,915.56 3,856.78 -5,269.38 2,736.25 6,022,509.39 536,543.85 1.11 5,844.39 3_MWD+IFR2+MS+Sag (2) 7,723.76 89.28 146.26 3,917.98 3,859.20 -5,347.77 2,789.53 6,022,431.26 536,597.48 1.85 5,939.00 3_MWD+IFR2+MS+Sag (2) 7,817.99 91.88 147.08 3,917.03 3,858.25 -5,426.48 2,841.30 6,022,352.78 536,649.60 2.89 6,032.95 3_MWD+IFR2+MS+Sag (2) 7,914.11 90.63 146.29 3,914.92 3,856.14 -5,506.79 2,894.08 6,022,272.73 536,702.74 1.54 6,128.78 3_MWD+IFR2+MS+Sag (2) 8,008.31 90.33 145.39 3,914.13 3,855.35 -5,584.73 2,946.97 6,022,195.03 536,755.98 1.01 6,222.81 3_MWD+IFR2+MS+Sag (2) 8,107.29 91.69 144.81 3,912.39 3,853.61 -5,665.90 3,003.59 6,022,114.14 536,812.96 1.49 6,321.66 3_MWD+IFR2+MS+Sag (2) 8,198.53 91.38 143.92 3,909.95 3,851.17 -5,740.02 3,056.73 6,022,040.26 536,866.43 1.03 6,412.81 3_MWD+IFR2+MS+Sag (2) 8,294.39 91.56 143.62 3,907.49 3,848.71 -5,817.32 3,113.37 6,021,963.22 536,923.41 0.36 6,508.61 3_MWD+IFR2+MS+Sag (2) 8,389.25 90.94 143.39 3,905.42 3,846.64 -5,893.56 3,169.77 6,021,887.25 536,980.16 0.70 6,603.43 3_MWD+IFR2+MS+Sag (2) 8,484.77 91.56 143.16 3,903.33 3,844.55 -5,970.10 3,226.88 6,021,810.97 537,037.60 0.69 6,698.92 3_MWD+IFR2+MS+Sag (2) 8,579.74 91.87 143.13 3,900.49 3,841.71 -6,046.06 3,283.81 6,021,735.28 537,094.88 0.33 6,793.84 3_MWD+IFR2+MS+Sag (2) 8,673.23 91.62 142.84 3,897.64 3,838.86 -6,120.68 3,340.07 6,021,660.93 537,151.47 0.41 6,887.28 3_MWD+IFR2+MS+Sag (2) 8,768.72 92.18 143.30 3,894.48 3,835.70 -6,196.97 3,397.41 6,021,584.91 537,209.15 0.76 6,982.71 3_MWD+IFR2+MS+Sag (2) 1/22/2020 12:18:49PM Page 4 COMPASS 5000.15 Build 91E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-34 MPU M-34 MPU M-34 Local Co-ordinate Reference: Well MPU Nl-34 TVD Reference: MPU M-34 Actual RKB @ 58.78usft MD Reference: MPU M-34 Actual RKB @ 58.78usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +Nl-S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,864.66 91.99 143.30 3,890.99 3,832.21 -6,273.84 3,454.71 6,021,508.31 537,266.79 0.20 7,078.57 3_MWD+IFR2+MS+Sag (2) 8,959.40 91.87 143.14 3,887.80 3,829.02 -6,349.68 3,511.40 6,021,432.74 537,323.82 0.21 7,173.25 3_MWD+IFR2+MS+Sag (2) 9,054.97 92.98 142.28 3,883.75 3,824.97 -6,425.64 3,569.25 6,021,357.04 537,382.01 1.47 7,268.73 3_MWD+IFR2+MS+Sag (2) 9,150.10 91.43 141.62 3,880.09 3,821.31 -6,500.49 3,627.84 6,021,282.46 537,440.93 1.77 7,363.78 3_MWD+IFR2+MS+Sag (2) 9,245.57 89.21 142.50 3,879.56 3,820.78 -6,575.78 3,686.53 6,021,207.45 537,499.96 2.50 7,459.24 3_MWD+IFR2+MS+Sag (2) 9,340.33 90.21 145.21 3,880.04 3,821.26 -6,652.29 3,742.42 6,021,131.20 537,556.19 3.05 7,553.96 3_MWD+IFR2+MS+Sag (2) 9,435.61 90.70 145.49 3,879.28 3,820.50 -6,730.67 3,796.59 6,021,053.08 537,610.71 0.59 7,649.11 3_MWD+IFR2+MS+Sag (2) 9,530.63 89.89 142.75 3,878.79 3,820.01 -6,807.65 3,852.27 6,020,976.36 537,666.73 3.01 7,744.08 3_MWD+IFR2+MS+Sag (2) 9,625.68 88.72 141.94 3,879.95 3,821.17 -6,882.89 3,910.33 6,020,901.39 537,725.13 1.50 7,839.12 3_MWD+IFR2+MS+Sag (2) 9,720.28 87.55 141.72 3,883.03 3,824.25 -6,957.23 3,968.76 6,020,827.33 537,783.89 1.26 7,933.66 3_MWD+IFR2+MS+Sag (2) 9,815.61 88.04 141.69 3,886.69 3,827.91 -7,031.99 4,027.80 6,020,752.84 537,843.26 0.51 8,028.91 3_MWD+IFR2+MS+Sag (2) 9,910.74 89.34 141.74 3,888.87 3,830.09 -7,106.64 4,086.72 6,020,678.47 537,902.51 1.37 8,124.01 3_MWD+IFR2+MS+Sag (2) 10,006.27 88.60 141.75 ' 3,890.59 3,831.81 -7,181.64 4,145.86 6,020,603.74 537,961.99 0.77 8,219.52 3_MWD+IFR2+MS+Sag (2) 10,101.84 88.23 142.36 3,893.23 3,834.45 -7,256.98 4,204.60 6,020,528.68 538,021.07 0.75 8,315.05 3_MWD+IFR2+MS+Sag (2) 10,196.82 88.17 142.02 3,896.21 3,837.43 -7,331.98 4,262.80 6,020,453.95 538,079.60 0.36 8,409.98 3_MWD+IFR2+MS+Sag (2) 10,292.14 89.90 142.96 3,897.82 3,839.04 -7,407.58 4,320.83 6,020,378.62 538,137.97 2.07 8,505.28 3_MWD+IFR2+MS+Sag (2) 10,387.44 90.26 144.40 3,897.68 3,838.90 -7,484.36 4,377.27 6,020,302.11 538,194.75 1.56 8,600.56 3_MWD+IFR2+MS+Sag (2) 10,482.30 93.61 144.66 3,894.48 3,835.70 -7,561.56 4,432.28 6,020,225.16 538,250.10 3.54 8,695.28 3_MWD+IFR2+MS+Sag (2) 10,578.35 95.40 146.77 3,886.94 3,828.16 -7,640.67 4,486.22 6,020,146.31 538,304.39 2.88 8,790.87 3_MWD+IFR2+MS+Sag (2) 10,673.88 97.58 147.69 3,876.14 3,817.36 -7,720.47 4,537.59 6,020,066.75 538,356.12 2.47 8,885.44 3_MWD+IFR2+MS+Sag (2) 10,768.59 97.01 147.22 3,864.11 3,805.33 -7,799.67 4,588.13 6,019,987.79 538,407.01 0.78 8,979.02 3_MWD+IFR2+MS+Sag (2) 10,863.58 94.52 144.76 3,854.57 3,795.79 -7,877.99 4,640.98 6,019,909.72 538,460.22 3.68 9,073.33 3_MWD+IFR2+MS+Sag (2) 10,958.79 94.34 143.17 3,847.22 3,788.44 -7,954.75 4,696.83 6,019,833.22 538,516.41 1.68 9,168.21 3_MWD+IFR2+MS+Sag (2) 11,054.61 93.60 142.61 3,840.58 3,781.80 -8,030.98 4,754.50 6,019,757.26 538,574.42 0.97 9,263.80 3_MWD+IFR2+MS+Sag (2) 11,145.18 90.94 142.26 3,837.00 3,778.22 -8,102.71 4,809.67 6,019,685.79 538,629.91 2.96 9,354.29 3_MWD+IFR2+MS+Sag (2) 11,243.17 91.01 142.71 3,835.33 3,776.55 -8,180.43 4,869.33 6,019,608.35 538,689.92 0.46 9,452.27 3_MWD+IFR2+MS+Sag (2) 11,339.52 91.19 141.39 3,833.48 3,774.70 -8,256.39 4,928.57 6,019,532.67 538,749.50 1.38 9,548.59 3_MWD+IFR2+MS+Sag (2) 11,434.02 90.20 140.72 3,832.33 3,773.55 -8,329.88 4,987.97 6,019,459.46 538,809.22 1.26 9,643.06 3_MWD+IFR2+MS+Sag (2) 11,529.39 89.21 141.74 3,832.82 3,774.04 -8,404.23 5,047.69 6,019,385.38 538,869.27 1.49 9,738.41 3_MWD+IFR2+MS+Sag (2) 11,624.28 88.84 141.65 3,834.44 3,775.66 -8,478.68 5,106.49 6,019,311.21 538,928.41 0.40 9,833.27 3_MWD+IFR2+MS+Sag (2) 11,720.01 89.71 141.26 3,835.65 3,776.87 -8,553.55 5,166.14 6,019,236.62 538,988.39 1.00 9,928.98 3_MWD+IFR2+MS+Sag (2) 11,814.67 90.27 140.48 3,835.67 3,776.89 -8,626.98 5,225.88 6,019,163.47 539,048.45 1.01 10,023.61 3_MWD+IFR2+MS+Sag (2) 11,909.81 89.96 141.04 3,835.47 3,776.69 -8,700.66 5,286.06 6,019,090.07 539,108.96 0.67 10,118.71 3_MWD+IFR2+MS+Sag (2) 12,005.09 91.20 142.67 3,834.51 3,775.73 -8,775.59 5,344.90 6,019,015.42 539,168.14 2.15 10,213.97 3_MWD+IFR2+MS+Sag (2) 12,100.15 90.57 143.23 3,833.04 3,774.26 -8,851.44 5,402.17 6,018,939.83 539,225.75 0.89 10,309.02 3_MWD+IFR2+MS+Sag (2) 12,195.20 90.82 144.13 3,831.89 3,773.11 -8,928.02 5,458.47 6,018,863.51 539,282.38 0.98 10,404.04 3_MWD+IFR2+MS+Sag (2) 12,290.21 91.19 144.52 3,830.22 3,771.44 -9,005.19 5,513.87 6,018,786.61 539,338.13 0.57 10,498.98 3_MWD+IFR2+MS+Sag (2) 12,385.29 91.25 145.38 3,828.20 3,769.42 -9,083.01 5,568.46 6,018,709.04 539,393.07 0.91 10,593.94 3_MWD+IFR2+MS+Sag (2) 12,479.43 89.89 143.37 3,827.26 3,768.48 -9,159.52 5,623.28 6,018,632.79 539,448.23 2.58 10,688.01 3_MWD+IFR2+MS+Sag (2) 12,576.03 90.45 141.81 3,826.98 3,768.20 -9,236.25 5,681.97 6,018,556.34 539,507.26 1.72 10,784.61 3_MWD+IFR2+MS+Sag (2) 1/22/2020 12:18:49PM Page 5 COMPASS 5000.15 Build 91E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-34 Wellbore: MPU M-34 Design: MPU M-34 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU W34 MPU M-34 Actual RKB @ 58.78usft MPU M-34 Actual RKB @ 58.78usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 12,670.93 90.82 141.59 3,825.92 3,767.14 -9,310.72 5,740.78 6,018,482.14 539,566.41 0.45 10,879.50 3_MWD+IFR2+MS+Sag (2) 12,765.66 90.76 141.83 3,824.62 3,765.84 -9,385.06 5,799.47 6,018,408.07 539,625.43 0.26 10,974.21 3_MWD+IFR2+MS+Sag (2) 12,860.85 90.94 141.87 3,823.21 3,764.43 -9,459.91 5,858.27 6,018,333.50 539,684.56 0.19 11,069.38 3 MWD+IFR2+MS+Sag (2) 12,953.53 91.01 142.89 3,821.63 3,762.85 -9,533.31 5,914.83 6,018,260.36 539,741.45 1.10 11,162.05 3_MWD+IFR2+MS+Sag (2) 13,051.12 92.43 142.79 3,818.70 3,759.92 -9,611.05 5,973.75 6,018,182.90 539,800.72 1.46 11,259.59 3_MWD+IFR2+MS+Sag (2) 13,146.81 92.49 143.90 3,814.59 3,755.81 -9,687.74 6,030.83 6,018,106.48 539,858.13 1.16 11,355.18 3_MWD+IFR2+MS+Sag (2) 13,242.06 90.88 142.44 3,811.79 3,753.01 -9,763.94 6,087.90 6,018,030.54 539,915.54 2.28 11,450.37 3_MWD+IFR2+MS+Sag (2) 13,336.42 91.31 142.08 3,809.99 3,751.21 -9,838.55 6,145.64 6,017,956.21 539,973.62 0.59 11,544.71 3_MWD+IFR2+MS+Sag (2) 13,432.78 92.49 141.24 3,806.79 3,748.01 -9,914.09 6,205.38 6,017,880.95 540,033.70 1.50 11,641.01 3_MWD+IFR2+MS+Sag (2) 13,526.76 91.00 139.98 3,803.93 3,745.15 -9,986.68 6,264.99 6,017,808.63 540,093.63 2.08 11,734.90 3_MWD+IFR2+MS+Sag (2) 13,622.05 89.89 139.76 3,803.19 3,744.41 -10,059.53 6,326.40 6,017,736.07 540,155.37 1.19 11,830.09 3_MWD+IFR2+MS+Sag (2) 13,716.78 88.91 140.51 3,804.18 3,745.40 -10,132.24 6,387.12 6,017,663.65 540,216.41 1.30 11,924.74 3_MWD+IFR2+MS+Sag (2) 13,812.36 88.60 140.75 3;806.26 3,747.48 -10,206.11 6,447.73 6,017,590.06 540,277.35 0.41 12,020.25 3_MWD+IFR2+MS+Sag (2) 13,908.41 88.60 141.29 3,808.61 3,749.83 -10,280.76 6,508.14 6,017,515.70 540,338.08 0.56 12,116.24 3_MWD+IFR2+MS+Sag (2) 14,002.76 89.77 140.42 3,809.95 3,751.17 -10,353.92 6,567.69 6,017,442.81 540,397.96 1.55 12,210.55 3_MWD+IFR2+MS+Sag (2) 14,097.18 89.03 140.86 3,810.94 3,752.16 -10,426.92 6,627.57 6,017,370.09 540,458.16 0.91 12,304.92 3_MWD+IFR2+MS+Sag (2) 14,193.23 88.84 141.11 3,812.72 3,753.94 -10,501.53 6,688.02 6,017,295.76 540,518.95 0.33 12,400.92 3_MWD+IFR2+MS+Sag (2) 14,288.06 89.71 142.23 3,813.92 3,755.14 -10,575.92 6,746.83 6,017,221.65 540,578.09 1.50 12,495.73 3_MWD+IFR2+MS+Sag (2) 14,384.30 90.64 142.81 3,813.63 3,754.85 -10,652.29 6,805.39 6,017,145.56 540,636.99 1.14 12,591.97 3_MWD+IFR2+MS+Sag (2) 14,480.21 91.13 142.96 3,812.15 3,753.37 -10,728.76 6,863.25 6,017,069.35 540,695.20 0.53 12,687.87 3_MWD+IFR2+MS+Sag (2) 14,575.51 89.89 141.28 3,811.30 3,752.52 -10,803.97 6,921.76 6,016,994.42 540,754.04 2.19 12,783.16 3_MWD+IFR2+MS+Sag (2) 14,671.23 90.58 140.17 3,810.91 3,752.13 -10,878.07 6,982.36 6,016,920.60 540,814.97 1.37 12,878.83 3_MWD+IFR2+MS+Sag (2) 14,766.05 89.65 140.51 3,810.72 3,751.94 -10,951.06 7,042.87 6,016,847.89 540,875.81 1.04 12,973.59 3_MWD+IFR2+MS+Sag (2) 14,861.41 89.09 139.61 3,811.76 3,752.98 -11,024.17 7,104.09 6,016,775.07 540,937.35 1.11 13,068.86 3_MWD+IFR2+MS+Sag (2) 14,956.61 89.77 140.95 3,812.71 3,753.93 -11,097.39 7,164.92 6,016,702.13 540,998.50 1.58 13,163.99 3_MWD+IFR2+MS+Sag (2) 15,051.21 90.02 141.02 3,812.88 3,754.10 -11,170.89 7,224.47 6,016,628.91 541,058.38 0.27 13,258.56 3_MWD+IFR2+MS+Sag (2) 15,146.72 90.33 140.79 3,812.59 3,753.81 -11,245.02 7,284.70 6,016,555.06 541,118.94 0.40 13,354.04 3_MWD+IFR2+MS+Sag (2) 15,241.95 90.88 141.20 3,811.59 3,752.81 -11,319.02 7,344.63 6,016,481.35 541,179.21 0.72 13,449.23 3_MWD+IFR2+MS+Sag (2) 15,336.92 91.32 141.18 3,809.76 3,750.98 -11,393.01 7,404.14 6,016,407.64 541,239.05 0.46 13,544.16 3_MWD+IFR2+MS+Sag (2) 15,430.85 91.19 141.23 3,807.71 3,748.93 -11,466.20 7,462.98 6,016,334.72 541,298.21 0.15 13,638.05 3_MWD+IFR2+MS+Sag (2) 15,526.53 90.51 141.17 3,806.29 3,747.51 -11,540.76 7,522.93 6,016,260.44 541,358.49 0.71 13,733.70 3_MWD+IFR2+MS+Sag (2) 15,621.68 89.89 141.54 3,805.96 3,747.18 -11,615.07 7,582.35 6,016,186.41 541,418.24 0.76 13,828.83 3_MWD+IFR2+MS+Sag (2) 15,717.08 89.77 141.94 3,806.24 3,747.46 -11,689.98 7,641.42 6,016,111.77 541,477.65 0.44 13,924.22 3_MWD+IFR2+MS+Sag (2) 15,812.97 89.09 141.85 3,807.19 3,748.41 -11,765.43 7,700.59 6,016,036.60 541,537.15 0.72 14,020.11 3_MWD+IFR2+MS+Sag (2) 15,907.46 88.41 142.01 3,809.25 3,750.47 -11,839.80 7,758.84 6,015,962.50 541,595.73 0.74 14,114.57 3_MWD+IFR2+MS+Sag (2) 16,002.60 89.65 142.67 3,810.86 3,752.08 -11,915.10 7,816.96 6,015,887.47 541,654.19 1.48 14,209.69 3_MWD+IFR2+MS+Sag (2) 16,097.99 90.21 143.88 3,810.98 3,752.20 -11,991.56 7,874.00 6,015,811.28 541,711.57 1.40 14,305.07 3_MWD+IFR2+MS+Sag (2) 16,193.63 90.45 141.79 3,810.43 3,751.65 -12,067.77 7,931.77 6,015,735.35 541,769.68 2.20 14,400.70 3_MWD+IFR2+MS+Sag (2) 16,289.09 90.14 140.60 3,809.94 3,751.16 -12,142.16 7,991.59 6,015,661.24 541,829.83 1.29 14,496.14 3_MWD+IFR2+MS+Sag (2) 16,383.83 90.14 140.64 3,809.71 3,750.93 -12,215.39 8,051.70 6,015,588.29 541,890.27 0.04 14,590.83 3_MWD+IFR2+MS+Sag (2) 1/22/2020 12:18:49PM Page 6 COMPASS 5000 15 Build 91E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-34 Project: Milne Point TVD Reference: MPU M-34 Actual RKB @ 58.78usft Site: M Pt Moose Pad MD Reference: MPU M-34 Actual RKB @ 58.78usft Well: MPU M-34 North Reference: True Wellbore: MPU M-34 Survey Calculation Method: Minimum Curvature Design: MPU M-34 Database: NORTH US + CANADA Survey Digitally signed by Chelsea namin Hand Checked By: Chelsea Wright "' l@0.0,22,3,,:53-0goo Approved By: Benjamin Hand DDate:igitally signed by Bej2020.0,.2213:07:31-0900 Date: 41-22-2020 11221202012:18:49PM Page 7 COMPASS 5000.15 Build 91E Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (a) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 16,479.55 89.46 140.22 3,810.04 3,751.26 -12,289.17 8,112.68 6,015,514.79 541,951.57 0.83 14,686.49 3_MWD+IFR2+MS+Sag (2) 16,574.80 89.46 139.96 3,810.94 3,752.16 -12,362.23 8,173.79 6,015,442.02 542,013.01 0.27 14,781.66 3_MWD+IFR2+MS+Sag (2) 16,670.60 89.59 140.65 3,811.73 3,752.95 -12,435.94 8,234.97 6,015,368.59 542,074.52 0.73 14,877.39 3_MWD+IFR2+MS+Sag (2) 16,765.00 89.71 142.13 3,812.31 3,753.53 -12,509.70 8,293.87 6,015,295.11 542,133.75 1.57 14,971.77 3_MWD+IFR2+MS+Sag (2) 16,860.18 89.34 143.62 3,813.10 3,754.32 -12,585.58 8,351.32 6,015,219.49 542,191.53 1.61 15,066.94 3_MWD+IFR2+MS+Sag (2) 16,955.81 89.96 144.93 3,813.68 3,754.90 -12,663.22 8,407.15 6,015,142.12 542,247.71 1.52 15,162.52 3_MWD+IFR2+MS+Sag (2) 17,050.61 90.45 143.32 3,813.34 3,754.56 -12,740.03 8,462.70 6,015,065.57 542,303.61 1.78 15,257.27 3_MWD+IFR2+MS+Sag (2) 17,146.39 90.02 141.75 3,812.95 3,754.17 -12,816.05 8,520.96 6,014,989.82 542,362.21 1.70 15,353.05 3_MWD+IFR2+MS+Sag (2) 17,241.28 90.82 143.05 3,812.26 3,753.48 -12,891.23 8,578.86 6,014,914.92 542,420.44 1.61 15,447.93 3_MWD+IFR2+MS+Sag (2) 17,336.51 90.51 142.43 3,811.15 3,752.37 -12,967.01 8,636.51 6,014,839.40 542,478.42 0.73 15,543.15 3_MWD+IFR2+MS+Sag (2) 17,431.76 90.95 141.71 3,809.94 3,751.16 -13,042.14 8,695.05 6,014,764.55 542,537.30 0.89 15,638.39 3_MWD+IFR2+MS+Sag (2) 17,526.76 91.01 140.41 3,808.31 3,749.53 -13,116.01 8,754.75 6,014,690.95 542,597.33 1.37 15,733.35 3_MWD+IFR2+MS+Sag (2) 17,620.90 91.01 140.41 3,806:65 3,747.87 -13,188.55 8,814.74 6,014,618.70 542,657.64 0.00 15,827.42 3_MWD+IFR2+MS+Sag (2) 17,717.45 91.19 140.28 3,804.80 3,746.02 -13,262.87 8,876.34 6,014,544.66 542,719.57 0.23 15,923.89 3_MWD+IFR2+MS+Sag (2) 17,812.33 91.07 139.26 3,802.93 3,744.15 -13,335.29 8,937.61 6,014,472.53 542,781.16 1.08 16,018.65 3_MWD+IFR2+MS+Sag (2) 17,907.91 90.82 138.82 3,801.35 3,742.57 -13,407.46 9,000.25 6,014,400.65 542,844.13 0.53 16,114.05 3_MWD+IFR2+MS+Sag (2) 18,002.37 91.13 139.46 3,799.74 3,740.96 -13,478.89 9,062.04 6,014,329.51 542,906.24 0.75 16,208.35 3_MWD+IFR2+MS+Sag (2) 18,028.59 90.76 140.51 3,799.31 3,740.53 -13,498.97 9,078.90 6,014,309.51 542,923.18 4.25 16,234.54 3_MWD+IFR2+MS+Sag (2) 18,100.00 90.76 140.51 3,798.36 3,739.58 -13,554.07 9,124.31 6,014,254.62 542,968.84 0.00 16,305.90 PROJECTED to TD Digitally signed by Chelsea namin Hand Checked By: Chelsea Wright "' l@0.0,22,3,,:53-0goo Approved By: Benjamin Hand DDate:igitally signed by Bej2020.0,.2213:07:31-0900 Date: 41-22-2020 11221202012:18:49PM Page 7 COMPASS 5000.15 Build 91E Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. MP rl1-34 County North Slope Borough State CASING RECORD Surface TD 7.199.00 Shoe Dentin 7.192.00 Alaska Supv. PBTD Date Run 13 -Jan -20 S. Sunderland / C. Demoski Csg Wt. On Hook: 160,000 Type Float Collar: Innovex Casing (Or Liner) Detail Csg Wt. On Slips: 120,000 Type of Shoe: Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 TXP BTC -SR Innovex 1.60 7,192.00 7,190.40 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 79.86 7,190.40 7,110.54 1 Float Collar 103/4 50.0 TXP BTC -SR Innovex 1.30 7,110.54 7,109.24 1 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 38.14 7,109.24 7,071.10 1 Baffle Adapter 103/4 50.0 12 Volume pumped (BBLs) TXP BTC -SR HES 1.48 7,071.10 7,069.62 112 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 4,396.92 7,069.62 2,672.70 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 12.94 2,672.70 2,659.76 1 ES Cementer 103/4 Displacement: TXP BTC -SR HES 2.82 2,659.76 2,656.94 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 13.51 2,656.94 2,643.43 66 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,591.61 2,643.43 51.82 1 Cut Joint of Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 19.88 51.82 31.82 Csg Wt. On Hook: 160,000 Type Float Collar: Innovex No. Hrs to Run: 18.5 Csg Wt. On Slips: 120,000 Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes _ No 6.45 Ft. Min. 9.4 PPG Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner top Packer?: _Yes _ No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 9-5/8'x12-1/4" bowspring centralizer placement: _ CEMENTING REPORT Shoe @ 7192 FC @ 7,109.24 Top of Liner Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Type 1/II Lead Sacks: 600 Yield: 2.35 Density (ppg) 12 Volume pumped (BBLs) 251 Mixing / Pumping Rate (bpm): 6 Tail Slurry w Type: Premium G Tail Sacks: 400 Yield: 1 16 Density (ppg) 15.8 Volume pumped (BBLs) 82 Mixing / Pumping Rate (bpm): 4.5 ur Post Flush (Spacer) CnF- g� Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual / calculated): 533.56/537.33 FCP (psi): 660 Pump used for disp: #1 Rig Mud Pump Bump Plug? X Yes No Bump press 1160 Casing Rotated? X Yes _ No Reciprocated? X Yes -No % Returns during job Cement returns to surface? X Yes -No Spacer returns? X Yes -No Vol to Surf: 61.8 Cement In Place At: 22:48 Date: 1/13/2020 Estimated TOC: 2,657 Method Used To Determine TOC: Cement circulated to surface Stage Collar @ 2656.94 Type ES Cementer Closure OK Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: ArcticCem Sacks: 687 Yield: 2.94 Density (ppg) 10.7 Volume pumped (BBLs) 360 Mixing / Pumping Rate (bpm): 5 Tail Slurry w Type: Premium G Sacks: 270 Yield: 1.17 y Density (ppg) 15.8 Volume pumped (BBLs) 56 Mixing / Pumping Rate (bpm): 3 Z Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: Lu or Displacement: Type: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual / calculated): 201.3/202.2 FCP (psi): 600 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1850 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 96 Cement returns to surface? X Yes -No Spacer returns? _Yes X No Vol to Surf: 266 Cement In Place At: 8:30 Date: 1/14/2020 Estimated TOC: 35 Method Used To Determine TOC: Cement to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 434.99 Total Volume cmt Pumped: _ Cmt returned to surface: 327.8 Calculated cement left in wellbore: 421.2 OH volume Calculated: 394.96 OH volume actual: 381.17 Actual % Washout: www.weliez.net WellEz Information Management LLC ver 04818br 749 THE STATE GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-34 Hilcorp Alaska, LLC Permit to Drill Number: 219-193 Surface Location: 4914' FSL, 381' FEL, SEC. 14, T13N, R9W, UM Bottomhole Location: 2205' FSL, 2033' FEL, SEC. 30, TUN, RlOW,UM Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development 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, Jer Pri e Chai DATED this �2 day of January, 2020. STATE OF ALASKA ALf._..A OIL AND GAS CONSERVATION COMM I- JN PERMIT TO DRILL 20 AAC 25.005 ;qq� r7 Pan. is DEC ;19 2019 1 a. Type of Work: 1b.. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 e i 'if. ell>i proposed for: Drill ❑ � Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑Q Service - Winj ❑ Single Zone ❑ comb (s 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: Hilcorp Alaska, LLC Bond No. 02203524-4•> ?� y �fq MPU M-34 ' 3. Address: 6. Proposed Depth: •F 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,711' TVD: 3,753' Milne Point Field Schrader Bluff Oil Pool - 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4914' FSL, 381' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADI -025515, ADL025517 Q - 4 Q Top of Productive Horizon: 8. DNR Approval Number. 13. Approximate Spud Date: 177' FSL, 1934' FWL, Sec 13, T13N, R9E, UM, AK LONS 16-004 ' L _/J 1/5/2020 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 2205' FSL, 2033' FEL, Sec 30, T13N, R10E, UM, AK 7659 r ,456' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.4' 15. Distance to Nearest Well Open Surface: x- 533783 • y- 6027765 Zone -4 GL / BF Elevation above MSL (ft): 24.7' to Same Pool: 60' to MPU M-18 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: 1694 Surface: 1308 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" 215# X-42 Weld 113' Surface Surface 113' 113' ±270 ft3 Stg 1 L - 1403 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 6,946' Surface Surface 6,946' 3,848' Stg 2 L - 1937 ft3 / T - 314 ft3 Tieback 7" 26# L-80 TXP SR 6,796' Surface Surface 6,796' 3,835' Tieback Assy. 8-1/2" 6-5/8" 20# L-80 Hyd 563 1 10,915' 1 6,796' 1 3,835' 17,711' • 3,753' Cementless Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 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 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hllCor .COm Authorized Title: Drilling M nager Contact Phone: 777-8395 �7i//'9 � Authorized Signature: Date: Commission Use Only Permit to Drill C �(_- JAPI tuber: d�-`� Permit Approval See cover letter for other Number: (�� 50 [�� k (��-" Date: !.-� requirements. 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: EJ Other: Ps`' f— Samples req'd: Yes ❑ Noa Mud log req'd: YesNo H/ H2S measures: Yes ❑ No [ Directional svy req'd: Yes NoEl. _ 44 n-Jlc'_-` If e-5 Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No LY I Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY --7/-) 1 Approved by: s ' COMMISSIONER THE COMMISSION Date: I /V,(U :2) &I Subm t Form endForm 10-4 1 Rev 5/20 7 This permit is valid for&Rhi h t proval per 20 AAC 25.005(8) Attachments i Duplicate Hilcorp Alaska, LLC Milne Point Unit (MPU) M-34 Drilling Program Version 1 12/19/2019 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 NIU 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 N/D Diverter, N/U BOPE, & Test................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Liner........................................................................................................32 17.0 Run 7" Tieback..............................................................................................................................36 18.0 Run Upper Completion.................................................................................................................39 19.0 Doyon 14 Diverter Schematic.......................................................................................................41 20.0 Doyon 14 BOP Schematic.............................................................................................................42 21.0 Wellhead Schematic......................................................................................................................43 22.0 Days Vs Depth................................................................................................................................44 23.0 Formation Tops & Information...................................................................................................45 24.0 Anticipated Drilling Hazards.......................................................................................................46 25.0 Doyon 14 Layout............................................................................................................................49 26.0 FIT Procedure................................................................................................................................50 27.0 Doyon 14 Choke Manifold Schematic..........................................................................................51 28.0 Casing Design.................................................................................................................................52 29.0 8-1/2" Hole Section MASP............................................................................................................53 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................54 31.0 Surface Plat (As Staked) (NAD 27)..............................................................................................55 32.0 Schrader Bluff OA Sand Offset MSV vs TVD Chart..................................................................56 ff Hilcorp E -W C-PZY 1.0 Well Summary Milne Point Unit M-34 SB Producer Drilling Procedure Well MPU M-34 Pad Milne Point "M" Pad Planned Completion Type Jet Pump on 4-1/2 tubing Target Reservoir(s) Schrader Bluff OB Sand ' Planned Well TD, MD / TVD 17,711' MD / 3,753' TVD PBTD, MD / TVD 17,701' MD / 3,753' TVD Surface Location (Governmental) 4914' FSL, 381' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533783.8, Y= 6027765.6 ' Top of Productive Horizon (Governmental) 177' FSL, 1934' FWL, Sec 13, TON, R9E, UM, AK TPH Location (NAD 27) X= 536124 Y= 6023039.5 BHL (Governmental) 2205' FSL, 2033' FEL, Sec 30, TON, R10E, UM, AK BI -IL (NAD 27) X= 542730, Y= 6014543 AFE Number 2010034 AFE Drilling Days 18 AFE Completion Das 4 AFE Drilling Amount $4,105,526 AFE Completion Amount $1,914,560 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1308 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1694 psig' Work String 5" 19.5# S-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 24.7 ft = 58.4 ft - GL Elevation above MSL: 24.7 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information Hilcorp Alaska, LLC F-ilcorp WC— Changes to Approver! Permit to Drill Date: 1211912019 Subject: Changes to Approved Permit to Drill for MPU M-34 File #: MPU M-34 Drilling and Completion Program Any modifications to MPU M-34 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC. Sec Page Date Procedure Change Approved By Approved By Milne Point Unit M-34 SB Producer HilcoT�7�+1 E..W Compmy Drilling Procedure 2.0 Management of Change Information Hilcorp Alaska, LLC F-ilcorp WC— Changes to Approver! Permit to Drill Date: 1211912019 Subject: Changes to Approved Permit to Drill for MPU M-34 File #: MPU M-34 Drilling and Completion Program Any modifications to MPU M-34 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC. Sec Page Date Procedure Change Approved By Approved By I a Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 3.0 Tubular Program: Milne Point Unit M-34 SB Producer Drilling Procedure Hole Secti .t► OD (in) ID rj --. ,(in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst _-W9(psi)(k-lbs) Collapse Tension Cond 20" 19.25" - - - X-52 Weld k -lbs Surface & 5" 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 Tieback 7" 6.276" 6.151" 7.656 26 L-80 TXP 7,240 5410 604 8-1/2" 6-5/8 Slotted 6.049 5.924 7.390 20 L-80 Hydri1563 6,090 3,470 459 4.0 Drill Pipe Information: OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tens o (in) (in) in) (#/ft) (Min) :' Max) k -lbs Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 DS50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 30,730 34,136 560k1b All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements Milne Point Unit M-34 SB Producer Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mm, ers e,hilcom jengel@hilcorp.com and cdinger@hilcoM.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Rud' Casing tally to mmyersghilcorp,com jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdingerghilcorp.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 iengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@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 calones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 6.0 Planned Wellbore Schematic C)) 51 OT& KB East: 5"/GL Eev.:,2U . TD=17,711 KV/3,7.SYTVD PM=17,711' NW 4753' TVD Page 6 Milne Point Unit Schematic MPU M1-34 Proposed Schematic LastCo€np°eteti: Future PTD: TED ------------------------ -- -- ----------------------- THEE &WELLHEAD ?ree Cameron 31/9' SM Wcllhcad fMC11"SMTC-iAw/31"x4112-TC41 Top andkttornTubing f)a r with 3" OW ")1' BPV rafik. 2ez 319' NPTtantnol lines. -------------------------------------- OPEN HOLE / CEM ENT QET'4 v� 20' x 34' 270 ft3 Cement to surface in a 42" hale Type 9-518" 1st stage L-1403 ft3 / T-458 R3 in a 12-1/4" hale 9-S/8"2nd stage L-1937ft3/T-314it3ina12-1/4"hale 65/8" C9=0m Slatted Liner in 8-1/2" We Milne Point Unit 20'x34" Conductor(Insulatedl 21S/X-42JWeld N/A M-34 SB Producer 80' Hilco-rp E.ergy Company Drilling Procedure 6.0 Planned Wellbore Schematic C)) 51 OT& KB East: 5"/GL Eev.:,2U . TD=17,711 KV/3,7.SYTVD PM=17,711' NW 4753' TVD Page 6 Milne Point Unit Schematic MPU M1-34 Proposed Schematic LastCo€np°eteti: Future PTD: TED ------------------------ -- -- ----------------------- THEE &WELLHEAD ?ree Cameron 31/9' SM Wcllhcad fMC11"SMTC-iAw/31"x4112-TC41 Top andkttornTubing f)a r with 3" OW ")1' BPV rafik. 2ez 319' NPTtantnol lines. -------------------------------------- OPEN HOLE / CEM ENT QET'4 v� 20' x 34' 270 ft3 Cement to surface in a 42" hale Type 9-518" 1st stage L-1403 ft3 / T-458 R3 in a 12-1/4" hale 9-S/8"2nd stage L-1937ft3/T-314it3ina12-1/4"hale 65/8" C9=0m Slatted Liner in 8-1/2" We r-------------------------------------------------------------------------------------------------1 CASING DETAIL Sae Type AVGrade/ Conn ID TCP MM BPF 20'x34" Conductor(Insulatedl 21S/X-42JWeld N/A Surface 80' WA 9-5/8' Surface 40/L-80/TV 8.83S" Surface 6,946" 4.0758 7" Tieback 26/ L-110 TV 6176' Surface 6,796' 4.0383 6-518" Uner(Sl:ntedl 24/L94jLfiWW563 6.049x' 6,796' 17,711'^ 4.0355 3.889" 7 TUBING DETAIL 7'x4-1/2-BLutwxt 164RetriemhleParker 3.690" 8 4-1/2" Tubing 126 / L 90 j HYDS22 1 3958 Surface I 36,830 I 4.0087 ------------------------- SLDTTED UNERDETAIL Top (MD) 18, tm[MD} I Top (TVD) I DS I F r I Date I '"Mr TMD WELL INCU14AIlON DETAIL XOP @ 300' Max I IDI Angle =T80 IEWFLRY nFTAIL Na. Tap MD Item LD Upper Cam 'an 1 29' Tubing Ilan er 4-4a' FMC TCIA 2 TMD StaYl: 4-1/2" x 1' GLM w/shear-aut valve 3 TMD 4-W' SCNI Multi Drop 3.674" 4 TBD 44/2" I IES Slitfing Sleeve w/ VAeatherfard 11D let Pune 3.813" S TMD 4-1f2" SGM Si le 3.813" 6 TBD 4-112' x 3.813" X -Ni le 3.889" 7 TBD 7'x4-1/2-BLutwxt 164RetriemhleParker 3.690" 8 TED 4-In'x3.813"XNNipple w/1725'No-Coll 3.725" 9 TBD Localtar Sub, TC -II Sm x Sax ;625" DD No -GD) 6-200 10 TED Bulkt Seals (TRSAI. Mule Stwe 6.G90 11 =6.796 SL2XP LTP with DG stip 11.27' tie back sleeve)TDL 6.190 12 1-16,800 Latztar Sub, TC -II Mmk x Sax 18.2S" DD No -Go) 6.200 13 TBD WLEG:w/ Cut MuksFwe- 8attam @4,82' 3.958" 14 i6AVY Crassawer,7'tbul LS63Swxb-5/8'LlgUS&3Pin 6.900 15 17,711' Shoe -- - — ---- - ----------------- GENERAL WELL INFO API:TPD Drilled. Cased &Cam eted bV DDVcm 14 -Future P,,i�d ey: CIL) IV1E12'49 Milne Point Unit M-34 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary 10 MPU M-34 is a grassroots jet pump producer planned to be drilled in the Schrader BluffoBsan M-34 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OB sand. An 8.5" lateral section will then be drilled. A 6-5/8" slotted liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore Drilling operations are expected to commence approximately January 5, 2020, pending rig schedule. Surface casing will be run to 6,945' MD / 3,848' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point "B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8" 5M BOP & Test 5. Drill 8-1/2" lateral to well TD. 6. Run 6-5/8" production liner 7. Run 7" tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: ✓ 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 ff Hilcorp E..W C—P.oy Milne Point Unit M-34 SB Producer 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. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-34. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • 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. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. ✓ Page 8 Milne Point Unit M-34 SB Producer Drilling Procedure Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril WL Double Gate N/A o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets For Reference 0 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line N/A • 3-1/8" x 5M Kill line • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg(2alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartz(2alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp(2alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse(2alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(2alaska.gov Test/Inspection notification standardization format: hM2:Hdoa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 ME 9.1 Milne Point Unit M-34 SB Producer Drilling Procedure R/U and Preparatory Work M-24 will utilize a newly set 20" conductor on M -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 RAJ. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 10.0 NX 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N!U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 11 Milne Point Unit M-34 SB Producer Hilco+{/�� Energy Company Drilling Procedure 10.0 NX 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N!U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 11 Milne Point Unit M-34 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: • May change on location M-43 ■ I M-11 ■ f ■ M-13 M-12 ■ 1 I � M-14 M-20 ■ M-15 M-57 ■ M-34 M-21 ■ M-72 ■ ' M-23 ■ ■ M-17 M -1a 1 75' Radius Clear of Ignition Sources Diverter Line ' Drawing Not To Scale MPU —Pad Diverter Line May Be Oriented Different On Location Page 12 Hilcorp Energy Campy 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-34 SB Producer Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 1 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 V Milne Point Unit M-34 SB Producer Drilling Procedure Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. 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. Surface Hole AC: • There are no wells with a clearance factor of <1.0 11.4 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone • PVT System: 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. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Page 14 r Density Viscosity Plastic Viscosity Yield Point I AN FL Milne Point Unit Tem Surface 1 8.8-9.8-1 M-34 SB Producer 1 20-40 Hilco E &y eom Drilling Procedure • 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 I AN FL pH Tem Surface 1 8.8-9.8-1 75-175 1 20-40 1 25-45 1 <10 8.5-9.0 1 <_ 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 1 gal dm 0.5 1.1.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute, adjust as dictated by hole conditions • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 15 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread lockin4 120' shoe track assemblv consisting of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring Milne Point Unit Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring M-34 SB Producer HES Baffle Adaptor Hilcorp E -W C..pmy Drilling Procedure 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread lockin4 120' shoe track assemblv consisting of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No_ Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth d7 Baffle Adapter (if used) ID Depth Bypass or Shutoff Baffle ID Depth Float Collar Depth Float Shoe Depth :nE4IIIII, "Reference Casing Sales Manuel Section 5 Page 17 "A Overall Length B Milt. ID After Drillout C Max. Tool OD D Opening Seat ID E Closing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD 17 OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit M-34 SB Producer Drilling Procedure Hikorp ES4I Running Order E541 Cementer Shut Off plug Baffle Adapter Bypass Plug By Pass Baffle Float Collar Float shoe 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Lowest Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geolo ist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs Milne Point Unit 23,060 ft -lbs M-34 SB Producer HilmiT E..W Company Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Lowest Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geolo ist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 HilcoN Enugy Cvm TXP@ BTC Page 19 Milne Point Unit M-34 SB Producer Drilling Procedure -n,d 11/0812018 I-) Grade L80 Outside Diameter 9.625 in. Min. Wall 87.55: COUPLING PIPE BODY Thickness 1st Band: Red 1st Bard: Brown Wall Thickness 0.395.in. Connection OD REGULAR 3rd Band: - 3rd Band: - Option 4th E'and: - Grade LBO Type V Drift API Standard Type Casing Page 19 Milne Point Unit M-34 SB Producer Drilling Procedure -n,d 11/0812018 I-) Grade L80 10.625 in. Type 1 10.825?- COUPLING PIPE BODY Ecdy: Red 1st Band: Red 1st Bard: Brown 2rd Bard: 2nd Band: - Brown 3rd Band: - 3rd Band: - 4th E'and: - GEOMETRY Nominal OD 9.6.25 in. Nlominal height 40 ibsft Drift 8.679 in. Nominal iC 8.83.5 in. '1'W. Thickness 0.395 in. Plsin End lNeight 38.97 IbV11 OD 7.--a-ce API PERFORMANCE Body Y*b Sta-g-h 516 x 1000 3s trdlema Y-Wd 5750 psi SLAYS 80009 psi Collapse 3090 psi Cos =_ctc OD 10.625 in. C:apli-2 -e-g-t 10.825?- Connection ID 8.823 in. Makeup Loss 4.831 in. Trr=-_:=a per a 5 Connection OD Oplion REGULAR PERFORMANCE Tension £fftciency 100.0% W=Ylatd Stength 916.000 x1000 Internal Pressure Capacity I11 5750.000 psi lbs Compression Efficiency 100% Compression Sveng`h 916.000 x1000 Max. Allowable Bending 38 `11100 it lbs Exemal Fpressu-e Capacity 3090.004 ps MAKE-UPTORQUES h inknum 188601t-' s Optinurr, 20960 fl4bs Maximum 23M 14bs OPERATION LIMIT TORQUES Operating Tcrque 35600 Ft -::s Yield Torque 43404 tt-Ibs Notes - This connection is fuIP/ interchangeable with: TXP@ BTC - 9.625 in_ - 35143.5147 f 53-5158.4 ibs/H [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5031 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which viii€I be reduced. Please contact a local Tenans technical sales representative_ i Milne Point Unit M-34 SB Producer Hilcol+7�+� E..W Compmy Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 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 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 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 M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. V/ Page 20 `/ 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-34 SB Producer Drilling Procedure 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. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • 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: Page 21 Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" � (5,945'- 2500') x .0558 bpf x 1.3 = 249.9 1403 JCasing Total Lead 249.9 1403 12-1/4" OH x 9-5/8" (6,945' - 5, 945') x .0558 b pf x 1.3 = 72.5 407 — Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Milne Point Unit M-34 SB Producer 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. • 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: 6,375' x.0758 bpf = 478.13 bbls 80 bbls of tuned spacer to be left 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 Page 22 Lead Slurry Tail Slurry Density 12.0 Ib/gal 15.8 Ib/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk 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. • 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: 6,375' x.0758 bpf = 478.13 bbls 80 bbls of tuned spacer to be left 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 Page 22 Hilcorp Energy Cwapany Milne Point Unit M-34 SB Producer Drilling Procedure 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 prematjrrel opened. K M 7 13.16 Increase pressure to 3300 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 23 Second Stage Surface Cement Job: Milne Point Unit M-34 SB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre job safety meeting. • 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 2nd 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): Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 4.41 ft3/sk , 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 — 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 F- Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.41 ft3/sk , 1.17 ft3/sk , Mixed Water 22.02 gal/sk 5.08 gal/sk Page 24 Milne Point Unit M-34 SB Producer Drilling Procedure 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: 2500' x .0758 bpf = 190 bbls mud 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 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 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: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. 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 jengelghilcorp. com and cdin er ghilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 14.0 N/D Diverter, NX BOPE, & Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment a' 14.4 Run 5" BOP test plug 14.5 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints n • Confirm test pressures with PTD �DC • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure ►� is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 R/D BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg F1oPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6" liners in mud pumps. Page 26 Milne Point Unit M-34 SB Producer HilcoR En=W C�®psoy Drilling Procedure 14.0 N/D Diverter, NX BOPE, & Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment a' 14.4 Run 5" BOP test plug 14.5 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints n • Confirm test pressures with PTD �DC • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure ►� is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 R/D BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg F1oPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6" liners in mud pumps. Page 26 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) Milne Point Unit M-34 SB Producer Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. l 15.4 RAJ and test casing to 2500 nsi / 30 min. Ensure to record volume / pressure (every 1/4 bbl) and G plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on i� the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 pm 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 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.54 S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid Page 27 Hilcorp E --W cz Milne Point Unit M-34 SB Producer Drilling Procedure running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Properties: Interval nsit PV I YP LSYP Total Solids MBT HPHT Hardness Production 1 8.9-9.5 V15-25 - ALAP 1 15-30 1 4-6 <10% <8 <1 1.0 <100 System Formunion. Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gaU100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE -GARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Page 28 J Hilcorp E..WC—pi" 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-34 SB Producer Drilling Procedure 15.14 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to stay in OB sand. • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% • Anticipate similar concentrations in OB • MPD will be utilized to monitor pressure build up on connections. • 8.5" Lateral A/C: • M-17, 18, 19 are lateral wells in the SB OA sand, — 50-70' TVD above M-34.. Geologically there is no risk. • J-23 & J -23L1 have been abandoned. J-23 was drilled in the OB, but the only risk is damage to the bit. • J -23A is a lateral injector in the NB sand, — 220' TVD above M-34. • M-35 is a planned well, a supporting injector in the OB sand to M-34 Page 29 15.15 Reference: Open hole sidetracking practice: Milne Point Unit M-34 SB Producer Drilling Procedure • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Lineup 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. Proposed brine blend (same as used on M-16, aiming for an 8 on the 6rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo -Vis Plus: 1.25ppb • Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (less if losses are seen, 350 gpm min). • Rotate at maximum rpm that can be sustained. Page 30 i Milne Point Unit M-34 SB Producer Hilcorp Energy Comp=y Drilling Procedure Pulling speed 5 — 10 min/std (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 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 / monitor for pressure build up with MPD. Increase fluid weight if necessary • Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH and LD BHA. 15.24 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 16.0 Run 6-5/8" Production Liner C I'"O Milne Point Unit M-34 SB Producer Drilling Procedure 16.1 Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and with 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW. • Proceed with well kill operations. 16.2 R/U 6-5/8" liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3 Run 6-5/8" slotted production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run round nose float shoe on bottom. • 6-5/8" slotted liner will auto —fill • 6-5/8" Liner will be centralized with 1/joint free floating • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 6-5/8" 20 # Hydril 563 Torque OD Minimum Optimum Maximum Yield Tor ue 6-5/8 5,900 ft -lbs 7,100 ft -lbs 10,300 ft -lbs 36,000 ft -lbs Page 32 Hilcorp Energy c mpmy Wedge 5630 Outside Diameter 8.625 in. Wall Thickness 0288 .n. Grade LBO Type 1` PIPE BODY DATA GEOh1ETRY Min. Wall 8T_5% Thickne5s connection OD REGULAR Option Drift APA Standard Type Casing Milne Point Unit M-34 SB Producer Drilling Procedure 111=2018 4*) Grade L80 am Type i Drift COUPLING PIPE B40M 63ey. Red 1 st Banat Red 1zt Bard: Brown 2rd Sand: 2rd Balli- • Brown 3rd Dald: • kd tiancl 41h Elland, Nominal OL* 6.625 m Nnini%al lheight 20.001ts,11 Drift 5.924 in Nnrni•,al'Pm7 6.049 in 'hall Thkknass 0.288: in. Stair. End 19.51 ibsi0 Go Ta7arar" API PERFORMANCE .We I B4dY Yid Strcrrith 459xi:0GC tG: kftmal Yiold 6090 rel 5. 60000 psi C aIapi; a 3470 k i 10Nr Et'TION CtAT,1, GEOMETRY Cannacl+mOD 7.39,1 r CoupLrr3L"Ih 9.2sai Mii.a•up Loss 4.050 in.. Threads W. in 3.29 Cannacu:A CC, 0;4on REGULAR PERFORMANCE Tarskr. 95-71, Jc4nI Yaaid SlrcrQih 4342363..ICC0 scrh;.mai Pressure Capac to East, a 0 pu tbs So In p f4,-- co ESFiie.arcy 100.0 N cempronl-xn slrangqtr 459.0110 e1CCq Mac Atu«ya"bs: Bending 52.6 "IM it lbs ExtaRAal Pras:ura Capacir,. 3470.000 psi coupirr; Fact, Lead 318000rte MAKE-UP TORQUES ,.... 5900':-" ,r p0mum 7100 a:C.s Mt jrnum 1030041-0ss OPERATIDPt LIMIT TORQUES Optf2wrq Toque 31000ti-les Yiabd 7arquL 36004" BUCK -ON Mvrimum 10000t.15s M—imum 11 OMt. Notes This connection is fuf#y interchangeathe with -- Wedge 563 - 6.625 in. - 24 J 28 J 32 lbsfit Connections with Dopelessl1 TechncAogy are fulty comp,athle v4ith1he same connection in its Standard version Page 33 Hilcorp E -V C -P -Y Milne Point Unit M-34 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. 16.7. Before picking up Baker SLZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 6-5/8" liner. 16.9. Note PUW, SOW, 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 w/ liner on 5" HWDP no faster than 30 ft/min -this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. • Ensure 5" HWDP has been drifted • There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, &20 rpm 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at -1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. Page 34 p Milne Point Unit M-34 SB Producer Hilcorp E -W C -p iy Drilling Procedure 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP liner hanger to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.21. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 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. P/U pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.25. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. 16.26. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.27. POOH & L/D remaining 5" HWDP 16.28. Once running tool is L/D, swap to the completion AFE Page 35 17.0 Run 7" Tieback 17.1 RIH w/ 3.5" washpipe on 5" dp to clean out liner top. POOH LDDP. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 psi) solid body casing rams. 17.3 RAJ 7" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.4 P/U tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.5 M/U first joint of 7" to seal assy. 17.6 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7" 26# TXP MUT OD Minimum Optimum Maximum Yield Torque 7" Milne Point Unit 14,750 ft -lbs 16,230 ft -lbs 23,400 ft -lbs M-34 SB Producer Hilco E..W �� Drilling Procedure 17.0 Run 7" Tieback 17.1 RIH w/ 3.5" washpipe on 5" dp to clean out liner top. POOH LDDP. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 psi) solid body casing rams. 17.3 RAJ 7" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.4 P/U tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.5 M/U first joint of 7" to seal assy. 17.6 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7" 26# TXP MUT OD Minimum Optimum Maximum Yield Torque 7" 13,280 ft -lbs 14,750 ft -lbs 16,230 ft -lbs 23,400 ft -lbs Page 36 H Hilc Enmw c22 TXPO BTC Outside Diameter 7.000 in. Wall Thickness 0.362 in_ GradeLBO Type V Min. Wall 87.5% Thickness Connection OD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-34 SB Producer Drilling Procedure --- 12,,'06,'2018 (') Grade LBO sporm, Type I Ccrineclion 00 Crfcn REGULAR COUPLING PIPE BODY Body: Red I st Band: Red tat Ba,�d: Brown 2nd Sandi 2nd Ean& - Brown 3rd Ban& - 3rd Band:- and.-4th 604-1)1 4thBand: - PIPE BODI DATA GEOMETRY Norrinal OD 7-000 in. Nominal V�Vght 26 lba,!t Dim 6-151 in. Nominal ID 6.276 in. Wall Thickness 0.362 in. Plan E�d %%ghl 25.69 t-sP. OD Tderarre AN PERFORMANCE Bo&y Yield Strength 604 x-1001) lbs Internal Yield 7240 vsi SMYS WOOD psi Collapse 5410 psi rCONNECTION DATA GEOMETRY Connection CID 7.656 in. CoW4ing Length 10-200 ir, CDnnecbcn RD 6.264 iL Make-up Loss 4.579 in Threads per in 5 Ccrineclion 00 Crfcn REGULAR PERFORMANCE Tension EfFci-,7qv 100.0% Join'. Y*Id Strength 604-1)1 h9emal Pressure Capacity n 7240.000 psi lbs Corrpres-icri EFbeicy 100% Compression Strength 604-OOOxl1X,0 Max.McwableBendmg 52 "400 h 11's External Pnesaure, Capadtj 5410.000 psi MAKE-UP TORQUES Minimum 13230 Nibs OptrnLTn 14750 ft -lbs Maidmirn 16230 ft-bs OPERATION L3MIT TORQUES Operating Terque 20000 ft -lbs Yield Torcpe 23400 ft -lbs Notes This conne--tjon is fully intercttangeable With: TXRE, BTC - 7 in. - 23 129 / 32 135 138 Ibs1ft [1) IrAemal Pressure Capackv related to structural resistance only. Intemal pressure leak resistance as per section 10.3API 5C3 I ISO 90400 - 2007. Page 37 17.7 M/U 7" to DP crossover. 17.8 M/U stand of DP to string, and M/U top drive. 17.9 Break circulation at 1 bpm and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 — l0k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.12 P/U string & remove unnecessary 7" joints. 17.13 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.14 Ensure circulation is possible through 7" string. 17.15 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.16 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.17 Slack off and land hanger. 17.18 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.19 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.20 R/D casing running tools. 17.21 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min. 17.22 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 Milne Point Unit M-34 SB Producer Hilcox Enact C®pmy Drilling Procedure 17.7 M/U 7" to DP crossover. 17.8 M/U stand of DP to string, and M/U top drive. 17.9 Break circulation at 1 bpm and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 — l0k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.12 P/U string & remove unnecessary 7" joints. 17.13 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.14 Ensure circulation is possible through 7" string. 17.15 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.16 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.17 Slack off and land hanger. 17.18 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.19 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.20 R/D casing running tools. 17.21 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min. 17.22 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 Hilcorp En.W C—PnY 18.0 Run Upper Completion Milne Point Unit M-34 SB Producer Drilling Procedure 18.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test same. Verify the Jet pump components. 18.2 Run the 4-1/2" Jet Pump Completion as per the following, verify with Operations Engineer: 4-1/2" Multi -drop Gauge Mandrel 5' pup joint 4-1/2" Sliding Sleeve )e 5' pup joint 4-1/2" Gauge Mandrel rw�� 4' pup joint 10' pup joint �� 4-1/2" X Nipple (ID=3.813 ") 10' pup joint 10' pup joint 7"x4-1/2" Retrievable Packer 10' pup joint 10' pup joint 4-1/2" XN Nipple (I13=3.75") — set shallower than 70deg deviation. Preload RHC plug body. 10' pup joint 4-1/2" full joints (# joints to be determined by on deviation survey) 4-1/2" WLEG Confirm depths with OE post drilling and final directional survey (reference updated schematic). 18.3 M/U Jet Pump assembly and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 MU tubing hanger and landing joint. Terminate control lines. 18.6 Land tubing hanger. 18.7 Drop ball and rod, pressure up to 1,700 psi to start setting of PHL packer. 18.8 Continue to pressure up to 3,000 psi to set packer. ,rc 18.9 Pressure up to 3,500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. 18.11 Pressure up annulus to 3,500 psi to test casing/packer for 30 minutes and chart. 18.12 Bleed tubing and IA down to 0 psi. 18.13 RILDS and test hanger. LD landing joint. 18.14 Install BPV. N/D BOP. Page 39 Milne Point Unit M-34 SB Producer Drilling Procedure 18.15 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.16 We won't be able to freeze protect the well with the rig. SL will be required to open the sliding sleeve to do this. Notify Wells Foreman of timing to ensure as close of coordination for SL from rig departure as possible. 18.17 Set BPV plug. Test tree to 250 psi low / 5000 psi high. Pull BPV plug and BPV. 18.18 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.19 Notify AOGCC of SVS testing. Test SVS on horizontal run of tree within 5 days of the start of production. Set low pressure trip below 275 psi Moose Pad header & separator pressure. 18.20 RDMO Doyon 14 Page 40 Hil=Encw Campmy 19.0 Doyon 14 Diverter Schematic 21AW 2M Riser - 21 -114* 2M— Divener -r 21-li4' 21. Spacer Spoo 15-314'3M a 1.4' 2M DSA Page 41 Milne Point Unit M-34 SB Producer Drilling Procedure —tb' full OWIN "ItC VMve 16' Diveder Une Hil=E—W wor 20.0 Doyon 14 BOP Schematic KA Line Page 42 Milne Point Unit M-34 SB Producer Drilling Procedure 2-7/8" x 5" VBR Blind Rams x SM HCR h*e Line 0 Gate VaW 2-7/8" x 5" VBR Hilcox EneW c— 21.0 Wellhead Schematic Milne Point Unit M-34 SB Producer Drilling Procedure CR, FN tiI Up. rvRv- �Fjric, , , 7 1 ' I----------- --- e3'.L i - ; t �•, icac s[c,�c, a 1r1LH 131W tAVFP aJ-. ---nl F -d. 91U a 11 EL 'LY i .IF rw all e t 2 u r . v 6 . 5 .. c4 N,,141 £G, u1'Or,Et_ FLUTUE �I F rpL.TSII 5C .6.0 Lu . t s l B, w 9 S $,1M N' .P ry I x @ ( p e:a 2' L •I' iGV ,•v,riLL 1Ai'kP N '9-V 5£dt. 1CP1 11000 2405 1 I r 1 fl+ iPF F, Ii.27 ea%t, A"M M.r N ' 4 KGtif!U M X5.2 & 11r ui art _ a_ --1. Al IFG RING Owl EI .. A,00 SL ire la[r Tq,^. ,52t k0vN •., _ JG 1.�CI , "CC' 1131 C;Fi! 5 SLPI HOLE x t rs — - W.a IL, --. — CT j.tJl. F u « , _ ii �'.(.F(A%i, s.Ity Rf FM a a t i 5tl t1 hA:L +Ci 55 11 _ . aR..aecca>oq •:�Pq.4:: aerty _. e.i quu-G. -._ c EV. .r,11Ltn •o-< n -' 1e. tb un r„•. Ott -2 �.-I i K— 1.." t( uYe: 4 R [r' I F 3 t'N[:'eLU N •�..•.v� -. .ctN 4G tt11EE�' i „d .,., [IM Page Page 43 22.0 Days Vs Depth N 4f INI . �R s aci 8000 0 a v N 10000 v 12000 14000 16000 18000 0 Page 44 MPU M-34 SB OB Producer Days vs Depth 5 10 15 20 Days 25 Milne Point Unit M-34 SB Producer Hilco F-� �� Drilling Procedure 22.0 Days Vs Depth N 4f INI . �R s aci 8000 0 a v N 10000 v 12000 14000 16000 18000 0 Page 44 MPU M-34 SB OB Producer Days vs Depth 5 10 15 20 Days 25 Hilcorp Energy Compmy 23.0 Formation Tops & Information Milne Point Unit M-34 SB Producer Drilling Procedure MPU M-34 Formations (wp05) MD (ft) TVDss (ft) TVD (ft) Formation Pressure EMW (psi) (ppg) Base Permafrost 2427 1786 1844 811.36 8.46 LA3 4997 3047 3105 1366.2 8.46 Schrader Bluff NA 6000 3539 3597 1582.68 8.46 Schrader Bluff OB 6991 3793 3851 1694.44 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST SS TVD FM LITH GEOLOGICAL DESCRIPTION COMMENTS An r»oe NOTE: See individual Well Program for T.A-- pft Gublk specific casing design, depths, sizes, ,10)". 6W weights, grades and connections. • Unconsolidated coarse to medium sand and small gravel with "nor siltstone. 1,000 a • IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE ♦a SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. nso' Base permafrost Initerbods of sand, clays and sittstones with occasional 2,000' show ot coal. Watch possible sidetracking while wsahinglroaming. L-33 6 L-+5. Sagan rktok fit■ No hydrates encountered on L -Pad wells drilled to date. Comirwod interbeds of sand, clays and sli atones with occaslon al shows of coal- Tracos of pyrito at +1. 3+00 ft 3,000, hterval at H- 3400 it can be sticky and tight (L.01). Clay interbeds between 3000 and 4500 it C 3472•- L A 3657• rsand. Y UGNU: Series of coarsening upward sands which aro l-AB•CD) made up of: (from top to bottom) coarse sand fine sand, silty shale. Better developed Intervening shales as you UGNU progress into the Land M (deeper} Ugnu and Schrsdor Bluff'. Possible hydrocarbons limited Lti ndh to Sw toner of Milne development Northern area Is 14X) downstructure and wet. •3739' wanm ( AB.c) •4000 (f'tA) Schrader Bluff Sands: 4,0001(Asco. Continued layering coarsen big upward sands asabove -411*11111 Schrader Bluff: Possible lost circulation t;r/ except more condensed and with occasional coal. zone while drilling long strings and running •4170' osand. Clay rich shale Interval 4300 to 4600 ft Ugnu and Schrader Bluff Possible hydrocarbons limited casing. Recommend deep setting surface (OA) ! AMC. tc S W toner of Milnedoyolopnent L-37 and L -4S are casing for Kuparuk long strings. Also, the completed In the Schrader Bluff sand Northam ansa ot Schrader Bluff sands area potential Schrader L -Pad is downstnrcturo and wet, differentia) stuck pipe interval if left un -cased Bluff C Surface casing point In shale below for Kuparuk long strings. Sands: Schrader Bluff OB sand for longer reach wells. I I Page 45 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation % Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates 1. Gas hyrates have not been seen on Moose pad. However, be prepared for them. 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: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. 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. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 46 Milne Point Unit M-34 SB Producer Hilco Energy com Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation % Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates 1. Gas hyrates have not been seen on Moose pad. However, be prepared for them. 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: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. 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. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 46 ff Hilcorp Energy Company Milne Point Unit M-34 SB Producer Drilling Procedure 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 1-12S 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 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 at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a 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 1-12S. No 142S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: ✓ Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M 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. Reference A/C report in directional plan. See section 15.14 for well specific A/C. Page 48 Milne Point Unit M-34 SB Producer Hilco+Tf�+1 Pnei l Cumpany 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 at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a 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 1-12S. No 142S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: ✓ Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M 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. Reference A/C report in directional plan. See section 15.14 for well specific A/C. Page 48 25.0 �uvuu 14 Lavuut Page 49 Ln rn Q +eooKre+t� 1 Milne Point Unit M-34 SB Producer Hilczjx F..W Drilling Procedure 25.0 �uvuu 14 Lavuut Page 49 Ln rn Q +eooKre+t� 1 N v 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-34 SB Producer Drilling Procedure 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/IJ 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 27.0 Doyon 14 Choke Manifold Schematic Page 51 Milne Point Unit M-34 SB Producer Hilco �� Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 51 Milne Point Unit M-34 SB Producer Drilling Procedure 28.0 Casing Design n HiIMT Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 12/19/2019 WELL: MPU M-34 DESIGN BY: Joe Engel Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1308 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1308 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 52 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 6-5/8" Top (MD) 0 6,945 Top (TVD) 0 3,848 Bottom (MD) 6,945 17,711 Bottom (TVD) 3,848 3,753 Length 6,945 10,766 Weight (ppf) 40 20 Grade L-80 L-80 Connection TXP H563 Weight w/o Bouyancy Factor (lbs) 277,800 215,320 Tension at Top of Section (lbs) 277,8001 215,320 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.30 2.13 Collapse Pressure at bottom (Psi) 1,901 ' 1,854 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.63 V7 1.87 MASP (psi) 1,308 1,308 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 4.40 4.66 Page 52 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation xilcor8-1/2" Hole Section °" MPU M-34 Milne Point Unit MD TVD Planned Top: 6945 3848 Planned TD: 17711 3753 Milne Point Unit M-34 SB Producer Drilling Procedure 4nticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OB Sand 3,848 1693 Oil 8.46 0.440- Offset .440- Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date J-23 9.1 Surface 3864 2000 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3848 (ft) x 0.78(psi/ft)= 3001 3001(psi) - [0.1(psi/ft)*3848(ft)]= 2617 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 3848 (ft) x 0.44(psi/ft)= 1693 psi 1693(psi) - 0. 1(psi/ft) *3848(ft) 1308 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure euetie of entire wellbore to gas at 0.1 psi/ft. Page 53 30.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-34 SB Producer Drilling Procedure 11 t'k— Ala+\e.t 11 &up Bata: 1Z'16,2019 Page 54 Milne Point Unit MPU M-34 Well wp05 Alaska Stale Plane Zone 4 NAD 1927 /r 0 1,000 2,000 (Y� Feet GI -c Sec. 12 1 ♦♦ Jf f ` r Sec -'?It/ 'w +� Se ill r 1 ADL388235 ' ADU025509'J'{626j`Y Pyr r A L 5 02 r� I - - J' lL 8Pe1 <. \ r Jr♦ ,r L-08Pr -1. e2 iiI MPU 1,1-334 SHI-`. J J ~f rx�`J r ♦\ r f \+� • � 1 1-r1 7,yr_il - 1 •1'} ' w zs.i:eal `v ' r A. 1 1 ♦J' J f Jf,.+♦ l {]S . I •., ' J♦♦ � J I J� JI \ 1 r f . I 1 11 1♦`' \ y\r �� \Y �J PJJ 'IPE S4BUh r f \ + \♦ r 'I' ♦♦ I r 1 { , ti 1 I \ \, J ♦4' `L.35•iJ , Z .�PE9AD7.A ♦ f f \ t' � 1+lam f t r a S L 1 1 ♦+ ♦I J♦ v/ �{' \ !! r a \ F.1'0 1 \'-133 1 a1 L 1 AJ . Sec. 13 >> f r ! + Sec- 18 r . 4 Se:.114 '! , J l L . J i ,1 / � 1 f r �+ I L ' ' ♦ JJ / +\ ♦ � rl '' � f Y ' L.i_' I J J dr -61 JI I I I l t li : JJ / \` r` L rte\ 1 f rr.tcrn�•. � 1,1PUNI-34TPH IJ ' f 1 � t.i-C3 1 ►t 1 ;,, , _ !� '1 � it J V:15 , ♦� 1 '\\ r '♦ r L / ♦ � • FEt f J /'\ ♦�PONITUNIT,.'. ADL025O i 1 +/JI L11� 1♦ ' N��. IJ 1 LI> 1 r f4DL025514+ 1 'J I > r1 6J1`, L1VLh i• I 'I' 1 IN >1 i J♦ LU01314009E�`„' `�`� �� U013NO10E ♦l / 1 1 \1 w�`\ S_23 1 1 x1.'1 Sec 24 •w♦ • Sec. 19. '. 1 I �x423Fat , }^3 (6331M-19 Paz IFE.i '\ t • A421 L.35aFe2• L.3i.:,es' \ V ` L -11A '24 L�Pai- E1tJIFta1Et'J7 \..__ '. ` Legend ✓ ! i, - ` KUPARf ! MPU M-34 _SHL j �� - — - } `a" '♦ RIVEF x ADL025517 •� L UNIT �` MPU M-34_TPH }-23a Sec. 26 ' ADL025519 MPU M-34 BHL _ _ - r Other Surface Holes (SHL) },28 ., .zSec. J 12x1 (636) Oliver Bottom Holes (BHL} A% Other Well Paths / }'28 + I L J! Oil and Gas Unit Boundary rr 3r,23 J J / Pad Footprint MPU ht -34 BHL - L L �+ J 1 1 ' J' 11 t'k— Ala+\e.t 11 &up Bata: 1Z'16,2019 Page 54 Milne Point Unit MPU M-34 Well wp05 Alaska Stale Plane Zone 4 NAD 1927 /r 0 1,000 2,000 (Y� Feet 1 31.0 Surface Plat (As Staked) (NAD 27) As Built to be submitted once complete 12 GRIDZ _ lmMOM Milne Point Unit �/( M-34 SB Producer Hilc Enw CzT Drilling Procedure 1 31.0 Surface Plat (As Staked) (NAD 27) As Built to be submitted once complete Page 55 12 GRIDZ _ lmMOM �/( / f PAD m �Kt I I i Y PAD 7 SEC. 12 I SEC,73 -- I u SEC, 11 I M_{4 SEC, 14 ( M_10 r I j I M -N ■ I M-11 ■ I 23 1 M'1S I 8■IE SITE E I M-12 XF ( ■ Y-74 I , +M-35 I VICINITY MAP I M-ZO ■ NTS I M-57 � ■ 81-15 I +M-34 M-21 M I I ■ w,6 M -ser I LEGEND; M-22 ■ I M Y -17I + AS -STAKED, CONDUCTOR M-23 ■ ■ 81-78 I A EXISTING CONDUCTOR bI.$I I M-24 ■ ■ 81-19 I NOTES; 1. ALASKA STATE BANE COORDINATES ARE NAD27. ZONE 4. 2. OEODEDC POSIMNS ARE NAD27. M-26 Iff i 3. BASS OF 11 =ONTAL AND 1wTIm CmwA i5 LOOSE I M_a ■ PAD MONUMENT SW -ALCM STKD W_ I M-03_ 4. MPU WOOSE PAD SCAB FACTOR IS: &9994013. ■ —05 I 5. DATE OF SURVE)' NDIflASER 25, 2019. ■ M-06 I I 6. REFERENCE FED 9COK: NCIO-04 PC 21L 1 I GRAPHIC SCALE 0 fDa 200 400 MOOSE PAD 1 t IN FEET ) t Inch - 200 Fl, LOCATED WITHIN PROTRACTED SEC. 14, T. 13 N., R, 9 E., UMIAT MERIDIAN, ALASKA WELL A.S,P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR N0. COORDINATES COORDINATES POSITION(DMS) POSITION p.pp) OFFSETS ELEVATION BOX EL. M-� I Y= 6,027,765.64 N= 1,167.99 7x'29'12.785" 70.48&884T 4,914' FSL X�+ 533,783.85 E= 1,785.02 749'43'25.944' 149.7238738' 3$1' FEL 24.7" N A / Y= 6,027,765.63 N= 1,167.98 70"29'12.781" 70.4858836' 4,913' FSL M-35 X= 833873.$1 E= 1,874.99 14943'23.297" 748.7231382' 291' FEL 24.9' N/A � Hileorp Alaska tgja a MPU MOOSE PAD M. 12/7/1 AMM LULS X++ AS -STAKED CONDUCTORS 1' . 2L IL= I "n R[Vml WELLS M-34 & M-35 t a t Page 55 Page 55 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart SB OB wells are expected to be nonnally pressured, same gradient as OA Schrader Bluff OA Sand Offset MW vs TVD MW, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 4111 11 m 1500 2000 D 2500 �1I 3500 4500 Page 56 MPU L-46 (2015) MPU L-47 (2015) MPU L-48 (2015) MPU L-49 (2015) MPU L-50 (2015) MPU F-106 (2017) MPU F-107 (2017) MPU F-108 (2017) MPU F-109 (2017) MPU F-110 (2017) Milne Point Unit M-34 SB Producer Hilco F-� �� Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart SB OB wells are expected to be nonnally pressured, same gradient as OA Schrader Bluff OA Sand Offset MW vs TVD MW, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 4111 11 m 1500 2000 D 2500 �1I 3500 4500 Page 56 MPU L-46 (2015) MPU L-47 (2015) MPU L-48 (2015) MPU L-49 (2015) MPU L-50 (2015) MPU F-106 (2017) MPU F-107 (2017) MPU F-108 (2017) MPU F-109 (2017) MPU F-110 (2017) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-34 MPU M-34 Plan: MPU M-34 wp05 Standard Proposal Report 16 December, 2019 HALLIBURTON Sperry Drilling Services -8250 -9000 Start Dir 4°/100' :12882.09' MD, 3818.4'TVD M-34 wp04 CPI _ , - End Dir : 12926' MD, 381 T9T TVD -9750 - - - ✓ r 1 10500 MPU Lease line - full � I I -11250 i I I -12000 I I \81/�T' : 17711.14' MD, 3753.1' TVD I -12750 _ MPU M-34 wp05 43500- 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usft/in) I 1 WELL DETAILS: Plan: MPU M-34 750 I +N/ -S +E/ -W24.70 Northing Easting Latittude Longitude I 1 0.00 0.00 6027765.64 533783.85 70° 29' 12.785 N 149° 43'25,944 W Start Dir 3°/100':250'MD,250'TVD REFERENCE INFORMATION _ 1 - Co-ordinate (N/E) Reference: Well Plan: MPU M-34, True North 0 - - -Start Vertical (TVD) Reference: MPU M-34 As -Staked RKB @ 58.40usft (Original Well Elev) Dir 4°/100' : 400' MD, 399.85'TVD Measured Depth Reference: MPU M-34 As -Staked RKB @ 58.40usft (Original Well Elev) Calculation Method: Minimum Curvature 525° End Dir : 1811.65' MD, 1542.51' TVD CASING DETAILS -750 TVD TVDSS MD Size Name `2go 3848.15 3789.75 6945.80 9-5/8 9 5/8" x 12 1/4" 3753.10 3694.70 17711.14 4-1/2 4 1/2" x 8 1/2" 200 ° -1500 y25o HALLIBURTON Project: Milne Point Site: M Pt Moose Pad Sperry Drilling Well: Plan: MPU M-34 -2250 250o Wellbore: MPU M-34 Plan: MPU M-34 wp05 1 3000 -3000- ,5250 - StartDir 4°/100' : 6070.82' MD, 3632.04TVD -3750- 3750 X50 - End Dir : 6745.8' MD, 3830.72' TVD -4500 9 5/8" x 12 1/4" - - - - - - Start Dir 4Q/100': 6945.8' MD, 3848.15'TVD M-34 wp04 Heel End Dir : 7080.84' MD, 3853.63' TVD G -5250- 5250-6000C -6000— t: 70 ^ -6750— t O rn -7500 Fault -8250 -9000 Start Dir 4°/100' :12882.09' MD, 3818.4'TVD M-34 wp04 CPI _ , - End Dir : 12926' MD, 381 T9T TVD -9750 - - - ✓ r 1 10500 MPU Lease line - full � I I -11250 i I I -12000 I I \81/�T' : 17711.14' MD, 3753.1' TVD I -12750 _ MPU M-34 wp05 43500- 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usft/in) SECTION DETAILS Project: Milne Point Site: M Pt Moose Pad Sec 1 MD IncAzi TVO +N/ -S 33.70 0.00 0.00 33.70 0.00 +E/ -W Dleg TFace VSect 0.00 0.00 0.00 0.00 Target Annotation Well: Plan: MPU M-34 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100': 250' MD, 250TVD Wellbore: MPU M-34 3 4 400.00 4.50 170.00 399.85 5.80 950.00 26.44 16160 926.72 -144.96 1.02 3.00 170.00 5.22 43.95 4.00 -10.00 141.67 StartDir 4°/100': 400' MD, 399.85TVD Design: MPU M-34 wp0 5 1811.65 60.62 154.67 1542.51 582.62 272.06 4.00 -10.71 706.83 End Dir : 1811.65' MD, 1542.51' TVD g 6 6070.82 60.62 154.67 3632.04 A037O9 1860.13 0.00 0.00 4333.49 StartDir 4°/100' : 6070.82' MD, 3632.04'4 7 6745.80 85.00 142.40 3830.72 -0579.33 2197.36 4.00 -27.79 4968.87 End Dir : 6745.8' MD, 3830.72' TVD MALUBURTON 8 6945.80 85.00 142.40 3848.15 -0737.19 2318.93 0.00 0.00 5168.11 M-34 wpO4 Heel Start Dir 4-1100': 6945.8' MD, 3848.15'Tl 9 7080.84 90.35 143.16 3853.63 -0844.60 2400.51 4.00 8.11 5302.98 End Dir : 7080.84' MD, 3853.63' ND eo.m•r ornoe® 10 12882.09 90.35 143.16 3818.40 -9487.38 5878.70 0.00 0.00 11103.61 M-34 wp04 CP1 StartDir4°/100': 12882.09' MD, 3818.4'7 11 12926.00 90.78 141.46 3817.97 -9522.12 5905.54 4.00 -75.86 11147.52 End Dir : 12926' MD, 3817.97' ND 12 17711.14 90.78 141.46 3753.10 -13264.45 8886.87 0.00 0.00 15931.57 M-34 wp04 Toe Total Depth : 17711.14' MD, 3753.1' ND Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA WELL OETAILs: Plan: MPU M-34 SURVEY PROGRAM Scan Method: Closest Approach 3D 2470 L4ngdude Date: 2019-12-16700:00:00 Validated: Yes Version: Error Surface: Pedal Curye Warning Method: Error Ratio +N/ -s .E/ -w NartM1ing Easting Latitude 0.00 0.00 6027/65.64 53378385 ]0.29' 12785 N 149' 43' 25944 W Depth From Depth To Survey/Plan Tool 33.70 650.00 MPU M-34 wp05 (MPU M-34) 3_Gyro-GC REFERENCE INFORMATION 650.00 6945.80 _Csg MPU M-34wp05 (MPU M-34) 3 MWD+IFR2+MS+: FORMATION TOP DETAILS 6945.80 17711.14 MPU M-34 wp05 (MPU M-34) 3 MWD+IFR2+MS+; T1O TV MOPat2 Formelien Reference: Well Plan: MPV M-34, True Nodh Cc-artlinate (TVD) Vertical (TVO) Relerence: MPU M30 ASStaketl RKB 5840usR (Gdginal Well El,,) 124800 t 306.40 17M 00 141872 SV5 40 1844.40 1788.00 242400 BPRF Measured Depth Rarerence: MPU M- M4 taked RKB @ SB 40usft (Original Well Elev) 1882.40 1824.00 250446 SV1 Calculation MetM1a4 Minimum Curvature 310540 3047.00 4994.34 LA3 3371.40 331300 5539.54 UGNU MB 3597.40 3539.00 61100.21 SB NA CASING DETAILS 3851.40 3793.00 6991.26 SB OB (heap NO TV 3848.15 3789.75 6945.80 3753.10 3694.70 17711.14 MD Size Name 9-5/8 9 5/6. x 12 1/4" 4-12 4 12" x 8 12" -2000 -1000 O Start Dir 3-/100': 250' MD, 2507VID ti� O 2C,0 0 Din' Start,ryyO /�1y0oo0- o D TVarO 0 0p-' 9h.y8o , ryOO Oh End Dir 1811.65' MD, 1542.51' TVD ' 500 9,o 0p0 y O`y 0 • �X c,, 1000 SV5 O O O `5 o4° 6PRF 003 �O . O ' o 0 2000 Qjcpotv0) a SV1 0 O5 ao4o 0Mo >``' P �Qs h c^D / ; LA3 3000 o5' 'OD rO -UM- Q B "OxM.^ 8 1. 2� /2O"----UGN 4^1n/ - SB -NA ..... .. ...... _ _.... .O.3.O..9. 4000 -- -- -" a yr a a -a w w rw w iry in rn 0 ��$ m v v MPU M-34 wp05 ut SB OB (heel) 0 0 0 0 0 00 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 S o $ - 9 5/8" x 12 1/4" i M-34 wp04 Toe 5000 M-34 wp04 Heel M-34 wp04 CP1 6000 _ _r 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 Vertical Section at 142.40° (2000 usftln) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-34 Wellbore: MPU M-34 Design: MPU M-34 wp05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-34 TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) • System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Wellbore MPU M-34 Site M Pt Moose Pad Site Position: Northing: 6,027,877.65 usft Latitude: 70° 29' 13.905 N From: Map Easting: 533,363.92 usft Longitude: 149° 43' 38.286 W Position Uncertainty: 5.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M-34 Well Position +N/ -S 0.00 usft Northing: 6,027,765.64 usfl • Latitude: 70° 29' 12.785 N +E/ -W 0.00 usft Easting: 533,783.85 usfi . Longitude: 149° 43'25.944 W Position Uncertainty 0.00 usft Wellhead Elevation: usfi Ground Level: 24.70usft Wellbore MPU M-34 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2019 1/8/2020 16.18 80.90 57,402.77825074 Design MPU M-34 wp05 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 142.40 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -2470 0.00 0.00 0.00 0.00 0.00 0.00 250.00 0.00 0.00 250.00 191.60 0.00 0.00 0.00 0.00 0.00 0.00 400.00 4.50 170.00 399.85 341.45 -5.80 1.02 3.00 3.00 0.00 170.00 950.00 26.44 161.60 926.72 86832 -144.96 43.95 4.00 3.99 -1.53 -10.00 1,811.65 60.62 154.67 1,542.51 1,484.11 -682.62 272.06 4.00 3.97 -0.80 -10.71 6,070.82 60.62 154.67 3,632.04 3,573.64 -4,037.09 1,860.13 0.00 0.00 0.00 0.00 6,745.80 85.00 142.40 3,830.72 3,77232 -4,579.33 2,197.36 4.00 3.61 -1.82 -27.79 6,945.80 85.00 142.40 3,848.15 3,789.75 -4,737.19 2,318.93 0.00 0.00 0.00 0.00 7,080.84 90.35 143.16 3,853.63 3,795.23 -4,844.60 2,400.51 4.00 3.96 0.56 8.11 12,882.09 90.35 143.16 3,818.40 3,760.00 -9,487.38 5,878.70 0.00 0.00 0.00 0.00 12,926.00 90.78 141.46 3,817.97 3,759.57 -9,522.12 5,905.54 4.00 0.98 -3.88 -75.86 17,711.14 90.78 141.46 3,753.10 3,694.70 -13,264.45 8,886.87 0.00 0.00 0.00 0.00 12/16/2019 1:59, 00PM Page 2 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-34 Wellbore: MPU M-34 Design: MPU M-34 wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-34 TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -24.70 33.70 0.00 0.00 33.70 -24.70 0.00 0.00 6,027,765.64 533,783.85 0.00 0.00 100.00 0.00 0.00 100.00 41.60 0.00 0.00 6,027,765.64 533,783.85 0.00 0.00 200.00 0.00 0.00 200.00 141.60 0.00 0.00 6,027,765.64 533,783.85 0.00 0.00 250.00 0.00 0.00 250.00 191.60 0.00 0.00 6,027,765.64 533,783.85 0.00 0.00 Start Dir 30/100' : 250' MD, 250 -TVD 300.00 1.50 170.00 299.99 241.59 -0.64 0.11 6,027,765.00 533,783.97 3.00 0.58 400.00 4.50 170.00 399.85 341.45 -5.80 1.02 6,027,759.85 533,784.90 3.00 5.22 Start Dir 4°/100' : 400' MD, 399.85'TVD 500.00 8.47 165.28 499.19 440.79 -16.79 3.58 6,027,748.87 533,787.50 4.00 15.48 600.00 12.46 163.57 597.50 539.10 -34.26 8.50 6,027,731.42 533,792.50 4.00 32.33 700.00 16.45 162.68 694.32 635.92 -58.13 15.77 6,027,707.59 533,799.88 4.00 55.68 800.00 20.45 162.12 789.16 730.76 -88.28 25.35 6,027,677.48 533,809.60 4.00 85.41 900.00 24.44 161.75 881.57 823.17 -124.57 37.20 6,027,641.25 533,821.61 4.00 121.39 950.00 26.44 161.60 926.72 868.32 -144.96 43.95 6,027,620.90 533,828.45 4.00 141.67 1,000.00 28.41 160.82 971.10 912.70 -166.76 51.37 6,027,599.13 533,835.98 4.00 163.47 1,100.00 32.36 159.52 1,057.35 998.95 -214.31 68.56 6,027,551.66 533,853.38 4.00 211.63 1,200.00 36.31 158.48 1,139.91 1,081.51 -266.95 88.79 6,027,499.13 533,873.85 4.00 265.68 1,300.00 40.28 157.61 1,218.37 1,159.97 -324.40 111.98 6,027,441.78 533,897.29 4.00 325.34 1,400.00 44.25 156.88 1,292.37 1,233.97 -386.40 138.00 6,027,379.91 533,923.59 4.00 390.34 1,419.72 45.03 156.75 1,306.40 1,248.00 -399.13 143.46 6,027,367.20 533,929.10 4.00 403.76 SV5 1,500.00 48.22 156.24 1,361.53 1,303.13 -452.63 166.73 6,027,313.81 533,952.62 4.00 460.35 1,600.00 52.20 155.68 1,425.52 1,367.12 -522.79 198.04 6,027,243.81 533,984.24 4.00 535.03 1,700.00 56.18 155.18 1,484.02 1,425.62 -596.52 231.76 6,027,170.24 534,018.29 4.00 614.02 1,800.00 60.16 154.72 1,536.76 1,478.36 -673.46 267.73 6,027,093.47 534,054.61 4.00 696.94 1,811.65 60.62 154.67 1,542.51 1,484.11 -682.62 272.06 6,027,084.33 534,058.98 4.00 706.83 End Dir : 1811.65' MD, 1542.51' TVD 1,900.00 60.62 154.67 1,585.86 1,527.46 -752.20 305.01 6,027,014.90 534,092.24 0.00 782.06 2,000.00 60.62 154.67 1,634.92 1,576.52 -830.96 342.29 6,026,936.32 534,129.88 0.00 867.21 2,100.00 60.62 154.67 1,683.98 1,625.58 -909.72 379.58 6,026,857.74 534,167.52 0.00 952.36 2,200.00 60.62 154.67 1,733.04 1,674.64 -988.48 416.86 6,026,779.16 534,205.16 0.00 1,037.51 2,300.00 60.62 154.67 1,782.10 1,723.70 -1,067.24 454.15 6,026,700.58 534,242.80 0.00 1,122.66 2,400.00 60.62 154.67 1,831.15 1,772.75 -1,146.00 491.43 6,026,622.00 534,280.44 0.00 1,207.81 2,427.00 60.62 154.67 1,844.40 1,786.00 -1,167.26 501.50 6,026,600.78 534,290.60 0.00 1,230.80 BPRF 2,500.00 60.62 154.67 1,880.21 1,821.81 -1,224.76 528.72 6,026,543.42 534,318.08 0.00 1,292.96 2,504.46 60.62 154.67 1,882.40 1,824.00 -1,228.26 530.38 6,026,539.92 534,319.75 0.00 1,296.75 SV1 2,600.00 60.62 154.67 1,929.27 1,870.87 -1,303.51 566.01 6,026,464.84 534,355.71 0.00 1,378.11 2,700.00 60.62 154.67 1,978.33 1,919.93 -1,382.27 603.29 6,026,386.26 534,393.35 0.00 1,463.26 2,800.00 60.62 154.67 2,027.39 1,968.99 -1,461.03 640.58 6,026,307.68 534,430.99 0.00 1,548.41 2,900.00 60.62 154.67 2,076.45 2,018.05 -1,539.79 677.86 6,026,229.10 534,468.63 0.00 1,633.56 3,000.00 60.62 154.67 2,125.51 2,067.11 -1,618.55 715.15 6,026,150.52 534,506.27 0.00 1,718.70 3,100.00 60.62 154.67 2,174.57 2,116.17 -1,697.31 752.43 6,026,071.93 534,543.91 0.00 1,803.85 3,200.00 60.62 154.67 2,223.63 2,165.23 -1,776.07 789.72 6,025,993.35 534,581.55 0.00 1,889.00 12/162019 1:59:OOPM Page 3 COMPASS 5000.15 Build 91E 7=ffTiTwA1_--1 0 1 - - Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-34 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Project: Milne Point MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-34 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-34 Design: MPU M-34 wp05 Planned Survey - - - - _- Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 2,214.29 3,300.00 60.62 154.67 2,272.69 2,214.29 -1,854.83 827.01 6,025,914.77 534,619.19 0.00 1,974.15 3,400.00 60.62 154.67 2,321.75 2,263.35 -1,933.58 864.29 6,025,836.19 534,656.83 0.00 2,059.30 3,500.00 60.62 154.67 2,370.81 2,312.41 -2,012.34 901.58 6,025,757.61 534,694.47 0.00 2,144.45 3,600.00 60.62 154.67 2,419.87 2,361.47 -2,091.10 938.86 6,025,679.03 534,732.11 0.00 2,229.60 3,700.00 60.62 154.67 2,468.93 2,410.53 -2,169.86 976.15 6,025,600.45 534,769.75 0.00 2,314.75 3,800.00 60.62 154.67 2,517.99 2,459.59 -2,248.62 1,013.43 6,025,521.87 534,807.39 0.00 2,399.90 3,900.00 60.62 154.67 2,567.05 2,508.65 -2,327.38 1,050.72 6,025,443.29 534,845.03 0.00 2,485.05 4,000.00 60.62 154.67 2,616.11 2,557.71 -2,406.14 1,088.01 6,025,364.71 534,882.67 0.00 2,570.20 4,100.00 60.62 154.67 2,665.17 2,606.77 -2,484.90 1,125.29 6,025,286.13 534,920.31 0.00 2,655.35 4,200.00 60.62 154.67 2,714.23 2,655.83 -2,563.65 1,162.58 6,025,207.55 534,957.95 0.00 2,740.50 4,300.00 60.62 154.67 2,763.29 2,704.89 -2,642.41 1,199.86 6,025,128.97 534,995.58 0.00 2,825.65 4,400.00 60.62 154.67 2,812.35 2,753.95 -2,721.17 1,237.15 6,025,050.38 535,033.22 0.00 2,910.80 4,500.00 60.62 154.67 2,861.41 2,803.01 -2,799.93 1,274.43 6,024,971.80 535,070.86 0.00 2,995.95 4,600.00 60.62 154.67 2,910.47 2,852.07 -2,878.69 1,311.72 6,024,893.22 535,108.50 0.00 3,081.10 4,700.00 60.62 154.67 2,959.52 2,901.12 -2,957.45 1,349.01 6,024,814.64 535,146.14 0.00 3,166.24 4,800.00 60.62 154.67 3,008.58 2,950.18 -3,036.21 1,386.29 6,024,736.06 535,183.78 0.00 3,251.39 4,900.00 60.62 154.67 3,057.64 2,999.24 -3,114.96 1,423.58 6,024,657.48 535,221.42 0.00 3,336.54 4,997.34 60.62 154.67 3,105.40 3,047.00 -3,191.63 1,459.87 6,024,580.99 535,258.06 0.00 3,419.43 LA3 5,000.00 60.62 154.67 3,106.70 3,048.30 -3,193.72 1,460.86 6,024,578.90 535,259.06 0.00 3,421.69 5,100.00 60.62 154.67 3,155.76 3,097.36 -3,272.48 1,498.15 6,024,500.32 535,296.70 0.00 3,506.84 5,200.00 60.62 154.67 3,204.82 3,146.42 -3,351.24 1,535.44 6,024,421.74 535,334.34 0.00 3,591.99 5,300.00 60.62 154.67 3,253.88 3,195.48 -3,430.00 1,572.72 6,024,343.16 535,371.98 0.00 3,677.14 5,400.00 60.62 154.67 3,302.94 3,244.54 -3,508.76 1,610.01 6,024,264.58 535,409.62 0.00 3,762.29 5,500.00 60.62 154.67 3,352.00 3,293.60 -3,587.52 1,647.29 6,024,186.00 535,447.26 0.00 3,847.44 5,539.54 60.62 154.67 3,371.40 3,313.00 -3,618.66 1,662.04 6,024,154.93 535,462.14 0.00 3,881.11 UGNU MB 5,600.00 60.62 154.67 3,401.06 3,342.66 -3,666.28 1,684.58 6,024,107.42 535,484.90 0.00 3,932.59 5,700.00 60.62 154.67 3,450.12 3,391.72 -3,745.03 1,721.86 6,024,028.84 535,522.54 0.00 4,017.74 5,800.00 60.62 154.67 3,499.18 3,440.78 -3,823.79 1,759.15 6,023,950.25 535,560.18 0.00 4,102.89 5,900.00 60.62 154.67 3,548.24 3,489.84 -3,902.55 1,796.44 6,023,871.67 535,597.82 0.00 4,188.04 6,000.00 60.62 154.67 3,597.30 3,538.90 -3,981.31 1,833.72 6,023,793.09 535,635.45 0.00 4,273.19 6,000.21 60.62 154.67 3,597.40 3,539.00 -3,981.47 1,833.80 6,023,792.93 535,635.53 0.00 4,273.36 SB NA 6,070.82 60.62 154.67 3,632.04 3,573.64 -4,037.09 1,860.13 6,023,737.44 535,662.11 0.00 4,333.49 Start Dir 401100' : 6070.82' MD, 3632.04'TVD 6,100.00 61.65 154.05 3,646.13 3,587.73 -4,060.12 1,871.19 6,023,714.46 535,673.27 4.00 4,358.49 6,200.00 65.22 152.02 3,690.85 3,632.45 -4,139.81 1,911.76 6,023,634.96 535,714.21 4.00 4,446.38 6,300.00 68.81 150.10 3,729.90 3,671.50 -4,220.34 1,956.32 6,023,554.64 535,759.13 4.00 4,537.38 6,400.00 72.42 148.27 3,763.09 3,704.69 -4,301.33 2,004.65 6,023,473.88 535,807.82 4.00 4,631.03 6,500.00 76.04 146.51 3,790.26 3,731.86 -4,382.37 2,056.51 6,023,393.09 535,860.04 4.00 4,726.88 6,600.00 79.68 144.81 3,811.29 3,752.89 -4,463.08 2,111.65 6,023,312.64 535,915.54 4.00 4,824.46 6,700.00 83.33 143.15 3,826.06 3,767.66 -4,543.05 2,169.80 6,023,232.94 535,974.05 4.00 4,923.31 6,745.80 85.00 142.40 3,830.72 3,772.32 -4,579.33 2,197.36 6,023,196.79 536,001.77 4.00 4,968.87 End Dir : 6745.8' MD, 3830.72' TVD 12/16/2019 1:59:OOPM Page 4 COMPASS 5000.15 Build 91E HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-34 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Project: Milne Point MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-34 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-34 Design: MPU M-34 wp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,777.04 6,800.00 85.00 142.40 3,835.44 3,777.04 -4,622.11 2,230.30 6,023,154.16 536,034.91 0.00 5,022.86 6,900.00 85.00 142.40 3,844.16 3,785.76 -4,701.04 2,291.09 6,023,075.52 536,096.04 0.00 5,122.48 6,945.80 85.00 142.40 3,848.15 3,789.75 -4,737.19 2,318.93 6,023,039.50 536,124.04 0.00 5,168.11 Start Dir 40/100' : 6945.8' MD, 3848.15'TVD - 9 5/8" x 121/4" 6,991.26 86.80 142.66 3,851.40 3,793.00 -4,773.17 2,346.51 6,023,003.64 536,151.78 4.00 5,213.45 SB_OB (heel) 7,000.00 87.15 142.71 3,851.86 3,793.46 -4,780.12 2,351.80 6,022,996.73 536,157.11 4.00 5,222.18 7,080.84 90.35 143.16 3,853.63 3,795.23 -4,844.60 2,400.51 6,022,932.47 536,206.10 4.00 5,302.98 End Dir : 7080.84' MD, 3853.63' TVD 7,100.00 90.35 143.16 3,853.51 3,795.11 -4,859.93 2,412.00 6,022,917.19 536,217.66 0.00 5,322.14 7,200.00 90.35 143.16 3,852.91 3,794.51 -4,939.96 2,471.95 6,022,837.45 536,277.97 0.00 5,422.13 7,300.00 90.35 143.16 3,852.30 3,793.90 -5,019.99 2,531.91 6,022,757.70 536,338.28 0.00 5,522.12 7,400.00 90.35 143.16 3,851.69 3,793.29 -5,100.02 2,591.86 6,022,677.95 536,398.60 0.00 5,622.11 7,500.00 90.35 143.16 3,851.08 3,792.68 -5,180.05 2,651.82 6,022,598.20 536,458.91 0.00 5,722.10 7,600.00 90.35 143.16 3,850.48 3,792.08 -5,260.08 2,711.78 6,022,518.45 536,519.22 0.00 5,822.09 7,700.00 90.35 143.16 3,849.87 3,791.47 -5,340.12 2,771.73 6,022,438.70 536,579.53 0.00 5,922.08 7,800.00 90.35 143.16 3,849.26 3,790.86 -5,420.15 2,831.69 6,022,358.95 536,639.85 0.00 6,022.07 7,900.00 90.35 143.16 3,848.65 3,790.25 -5,500.18 2,891.64 6,022,279.20 536,700.16 0.00 6,122.05 8,000.00 90.35 143.16 3,848.05 3,789.65 -5,580.21 2,951.60 6,022,199.45 536,760.47 0.00 6,222.04 8,100.00 90.35 143.16 3,847.44 3,789.04 -5,660.24 3,011.55 6,022,119.70 536,820.79 0.00 6,322.03 8,200.00 90.35 143.16 3,846.83 3,788.43 -5,740.27 3,071.51 6,022,039.95 536,881.10 0.00 6,422.02 8,300.00 90.35 143.16 3,846.23 3,787.83 -5,820.30 3,131.47 6,021,960.20 536,941.41 0.00 6,522.01 8,400.00 90.35 143.16 3,845.62 3,787.22 -5,900.33 3,191.42 6,021,880.45 537,001.72 0.00 6,622.00 8,500.00 90.35 143.16 3,845.01 3,786.61 -5,980.36 3,251.38 6,021,800.70 537,062.04 0.00 6,721.99 8,600.00 90.35 143.16 3,844.40 3,786.00 -6,060.39 3,311.33 6,021,720.95 537,122.35 0.00 6,821.98 8,700.00 90.35 143.16 3,843.80 3,785.40 -6,140.42 3,371.29 6,021,641.20 537,182.66 0.00 6,921.97 8,800.00 90.35 143.16 3,843.19 3,784.79 -6,220.45 3,431.25 6,021,561.45 537,242.98 0.00 7,021.96 8,900.00 90.35 143.16 3,842.58 3,784.18 -6,300.48 3,491.20 6,021,481.70 537,303.29 0.00 7,121.95 9,000.00 90.35 143.16 3,841.97 3,783.57 -6,380.51 3,551.16 6,021,401.95 537,363.60 0.00 7,221.94 9,100.00 90.35 143.16 3,841.37 3,782.97 -6,460.55 3,611.11 6,021,322.20 537,423.92 0.00 7,321.93 9,200.00 90.35 143.16 3,840.76 3,782.36 -6,540.58 3,671.07 6,021,242.45 537,484.23 0.00 7,421.92 9,300.00 90.35 143.16 3,840.15 3,781.75 -6,620.61 3,731.03 6,021,162.70 537,544.54 0.00 7,521.91 9,400.00 90.35 143.16 3,839.55 3,781.15 -6,700.64 3,790.98 6,021,082.95 537,604.85 0.00 7,621.89 9,500.00 90.35 143.16 3,838.94 3,780.54 -6,780.67 3,850.94 6,021,003.20 537,665.17 0.00 7,721.88 9,600.00 90.35 143.16 3,838.33 3,779.93 -6,860.70 3,910.89 6,020,923.45 537,725.48 0.00 7,821.87 9,700.00 90.35 143.16 3,837.72 3,779.32 -6,940.73 3,970.85 6,020,843.70 537,785.79 0.00 7,921.86 9,800.00 90.35 143.16 3,837.12 3,778.72 -7,020.76 4,030.81 6,020,763.95 537,846.11 0.00 8,021.85 9,900.00 90.35 143.16 3,836.51 3,778.11 -7,100.79 4,090.76 6,020,684.20 537,906.42 0.00 8,121.84 10,000.00 90.35 143.16 3,835.90 3,777.50 -7,180.82 4,150.72 6,020,604.45 537,966.73 0.00 8,221.83 10,100.00 90.35 143.16 3,835.29 3,776.89 -7,260.85 4,210.67 6,020,524.70 538,027.04 0.00 8,321.82 10,200.00 90.35 143.16 3,834.69 3,776.29 -7,340.88 4,270.63 6,020,444.95 538,087.36 0.00 8,421.81 10,300.00 90.35 143.16 3,834.08 3,775.68 -7,420.91 4,330.59 6,020,365.20 538,147.67 0.00 8,521.80 10,400.00 90.35 143.16 3,833.47 3,775.07 -7,500.94 4,390.54 6,020,285.46 538,207.98 0.00 8,621.79 10,500.00 90.35 143.16 3,832.87 3,774.47 -7,580.98 4,450.50 6,020,205.71 538,268.30 0.00 8,721.78 10,600.00 90.35 143.16 3,832.26 3,773.86 -7,661.01 4,510.45 6,020,125.96 538,328.61 0.00 8,821.77 12/16/2019 1:59:00PM Page 5 COMPASS 5000.15 Build 91E Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-34 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Project: Milne Point MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-34 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-34 Design: MPU M-34 wp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,773.25 10,700.00 90.35 143.16 3,831.65 3,773.25 -7,741.04 4,570.41 6,020,046.21 538,388.92 0.00 8,921.76 10,800.00 90.35 143.16 3,831.04 3,772.64 -7,821.07 4,630.36 6,019,966.46 538,449.23 0.00 9,021.75 10,850.00 90.35 143.16 3,830.74 3,772.34 -7,861.08 4,660.34 6,019,926.58 538,479.39 0.00 9,071.74 Fault 10,900.00 90.35 143.16 3,830.44 3,772.04 -7,901.10 4,690.32 6,019,886.71 538,509.55 0.00 9,121.74 11,000.00 90.35 143.16 3,829.83 3,771.43 -7,981.13 4,750.28 6,019,806.96 538,569.86 0.00 9,221.72 11,100.00 90.35 143.16 3,829.22 3,770.82 -8,061.16 4,810.23 6,019,727.21 538,630.17 0.00 9,321.71 11,200.00 90.35 143.16 3,828.61 3,770.21 -8,141.19 4,870.19 6,019,647.46 538,690.49 0.00 9,421.70 11,300.00 90.35 143.16 3,828.01 3,769.61 -8,221.22 4,930.14 6,019,567.71 538,750.80 0.00 9,521.69 11,400.00 90.35 143.16 3,827.40 3,769.00 -8,301.25 4,990.10 6,019,487.96 538,811.11 0.00 9,621.68 11,500.00 90.35 143.16 3,826.79 3,768.39 -8,381.28 5,050.06 6,019,408.21 538,871.42 0.00 9,721.67 11,600.00 90.35 143.16 3,826.19 3,767.79 -8,461.31 5,110.01 6,019,328.46 538,931.74 0.00 9,821.66 11,700.00 90.35 143.16 3,825.58 3,767.18 -8,541.34 5,169.97 6,019,248.71 538,992.05 0.00 9,921.65 11,800.00 90.35 143.16 3,824.97 3,766.57 -8,621.38 5,229.92 6,019,168.96 539,052.36 0.00 10,021.64 11,900.00 90.35 143.16 3,824.36 3,765.96 -8,701.41 5,289.88 6,019,089.21 539,112.68 0.00 10,121.63 12,000.00 90.35 143.16 3,823.76 3,765.36 -8,781.44 5,349.84 6,019,009.46 539,172.99 0.00 10,221.62 12,100.00 90.35 143.16 3,823.15 3,764.75 -8,861.47 5,409.79 6,018,929.71 539,233.30 0.00 10,321.61 12,200.00 90.35 143.16 3,822.54 3,764.14 -8,941.50 5,469.75 6,018,849.96 539,293.61 0.00 10,421.60 12,300.00 90.35 143.16 3,821.93 3,763.53 -9,021.53 5,529.70 6,018,770.21 539,353.93 0.00 10,521.59 12,400.00 90.35 143.16 3,821.33 3,762.93 -9,101.56 5,589.66 6,018,690.46 539,414.24 0.00 10,621.58 12,500.00 90.35 143.16 3,820.72 3,762.32 -9,181.59 5,649.62 6,018,610.71 539,474.55 0.00 10,721.56 12,600.00 90.35 143.16 3,820.11 3,761.71 -9,261.62 5,709.57 6,018,530.96 539,534.87 0.00 10,821.55 12,700.00 90.35 143.16 3,819.51 3,761.11 -9,341.65 5,769.53 6,018,451.21 539,595.18 0.00 10,921.54 12,800.00 90.35 143.16 3,818.90 3,760.50 -9,421.68 5,829.48 6,018,371.46 539,655.49 0.00 11,021.53 12,882.09 90.35 143.16 3,818.40 3,760.00 -9,487.38 5,878.70 6,018,306.00 539,705.00 0.00 11,103.61 Start Dir 4°/100' : 12882.09' MD, 3818.4'TVD 12,900.00 90.52 142.47 3,818.26 3,759.86 -9,501.65 5,889.53 6,018,291.78 539,715.89 4.00 11,121.52 12,926.00 90.78 141.46 3,817.97 3,759.57 -9,522.12 5,905.55 6,018,271.38 539,732.00 4.00 11,147.52 End Dir : 12926' MD, 3817.97' TVD 13,000.00 90.78 141.46 3,816.97 3,758.57 -9,580.00 5,951.65 6,018,213.72 539,778.36 0.00 11,221.50 13,100.00 90.78 141.46 3,815.61 3,757.21 -9,658.20 6,013.95 6,018,135.80 539,841.02 0.00 11,321.48 13,200.00 90.78 141.46 3,814.25 3,755.85 -9,736.41 6,076.26 6,018,057.89 539,903.67 0.00 11,421.46 13,300.00 90.78 141.46 3,812.90 3,754.50 -9,814.62 6,138.56 6,017,979.97 539,966.32 0.00 11,521.43 13,400.00 90.78 141.46 3,811.54 3,753.14 -9,892.83 6,200.87 6,017,902.06 540,028.97 0.00 11,621.41 13,500.00 90.78 141.46 3,810.19 3,751.79 -9,971.03 6,263.17 6,017,824.14 540,091.63 0.00 11,721.39 13,600.00 90.78 141.46 3,808.83 3,750.43 -10,049.24 6,325.47 6,017,746.23 540,154.28 0.00 11,821.37 13,700.00 90.78 141.46 3,807.48 3,749.08 -10,127.45 6,387.78 6,017,668.31 540,216.93 0.00 11,921.34 13,800.00 90.78 141.46 3,806.12 3,747.72 -10,205.66 6,450.08 6,017,590.39 540,279.58 0.00 12,021.32 13,900.00 90.78 141.46 3,804.77 3,746.37 -10,283.86 6,512.38 6,017,512.48 540,342.24 0.00 12,121.30 14,000.00 90.78 141.46 3,803.41 3,745.01 -10,362.07 6,574.69 6,017,434.56 540,404.89 0.00 12,221.28 14,100.00 90.78 141.46 3,802.05 3,743.65 -10,440.28 6,636.99 6,017,356.65 540,467.54 0.00 12,321.25 14,200.00 90.78 141.46 3,800.70 3,742.30 -10,518.49 6,699.30 6,017,278.73 540,530.19 0.00 12,421.23 14,300.00 90.78 141.46 3,799.34 3,740.94 -10,596.69 6,761.60 6,017,200.81 540,592.84 0.00 12,521.21 14,400.00 90.78 141.46 3,797.99 3,739.59 -10,674.90 6,823.90 6,017,122.90 540,655.50 0.00 12,621.18 14,500.00 90.78 141.46 3,796.63 3,738.23 -10,753.11 6,886.21 6,017,044.98 540,718.15 0.00 12,721.16 12/162019 1:59:00PM Page 6 COMPASS 5000.15 Build 91E Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-34 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Project: Milne Point MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-34 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-34 (usft) usft (usft) Design: MPU M-34 wp05 (usft) 3,736.88 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (') (usft) usft (usft) (usft) (usft) (usft) 3,736.88 14,600.00 90.78 141.46 3,795.28 3,736.88 -10,831.31 6,948.51 6,016,967.07 540,780.80 0.00 12,821.14 14,700.00 90.78 141.46 3,793.92 3,735.52 -10,909.52 7,010.82 6,016,889.15 540,843.45 0.00 12,921.12 14,800.00 90.78 141.46 3,792.56 3,734.16 -10,987.73 7,073.12 6,016,811.24 540,906.11 0.00 13,021.09 14,900.00 90.78 141.46 3,791.21 3,732.81 -11,065.94 7,135.42 6,016,733.32 540,968.76 0.00 13,121.07 15,000.00 90.78 141.46 3,789.85 3,731.45 -11,144.14 7,197.73 6,016,655.40 541,031.41 0.00 13,221.05 15,100.00 90.78 141.46 3,788.50 3,730.10 -11,222.35 7,260.03 6,016,577.49 541,094.06 0.00 13,321.03 15,200.00 90.78 141.46 3,787.14 3,728.74 -11,300.56 7,322.34 6,016,499.57 541,156.72 0.00 13,421.00 15,300.00 90.78 141.46 3,785.79 3,727.39 -11,378.77 7,384.64 6,016,421.66 541,219.37 0.00 13,520.98 15,400.00 90.78 141.46 3,784.43 3,726.03 -11,456.97 7,446.94 6,016,343.74 541,282.02 0.00 13,620.96 15,500.00 90.78 141.46 3,783.07 3,724.67 -11,535.18 7,509.25 6,016,265.82 541,344.67 0.00 13,720.94 15,600.00 90.78 141.46 3,781.72 3,723.32 -11,613.39 7,571.55 6,016,187.91 541,407.32 0.00 13,820.91 15,700.00 90.78 141.46 3,780.36 3,721.96 -11,691.60 7,633.85 6,016,109.99 541,469.98 0.00 13,920.89 15,800.00 90.78 141.46 3,779.01 3,720.61 -11,769.80 7,696.16 6,016,032.08 541,532.63 0.00 14,020.87 15,900.00 90.78 141.46 3,777.65 3,719.25 -11,848.01 7,758.46 6,015,954.16 541,595.28 0.00 14,120.84 16,000.00 90.78 141.46 3,776.30 3,717.90 -11,926.22 7,820.77 6,015,876.25 541,657.93 0.00 14,220.82 16,100.00 90.78 141.46 3,774.94 3,716.54 -12,004.43 7,883.07 6,015,798.33 541,720.59 0.00 14,320.80 16,200.00 90.78 141.46 3,773.59 3,715.19 -12,082.63 7,945.37 6,015,720.41 541,783.24 0.00 14,420.78 16,300.00 90.78 141.46 3,772.23 3,713.83 -12,160.84 8,007.68 6,015,642.50 541,845.89 0.00 14,520.75 16,400.00 90.78 141.46 3,770.87 3,712.47 -12,239.05 8,069.98 6,015,564.58 541,908.54 0.00 14,620.73 16,500.00 90.78 141.46 3,769.52 3,711.12 -12,317.25 8,132.29 6,015,486.67 541,971.20 0.00 14,720.71 16,600.00 90.78 141.46 3,768.16 3,709.76 -12,395.46 8,194.59 6,015,408.75 542,033.85 0.00 14,820.69 16,700.00 90.78 141.46 3,766.81 3,708.41 -12,473.67 8,256.89 6,015,330.83 542,096.50 0.00 14,920.66 16,800.00 90.78 141.46 3,765.45 3,707.05 -12,551.88 8,319.20 6,015,252.92 542,159.15 0.00 15,020.64 16,900.00 90.78 141.46 3,764.10 3,705.70 -12,630.08 8,381.50 6,015,175.00 542,221.80 0.00 15,120.62 17,000.00 90.78 141.46 3,762.74 3,704.34 -12,708.29 8,443.80 6,015,097.09 542,284.46 0.00 15,220.59 17,100.00 90.78 141.46 3,761.38 3,702.98 -12,786.50 8,506.11 6,015,019.17 542,347.11 0.00 15,320.57 17,200.00 90.78 141.46 3,760.03 3,701.63 -12,864.71 8,568.41 6,014,941.26 542,409.76 0.00 15,420.55 17,300.00 90.78 141.46 3,758.67 3,700.27 -12,942.91 8,630.72 6,014,863.34 542,472.41 0.00 15,520.53 17,400.00 90.78 141.46 3,757.32 3,698.92 -13,021.12 8,693.02 6,014,785.42 542,535.07 0.00 15,620.50 17,500.00 90.78 141.46 3,755.96 3,697.56 -13,099.33 8,755.32 6,014,707.51 542,597.72 0.00 15,720.48 17,600.00 90.78 141.46 3,754.61 3,696.21 -13,177.54 8,817.63 6,014,629.59 542,660.37 0.00 15,820.46 17,700.00 90.78 141.46 3,753.25 3,694.85 -13,255.74 8,879.93 6,014,551.68 542,723.02 0.00 15,920.44 ' 17,711.14 90.78 141.46 3,753.10 • 3,694.70 -13,264.45 8,886.87 6,014,543.00 542,730.00 0.00 15,931.57 Total Depth: 17711.14' MD, 3753.1' TVD 12/16/2019 1:59:00PM Page 7 COMPASS 5000.15 Build 91E HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-34 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origins Project: Milne Point MD Reference: MPU M-34 As -Staked RKB @ 58.40usft (Origina Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-34 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-34 Design: MPU M-34 wp05 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) M-34 wp04 CP1 0.00 0.00 3,818.40 -9,487.38 5,878.70 6,018,306.00 539,705.00 - plan hits target center - Point M-34 wp04 Heel 0.00 0.00 3,848.15 -4,737.19 2,318.93 6,023,039.50 536,124.04 - plan hits target center - Circle (radius 30.00) M-34 wp04 Toe 0.00 0.00 3,753.10 -13,264.45 8,886.87 6,014,543.00 542,730.00 - plan hits target center - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 6,945.80 3,848.15 9 5/8" x 12 1/4" 9-5/8 12-1/4 17,711.14 3,753.10 41/2"x81/2" 4-1/2 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 5,539.54 3,371.40 UGNU MB 1,419.72 1,306.40 SV5 2,504.46 1,882.40 SV1 2,427.00 1,844.40 BPRF 6,991.26 3,851.40 SB_OB (heel) 4,997.34 3,105.40 LA3 6,000.21 3,597.40 SB NA Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 250.00 250.00 0.00 0.00 Start Dir 30/100' : 250' MD, 250'TVD 400.00 399.85 -5.80 1.02 Start Dir 4°/100' : 400' MD, 399.85'TVD 1,811.65 1,542.51 -682.62 272.06 End Dir : 1811.65' MD, 1542.51'TVD 6,070.82 3,632.04 -4,037.09 1,860.13 Start Dir 41/100': 6070.82' MD, 3632.04'TVD 6,745.80 3,830.72 -4,579.33 2,197.36 End Dir : 6745.8' MD, 3830.72' TVD 6,945.80 3,848.15 -4,737.19 2,318.93 Start Dir 4'/100': 6945.8' MD, 3848.15'TVD 7,080.84 3,853.63 -4,844.60 2,400.51 End Dir : 7080.84' MD, 3853.63' TVD 10,850.00 3,830.74 -7,861.08 4,660.34 Fault 12,882.09 3,818.40 -9,487.38 5,878.70 Start Dir 4°/100' : 12882.09' MD, 3818.4'TVD 12,926.00 3,817.97 -9,522.12 5,905.55 End Dir : 12926' MD, 3817.97' TVD 17,711.14 3,753.10 -13,264.45 8,886.87 Total Depth : 17711.14' MD, 3753.1' TVD 12/16/2019 1:59:OOPM Page 8 COMPASS 5000.15 Build 91E Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-34 MPU M-34 MPU M-34 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 16 December, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 Well Coordinates: 6,027,765.64 N, 533,783.85 E (70° 29' 12.78" N, 149° 43' 25.94" W) Datum Height: MPU M-34 As -Staked RKB @ 58.40usft (Original Well Elev) Scan Range: 33.70 to 6,945.80 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Type: • • = Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 Scan Range: 33.70 to 6,945.80 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M Pt L Pad MPL-36 - MPL-36 - MPL-36 6,580.10 835.01 6,580.10 748.18 14,204.08 9.616 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 6,658.70 840.45 6,658.70 743.15 14,214.61 8.637 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 6,945.80 935.73 6,945.80 794.78 14,239.59 6.638 Clearance Factor Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,580.10 835.01 6,580.10 747.17 14,204.08 9.506 Centre Distance Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,683.70 844.44 6,683.70 741.03 14,217.47 8.166 Ellipse Separation Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,945.80 935.73 6,945.80 789.30 14,239.59 6.390 Clearance Factor Pass - MPL-36 - MPL-361-1 PBI - MPL-361-1 PB1 6,580.10 835.01 6,580.10 746.40 14,204.08 9.423 Centre Distance Pass - MPL-36 - MPL-361-1 PBI - MPL-361-1 PBI 6,683.70 844.44 6,683.70 739.25 14,217.47 8.027 Ellipse Separation Pass - MPL-36 - MPL-361-1 P81 - MPL-36L1 PBI 6,945.80 935.73 6,945.80 785.23 14,239.59 6.217 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,580.10 835.01 6,580.10 748.19 14,204.08 9.617 Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,658.70 840.45 6,658.70 743.16 14,214.61 8.638 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,945.80 935.73 6,945.80 794.80 14,239.59 6.640 Clearance Factor Pass - MPtMPad M-01 - M-01 - M-01 6,426.16 476.41 6,426.16 330.40 4,383.20 3.263 Centre Distance Pass - M-01 - M-01 - M-01 6,558.70 482.95 6,558.70 322.70 4,490.42 3.014 Ellipse Separation Pass - M-01 - M-01 - M-01 6,683.70 502.67 6,683.70 331.23 4,586.50 2.932 Clearance Factor Pass - M-01 - M -01A- M -01A 5,365.61 738.76 5,365.61 668.45 3,254.25 10.507 Centre Distance Pass - M-01 - M -01A- M -01A 5,508.70 742.54 5,508.70 664.56 3,364.29 9.522 Ellipse Separation Pass - M-01 - M -01A- M -01A 6,908.70 1,022.99 6,908.70 822.45 4,500.00 5.101 Clearance Factor Pass - M Pt Moose Pad MPU M-12 - MPU M-12 - MPU M-12 270.74 194.03 270.74 191.40 272.65 73.672 Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12 283.70 194.05 283.70 191.32 285.58 70.945 Ellipse Separation Pass - MPU M-12 - MPU M-12 - MPU M-12 658.70 239.26 658.70 233.68 623.51 42.856 Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 270.74 194.03 270.74 191.40 272.65 73.672 Centre Distance Pass - 16 December, 2019 - 14:04 Page 2 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 686.10 208.49 686.10 203.83 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 44.751 Centre Distance Pass - MPU M-13 - MPU M -13i - MPU M-13 708.70 208.57 Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 Wp05 203.80 698.41 43.687 Ellipse Separation Pass - MPU M-13 - MPU M -13i - MPU M-13 Scan Range: 33.70 to 6,945.80 usft. Measured Depth. 440.46 1,583.70 426.39 1,452.47 31.294 Clearance Factor Scan Radius Is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft MPU M-14 - MPU M-14 - MPU M-14 33.70 119.96 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on MPU M-14 - MPU M-14 - MPU M-14 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 1,458.70 209.82 MPU M-12 - MPU M-12PB1 - MPU M-12PB1 283.70 194.05 283.70 191.32 285.58 70.945 Ellipse Separation Pass - MPU M-12- MPU M-12PB1 - MPU M-12PB1 658.70 239.26 658.70 233.68 623.51 42.856 Clearance Factor Pass - MPU M -12 -MPU M-12PB2-MPU M-12PB2 270.74 194.03 270.74 191.40 272.65 73.672 Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 283.70 194.05 283.70 191.32 285.58 70.945 Ellipse Separation Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 658.70 239.26 658.70 233.68 623.51 42.856 Clearance Factor Pass - MPU M-13 - MPU M-131 - MPU M-13 686.10 208.49 686.10 203.83 677.40 44.751 Centre Distance Pass - MPU M-13 - MPU M -13i - MPU M-13 708.70 208.57 708.70 203.80 698.41 43.687 Ellipse Separation Pass - MPU M-13 - MPU M -13i - MPU M-13 1,583.70 440.46 1,583.70 426.39 1,452.47 31.294 Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14 33.70 119.96 33.70 119.05 34.07 131.558 Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14 158.70 120.30 158.70 118.79 158.40 79.938 Ellipse Separation Pass - MPUM-I4- MPU M -I4- MPU M-14 1,458.70 223.62 1,458.70 209.82 1,422.24 16.202 Clearance Factor Pass - MPU M-1 5i - MPU M-15 - MPU M-1 5i 441.62 27.08 441.62 23.74 441.67 8.125 Centre Distance Pass - MPU M-151- MPU M-15 - MPU M -15i 458.70 27.11 458.70 23.67 458.65 7.884 Ellipse Separation Pass - MPU M -15i - MPU M-15 - MPU M -1 5i5,958.70 939.36 5,958.70 805.26 6,119.54 7.005 Clearance Factor Pass - MPU M -15i - MPU M -15P81 - MPU M-15PB1 441.62 27.08 441.62 23.74 441.67 8.125 Centre Distance Pass - MPU M -15i - MPU M-15PB1 - MPU M-15PB1 458.70 27.11 458.70 23.67 458.65 7.884 Ellipse Separation Pass - MPU M -1 5i- MPU M-15PB1 - MPU M-15PB1 5,958.70 939.36 5,958.70 805.03 6,119.54 6.993 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 33.70 59.76 33.70 58.84 34.18 65.533 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 58.70 59.80 58.70 58.78 59.17 58.484 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 6,258.70 219.99 6,258.70 76.17 6,402.35 1.530 Clearance Factor Pass - MPU M -17i - MPU M-1 7i - MPU M-171 33.70 149.99 33.70 149.08 34.00 164.494 Centre Distance Pass - MPU M -17i - MPU M -17i - MPU M -17i 283.70 150.47 283.70 148.24 283.70 67.506 Ellipse Separation Pass - MPU M -17i - MPU M -17i - MPU MAT 6,945.80 401.42 6,945.80 233.42 7,297.39 2.389 Clearance Factor Pass - MPU M -I8- MPU M-18- MPU M-18 33.70 180.00 33.70 179.09 34.42 197.397 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 108.70 180.19 108.70 178.94 108.52 145.153 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 4,658.70 703.12 4,658.70 593.73 4,773.76 6.427 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 33.70 180.00 33.70 179.09 34.42 197.397 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-1813131 108.70 180.19 108.70 178.94 108.52 145.153 Ellipse Separation Pass - MPU M -I8- MPU M-18PB1- MPU M-18PB1 4,658.70 703.12 4,658.70 593.71 4,773.76 6.426 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 33.70 180.00 33.70 179.09 34.42 197.397 Centre Distance Pass - 16 December, 2019 - 14:04 Page 3 of 8 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 Scan Range: 33.70 to 6,945.80 usft. Measured Depth.✓� Scan Radius is Unlimited-"GTearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPU M-18 - MPU M-18PB2 - MPU M-18PB2 108.70 180.19 108.70 178.94 108.52 145.153 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 4,658.70 703.12 4,658.70 593.72 4,773.76 6.427 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 258.70 137.43 258.70 135.45 259.62 69.532 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 6,058.70 853.12 6,058.70 714.19 9,243.45 6.140 Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PS1 258.70 137.43 258.70 135.45 259.62 69.532 Ellipse Separation Pass - MPU M-20- MPU M-20PB1 - MPU M-20PB1 6,058.70 853.12 6,058.70 714.19 9,243.45 6.141 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 258.70 137.43 258.70 135.45 259.62 69.532 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 6,056.70 853.12 6,058.70 714.19 9,243.45 6.140 Clearance Factor Pass - MPU M -21i - MPU M -21i - MPU M-21 i 33.70 127.72 33.70 126.31 34.17 90.478 Centre Distance Pass - MPU M-21 i - M PU M-21 i - MPU M-21 i 258.70 127.94 258.70 125.73 259.05 57.737 Ellipse Separation Pass - MPU M-21 i - M PU M-21 i - MPU M-21 i 5,633.70 1,497.86 5,633.70 1,360.23 6,065.00 12.734 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 33.70 172.64 33.70 171.73 33.95 189.330 Centre Distance Pass - MPU M-22 - MPU M-22 - MPU M-22 258.70 173.06 258.70 171.06 258.35 86.484 Ellipse Separation Pass - MPU M-22 - MPU M-22 - MPU M-22 583.70 218.71 583.70 214.65 555.28 53.953 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 33.70 172.64 33.70 171.73 33.95 189.330 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 258.70 173.06 258.70 171.06 258.35 86.484 Ellipse Separation Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 583.70 218.71 583.70 214.65 555.28 53.954 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup St - Kup S1 w 233.70 239.87 233.70 237.56 234.00 103.841 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w 308.70 240.04 306.70 237.30 308.99 87.635 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Kup S1 - Kup S1 w 1,583.70 592.53 1,583.70 579.98 1,565.76 47.207 Clearance Factor Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,377.66 293.75 1,377.86 283.59 1,603.91 28.907 Centre Distance Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,383.70 293.77 1,383.70 283.53 1,609.84 28.696 Ellipse Separation Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,808.70 420.74 1,808.70 400.38 1,967.67 20.664 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 233.70 153.61 233.70 150.86 234.00 55.811 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 258.70 153.63 258.70 150.73 259.00 53.096 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 5,808.70 807.08 5,808.70 665.03 8,371.69 5.682 Clearance Factor Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 233.70 138.03 233.70 135.27 234.00 50.102 Centre Distance Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 258.70 138.05 258.70 135.15 259.00 47.667 Ellipse Separation Pass - Plan: MPU M -21i P2 - M -21i Phase 2 - M-211 P2 wp02 4,708.70 1,498.87 4,708.70 1,407.20 7,155.42 16.351 Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02 611.08 265.71 611.08 261.15 578.73 58.258 Ellipse Separation Pass - 16 December, 2019 - 14:04 Page 4 of 8 COMPASS Hileorp Alaska, LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 233.70 127.64 233.70 125.02 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 48.745 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 258.70 127.66 Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 259.10 45.507 Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 608.70 Scan Range: 33.70 to 6,945.80 usft. Measured Depth. 608.70 155.92 606.39 29.165 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 233.70 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 150.92 234.00 66.014 Centre Distance Pass - Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 62.240 Ellipse Separation Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 2,195.58 5.876 Centre Distance Plan: MPU M-27 - M-27 - M-27 wp02 3,058.70 1,497.26 3,058.70 1,455.14 2,333.51 35.548 Clearance Factor Pass - Plan: MPU M -35i - MPU M -35i - MPU M -35i wp04 672.31 87.70 672.31 83.62 667.52 21.502 Centre Distance Pass - Plan: MPU M-351 - MPU M -35i - MPU M -35i wp04 683.70 87.72 683.70 83.59 678.62 21.254 Ellipse Separation Pass - Plan MPU M -35i - MPU M -35i - MPU M -35i wp04 6,945.80 705.21 6,945.80 522.29 7,018.39 3.855 Clearance Factor Pass - Plan MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 233.70 297.43 233.70 295.46 234.00 151.380 Centre Distance Pass - Plan MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 283.70 297.51 283.70 295.28 283.55 133.630 Ellipse Separation Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 1,083.70 508.07 1,083.70 501.91 900.00 82.532 Clearance Factor Pass - Plan MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 233.70 381.05 233.70 379.09 234.00 194.150 Centre Distance Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 283.70 381.10 283.70 378.88 283.48 171.376 Ellipse Separation Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M-441 H 6,945.80 714.75 6,945.80 558.84 10,548.43 4.584 Clearance Factor Pass - Plan: MPU M-48 - Slot 24 - MPU M-48 - MPU M-48 wp 233.70 194.75 233.70 192.43 234.00 84.074 Centre Distance Pass - Plan: MPU M-48 - Slot 24 - MPU M-48 - MPU M-48 wp 258.70 194.77 258.70 192.31 259.00 79.263 Ellipse Separation Pass - Plan: MPU M-48 - Slot 24 - MPU M-48 - MPU M-48 wp 608.70 235.17 608.70 230.58 586.39 51.313 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 233.70 127.64 233.70 125.02 234.10 48.745 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 258.70 127.66 258.70 124.85 259.10 45.507 Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 608.70 161.46 608.70 155.92 606.39 29.165 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 233.70 153.24 233.70 150.92 234.00 66.014 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 258.70 153.26 258.70 150.80 259.00 62.240 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! 608.70 188.31 608.70 183.71 606.29 40.903 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,010.80 71.96 2,010.80 59.71 2,195.58 5.876 Centre Distance Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,133.70 77.82 2,133.70 58.33 2,314.86 3.992 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,383.70 115.16 2,383.70 75.78 2,557.49 2.924 Clearance Factor Pass - Proposal: NI Kuparuk - Slot 34 - MPU M -N1 - Kup N1 233.70 124.37 233.70 122.20 234.00 57.355 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 258.70 124.39 258.70 122.07 259.00 53.514 Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 508.70 154.97 508.70 151.07 491.56 39.727 Clearance Factor Pass - Rig: MPU M -19i - MPU M -19i - MPU M -19i wp09 233.70 270.06 233.70 267.75 234.10 116.892 Centre Distance Pass - Rig: MPU M -19i - MPU M -19i - MPU M -19i wp09 458.70 270.37 458.70 266.72 465.22 74.013 Ellipse Separation Pass - Rig: MPU M -19i - MPU M -19i - MPU M -19i wp09 4,208.70 937.83 4,208.70 847.07 4,180.64 10.333 Clearance Factor Pass - Rig: MPU M -23i - MPU M -23i - MPU M -23i 258.70 21721 258.70 215.01 259.40 99.011 Ellipse Separation Pass - Rig: MPU M -23i - MPU M -23i - MPU M -23i 608.70 267.22 608.70 262.98 572.30 63.089 Clearance Factor Pass - 16 December, 2019 - 14:04 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Clearance Summary Based on Depth Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 Wp05 234.20 Scan Range: 33.70 to 6,945.80 usft. Measured Depth. 259.20 88.997 Ellipse Separation 573.05 58.748 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 74.253 Ellipse Separation Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) Rig: MPU M-231 - MPU M -23i - MPU M-23 wp06 233.70 218.60 233.70 216.28 Rig: MPU M -23i - MPU M -23i - MPU M-23 wp06 258.70 218.61 258.70 216.16 Rig: MPU M -23i - MPU M -23i - MPU M-23 wp06 608.70 267.84 608.70 263.28 Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 233.70 171.97 233.70 169.81 Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 258.70 171.98 258.70 169.67 Slot 42 - Placeholder - Slot 42 - Placeholder - Slat 42 - 708.70 210.59 708.70 205.50 Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 744.07 231.29 744.07 225.99 Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 758.70 231.33 758.70 225.96 Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 1,058.70 263.52 1,058.70 256.05 M Pt N Pad Milne Point Exploration From To Survey/Plan (usft) (usft) 33.70 650.00 MPU M-34 wp05 650.00 6,945.80 MPU M-34 wp05 6,945.80 17,711.14 MPU M-34wp05 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor= Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. @Measured Clearance Summary Based on Depth Factor Minimum usft 234.20 94.400 Centre Distance 259.20 88.997 Ellipse Separation 573.05 58.748 Clearance Factor 196.30 79.594 Centre Distance 221.30 74.253 Ellipse Separation 665.26 41.368 Clearance Factor Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass- Pass- Pass- Pass - 698.99 43.690 Centre Distance Pass - 712.86 43.101 Ellipse Separation Pass - 984.75 35.294 Clearance Factor Pass - Survey Tool 3_Gyro-GC _Csg 3 MWD+IFR2+MS+Sag 3_M WD+I FR2+MS+Sag 16 December, 2019 - 14:04 Page 6 of 8 COMPASS REFERENCE INFORMATION WELL DErAILSTIan: MPUM-34 NAD1927 ADCONCONUS Alaska Zone 04 1-IALLIBtJRTON Project: Milne Point N Site: M Pt Moose Pad Co-ortlinate ) ReMrenca: Well Plan: MPU M -3d, Trva NarN Well: Plan: MPU -34 Vertical (TVD) R-- MPU M-34A5-Smkad RKB a956.4a,5ft (Original Wall EI-) 24.70 M Spnrry Grilling Maezurod DepiM1 Reference: MPU M-34 As -Staked RKB @ 58.40usa (Original Wali Elev) +N/-3 +&-W Northlag FncM1 9 ]atitNde LongiWde Wellbore: MPU W34 cakulation Method: Minimum Curvatura 0.00 0.00 Plan: MPU M-34 WPO5 6027765.64 533783.85 70°29'12785N 149°43'25.944W SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering criteria Data:2019-12-i6T00:0000 Wid,ed Yea Val,ma: 33.70 To 17711.14 DePM From DBPN To SurveylPlen Tool CA$1NG DETAILS 33 70 650.00 MPU M-34 os (MPU M-34) 3 Gyro-GC_Csg Ladder/S.F. Plots 65000 6945.80 MPU M-34v.P05(MPU M-34) 3_MWD-IFR2*MS4Sag E945.80 17711.14 MPU M-3 ,05(MPU M-34) 3_MWD.IFR2aMS+Sag TVD TVD$$ MD $IZC NRma Of 2 3848.15 3789.75 6945.80 9-5/8 9 5/8" r 12 1/4" 3753.10 3694.70 17711.14 4-1/2 4 1/2" s 8 1/2" 80.00 180.00- X150.00 X150.00- I 0 0 o - M -08D W wp02 - McLaws co120.00 -- _ C MP M-14 / t Al� .I E2 MP M35i wpOjt iA , it n 90.00 .. aa) 60.00--'- '�_._ U MP M-16 d MP M-151 c 30.00 I 0.00 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) 4.00 0O 3.00 t c II j Collision Risk Procedures q. 162.00- .00 Collision Collision Avoidance Req. No -Go Zone - Stop Drilling j 1.00 - I NOERRORS I I I 0.00 I 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-34 MPU M-34 MPU W34 wp05 Sperry Drilling Services Clearance Summary N C f1-1) Anticollision Report 4112_� 16 December, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 Well Coordinates: 6,027,765.64 N, 533,783.85 E (70° 29' 12.78" N, 149° 43' 25.94" W) Datum Height: MPU M-34 As -Staked RKB @ 58.40usft (Original Well Elev) Scan Range: 6,945.80 to 17,711.14 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Type: Scan Type: 25.00 M0 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 Wp05 Scan Range: 6,945.80 to 17,711.14 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23A- MPJ -23A M PJ -23 - M PJ -23A - M PJ -23A MPJ -23 - MPJ -23A - MPJ -23A MPJ -23 - MPJ -231-1 - MPJ -231-1 MPJ -23 - MPJ -231-1 - MPJ -231-1 MPJ -23 - MPJ -231-1 - MPJ -231-1 MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPU J-24 - MPJ -24 MPJ -24 - MPU J-24 - MPJ -24 MPJ -24 - MPU J-24 - MPJ -24 MPJ -27 - MPJ -27 - MPJ -27 MPJ -27 - MPJ -27 - MPJ -27 MPJ -27 - MPJ -27 - MPJ -27 MPJ -28 - MPJ -28 - MPJ -28 MPJ -28 - MPJ -28 - MPJ -28 MPJ -28 - MPJ -28 - MPJ -28 M Pt L Pad MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-361-1 - MPL-361-1 MPL-36 - MPL-361-1 - MPL-361-1 MPL-36-MPL-361-1 PB1 -MPL-361-1 PB1 16,458.69 199.48 16,458.69 96.62 11,719.43 1.939 Centre Distance Pass - 13,779.00 534.86 13,779.00 79.64 13,402.00 1.175 Centre Distance Pass - 13,870.80 542.68 13,870.80 61.42 13,402.00 1.128 Ellipse Separation Pass - 13,895.80 547.46 13,895.80 61.55 13,402.00 1.127 Clearance Factor Pass - 14,954.45 1,406.49 14,954.45 780.02 11,975.00 2.245 Centre Distance Pass - 15,170.80 1,423.03 15,170.80 754.33 11,975.00 2.128 Ellipse Separation Pass - 15,295.80 1,447.32 15,295.80 .761.60 11,975.00 2.111 Clearance Factor Pass - 15,019.58 214.24 15,019.58 126.58 12,994.30 2.444 Centre Distance Pass - 15,220.80 271.28 15,220.80 44.02 12,880.09 1.194 Ellipse Separation Pass - 15,245.80 284.38 15,245.80 45.78 12,865.84 1.192 Clearance Factor Pass - 17,620.80 274.46 17,620.80 46.12 11,136.67 1.202 Clearance Factor Pass - 17,645.80 261.37 17,645.80 45.59 11,120.61 1.211 Ellipse Separation Pass - 17,711.14 231.27 17,711.14 56.37 11,078.54 1.322 Centre Distance Pass - 6,945.80 935.73 6,945.80 794.78 14,239.59 6.638 Ellipse Separation Pass - 7,095.80 1,021.58 7,095.80 863.26 14,250.85 6.453 Clearance Factor Pass - 6,945.80 935.73 6,945.80 789.30 14,239.59 6.390 Ellipse Separation Pass - 7,095.80 1,021.58 7,095.80 856.53 14,250.85 6.190 Clearance Factor Pass - 6,945.80 935.73 6,945.80 785.23 14,239.59 6.217 Ellipse Separation Pass - 16 December, 2019 - 14:07 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 Scan Range: 6,945.80 to 17,711.14 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPL-36-MPL-36L1PB1-MPL-36L1PBI 7,120.80 1,038.10 7,120.80 865.31 14,252.70 6.008 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,945.80 935.73 6,945.80 794.80 14,239.59 6.640 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 7,095.80 1,021.58 7,095.80 863.29 14,250.85 6.454 Clearance Factor Pass - M Pt M Pad 6,945.80 1,356.27 6,945.80 1,201.19 9,821.11 8.745 Clearance Factor Pass - M-01 - M-01 - M-01 6,945.80 588.55 6,945.80 405.57 4,772.81 3.217 Clearance Factor Pass - M-01 - M -01A- M -01A 6,945.80 1,037.36 6,945.80 834.61 4,515.02 5.116 Clearance Factor Pass - M Pt Moose Pad 17,520.80 783.77 17,520.80 252.93 17,587.05 1.476 Clearance Factor Pass - MPU M -15i - MPU M-15 - MPU M-151 6,945.80 1,247.50 6,945.80 1,088.62 6,940.80 7.851 Clearance Factor Pass - MPU M-1 5i - M PU M-1 5PB1 - MPU M-1 5PB1 6,945.80 1,260.38 6,945.80 1,101.01 6,906.12 7.908 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 6,945.80 439.88 6,945.80 272.27 7,019.76 2.625 Clearance Factor Pass - MPU M -17i - MPU M -17i - MPU M -17i ® - MPU MAT - MPU M -17i - MPU M -17i ® - ■ MPU MAT - MPU M -17i - MPU M -17i 8,303.43 7427 8,303.43 23.92 8,583.94 1.475 Centre Distance Pass - MPU M -18 -MPU M -18 -MPU M-18 ® a - MPU M -I8- MPU M -I8- MPU M-18 ®� - ■ MPU M -I8- MPU M -I8- MPU M-18 10,896.21 96.75 10,896.21 35.15 11,405,16 1.571 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,903.50 329.01 9,903.50 78.21 10,361.00 1.312 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,920.80 329.46 9,920.80 77.48 10,361.00 1207 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18- MPU M-18PB2 - MPU M-18PB2 10,842.90 99.24 10,842.90 31,56 11,349.30 1.466 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 6,945.80 1,356.27 6,945.80 1,201.19 9,821.11 8.746 Clearance Factor Pass - MPU M-20- MPU M-20PB1 - MPU M-20PB1 6,945.80 1,356.27 6,945.80 1,201.20 9,821.11 8.746 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 6,945.80 1,356.27 6,945.80 1,201.19 9,821.11 8.745 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 6,945.80 1,387.58 6,945.80 1,214.44 9,239.84 8.014 Clearance Factor Pass - Plan: MPU M -35i - MPU M -35i - MPU M -35i wp04 6,945.80 705.21 6,945.80 522.29 7,018.39 3.855 Centre Distance Pass - Plan: MPU M -35i - MPU M -35i - MPU M -35i wp04 17,520.80 783.77 17,520.80 252.93 17,587.05 1.476 Clearance Factor Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wF 9,170.80 234.76 9,170.80 98.96 12,864.02 1.729 Clearance Factor Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 9,220.80 215.89 9,220.80 94.38 12,901.73 1.777 Ellipse Separation Pass - 16 December, 2019 - 14:07 Page 3 of 7 COMPASS • N OA HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 To Survey/Plan Survey Tool (usft) (usft) Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 33.70 650.00 MPU M-34wp05 3_Gyro-GC_Csg 650.00 6,945.80 MPU M-34wp05 Reference Design: M Pt Moose Pad - Plan: MPU M-34 - MPU M-34 - MPU M-34 wp05 3_MWD+IFR2+MS+Sag Scan Range: 6,945.80 to 17,711.14 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 9,392.97 183.92 9,392.97 121.69 13,031.57 2.956 Centre Distance Pass - Plan: MPU MA4i - Slot 58 - MPU M -44i - MPU M44i H 7,745.80 252.58 7,745.80 129.80 11,149.94 2.057 Clearance Factor Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 7,845.80 216.12 7,845.80 119.04 11,225.23 2.226 Ellipse Separation Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 7,993.11 193.16 7,993.11 139.45 11,336.15 3.596 Centre Distance Pass - Rig: MPU M -19i - MPU M -19i - MPU M-191 wp09 - Rig: MPU M -19i - MPU M -19i - MPU M -19i wp09 - Rig: MPU M -19i - MPU M -19i - MPU M -19i wp09 - M Pt N Pad MPN-0I-MPN-0I-MPN-01 17,711.14 756.51 17,711.14 469.07 3,749.30 2.632 Clearance Factor Pass - MPN-01 - MPN-01A - MPN-01A 17,711.14 714.76 17,711.14 461.78 3,750.60 2.825 Clearance Factor Pass - MPN-01 - MPN-01 B - MPN-01 B 17,711.14 344.63 17,711.14 99.36 4,028.73 1.405 Clearance Factor Pass - Milne Point Exploration MPU-Liviano-01 - Liviano-01 - Liviano-01 9,163.89 817.65 9,163.89 681.79 4,131.84 6.018 Centre Distance Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 9,170.80 817.68 9,170.80 681.72 4,130.25 6.014 Ellipse Separation Pass - MPU-Liviano-0l-Liviano-0l-Liviano-01 9,195.80 818.24 9,195.80 682.03 4,124.50 6.007 Clearance Factor Pass - MPU-Liviano-01 - Liviano-01A- Liviano-01A 9,324.98 944.87 9,324.98 813.02 4,031.79 7.166 Clearance Factor Pass - Survey tooly program From To Survey/Plan Survey Tool (usft) (usft) 33.70 650.00 MPU M-34wp05 3_Gyro-GC_Csg 650.00 6,945.80 MPU M-34wp05 3 MWD+IFR2+MS+Sag 6,945.80 17,711.14 MPU M-34 wp05 3_MWD+IFR2+MS+Sag 16 December, 2019 - 14:07 Page 4 of 7 COMPASS &A S.A-m'3) HALLIBURTON Anticollision Report for Plan: MPU M-34 - MPU M-34 wp05 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point 16 December, 2019 - 14:07 Page 5 of 7 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DEWS:PI—MPUM-34 NAD1927(NADCONCONUS) Alk.Z04 04 Site: M Pt Moose Pad Ca -ordinate (NIE) Rereran Wall Plan: MPU M-34, T,e NOM Si 13'H,I .g Wellbore: Well: Plan: MPU M-34 Var —i (ND) Ralaran— MPU M-34M-Srakad RKB � 51(Onginal Well 1o MPU M-34 Measured Depth IMPU M -34M -81I RKB 51(Onginal Well Ela,) Cakula Mathod: MiI Curvatura +N/ -S +F/ -W 0.00 0.00 24 70 NrI Fasting latittude LOngiWd¢ Plan: MPU M-34 wpO5 6027765.64 533763.95 70° 29'12,785 N 149° 43'25.944 W SURVEY PROGRAM oat.: 2019-12-t6Toa:ao:00 --d Yea -w, NO GLOBAL FILTER: Using user defined selection 8 fiHering criteria 33.70 To 17711.14 Ladder/S.F. Depth Fra, Depth To Surve11I Tool 33.]0 650.00 MPU M -3a wp05 (MPU Mao) 3_Gyro-GC Czg Plots CASING DETAILS 650.00 6945.80 MPU M-34 Mks (MPU Mao) 3_MWD+IFR2�MS�Sag 6945.80 1T111.14 MPU M -341w05 (MPU M-34) 3_1-1 R—S—I, TVD TVD$$ Nm $IZ¢ Nam¢ 2 Of 2 3848.15 3789.75 6945.80 9-5/8 9 5/8" x 12 1/4" 3Ij753,10 3694,70 17711.14( 4-1/2 41/2"r81/2" MPU M-18PB )' .,.,,.., �I T_ 1II1( 11 TT (VIII =180.00 150.00 VIII)_-IIII 'lI I III 1111 IIII V IIII MPU M-18 II II !f I(11'MPU M-17 =012000II �._IIIIIIiI +1 illi III C 0 (I I UM -191 II I 1 II I II I I III 0.00 1I `m 90,00— _III IIII, I II I i 11 l V) m 60.90 l I II o X11 I ;II 30.00 C) I 0.00 I I I I IL' I 10 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000 1860 Measured Depth (1200 usft/in) 4.00 I I I 0 .00 v 3.00— I I i U_ U_ 1 _ Collision Risk Procedures Req.j E 2.00 - CL Collision Avoidance Req. No -Go Zone - Stop Drilling 1.00 I NOERRORS 0.00 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000 18600 Measured Depth (1200 usft/in) Schwartz, Guy L (CED) From: Joseph Engel <jengel@hilcorp.com> Sent: Monday, December 30, 2019 10:07 PM To: Schwartz, Guy L (CED) Cc: Davies, Stephen F (CED); Monty Myers Subject: RE: [EXTERNAL] M-34 anti collision (PTD 219-193) Guy - Correct, all the current moose pad wells are in the OA. The status of J-23 is as below: J-23 and J-231-1 have been abandoned. J-23 is the only well on the AC list that is a lateral in the same sand (OBa) as M- 34. J -23A is a lateral injector in the NB sand -220' TVD above M-34. As J-23 is abandoned, the only risk we have is mechanical damage to the bit. We will monitor MWD for magnetic interference while drilling near those depths. Please let me know if you have any other questions. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Monday, December 30, 2019 3:44 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] M-34 anti collision (PTD 219-193) Joe, Can you elaborate on the failures on the anti -collision. The existing M -pad wells are drilled in the OA sand so not a big issue as you will be drilled in zone OB right over them . What is the status of J-23 and what will you do to minimize risk? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.gov). TRANSMITTAL LETTER CHECKLIST WELL NAME: 1 / Pl4 PTD: 2- 1 � 143 Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD:,%G,� � �., / 1 GL,�= /" 1r?% r rc POOL: ' 4_- I cmc L Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit (If last two digits in API number API No. 50 - Production should continue to be reported as a functionthe original are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in Pilot Hole both well name ( PH) and API number (50-____7 _) from records, data and logs acquired for well name on ermit . The permit is approved subject to full compliance with 20 AAC 25.055. Spacing Exception Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. `Company Name) 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 sam les are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non -Conventional production or production testing of coal bed methane is not allowed for (name of welly until Well after (Com My Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. Com any Name) must contact the AOGCC to obtain advance approval of such water well testing program. 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 (Companv Name) in the attached application, the following well logs are also for required this well: Well Logging Requirements 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 da s after completion- su erasion or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 PTD#:2191930 Company Hilcorp Alaska LLC Initial Class/Type Well Name: MILNE PT UNIT M-34 Program DEV Well bore seg ❑ DEV/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit_ fee attached- - - - - - - - - - - - - - - - - - - -- - - - - - - - - -- - - No Commissioner: Date WrDateC 2 Lease number appropriate- - - - - - - - - - - - - - - Yes - - - - Surf_ Loc &_Top Prod Int lie in ADL0025514; Portion -of Productive Interval -lies in ADL002551.5; - - - - 3 Unique well name and number - - - - - - - - - - - - - - - - ---------------- Yes - - - - - - - TD lies in ADL0025-17------------------------- _ 4 Well located in a_defined pool -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - _ Milne Point Schrader Bluff_ Oil Pool (525140), governed by -CO 477, amended by CO 477_.05. - - - - - 5 Well located proper distance from drilling unit -boundary -_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes . - - - - CO 477.05 specifies:_ "There are no restrictions as to well spacing except that no pay shall- - - - - - . - - - - - 6 Well located proper distance from other wells_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - . . - - - be opened -in a well closer than 500 feet from the exterior boundary of the affected area. 7 Sufficient acreage available in -drilling unit_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - _ As planned, well conforms to spacing requirements. 8 If_deviated,is_we_llboreNat-included ___________________________________ Yes_--____________________ ------------------------------------- 9 Operator only affected party- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -Yes - - _ - - - - _ ---------------------------------------------------- 10 Operator has -appropriate bond in force - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Corrected bond number on form._ _ _ _ - _ _ - _ _ _ _ - - - - - - - - - - - - - - - - - _ - _ - - - - - 11 Permit_can be issued without conservation order- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - _ - _ _ - - - .. - .. - .. - - - - - - Appr Date 12 Permit_ can be issued without administrative_approval- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - -- - - - - - - - - - -- - - - - - - - - - - - 13 Can permit be approved before 15 -day wait_ Yes 12/20/2019 _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - 14 Well located within area and -strata authorized by Injection Order # (put_l0# in_comments)_(For_ -NA- _ _ - - - - - - - - - - - - - 15 All wells -within -1/4 -mite -area -of review identified (For service well only) - - - - - - - - - - - - - - NA_ - - - - - - - - - - - - - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ - - - - - - - 16 Pre -produced injector; duration of pre production Less than 3 months_ (For service well only) NA_ _ _ _ _ _ _ _ _ _ . 17 Nonconven. gas conforms to AS31,05.030([.1.A),0,2.A-D) - - - - - - - - - - - NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 18 Conductor string -provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - 20" conductor set at 113 ft. - _ _ - _ _ - - _ - - _ _ _ - Engineering 19 Surface casing_ protects all known_ USDWs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - _ - - _ _ _--------------------- - - - - - - - _ - - - _ _ - - - - 20 CMT_vol_adequate_ to circulate_on conductor_& surf_csg - - _ _ _ _ _ _ - _ Yes - - - - - - - 9 5/6" casing will be cemented in two stages, ES tool at 2500 ft-- - - - - - - - - - - - - - - 21 CMT_vol _adequate_to tie-in long string to surf csg------------------ - - - - NA_ - - - - - - _ - _ - _ _ - _ _ - - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - - _ - _ _ 22 -C-MT-will coverall known -productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Lateral will _be cased with uncemented slotted liner (6.5/8" OD) - _ _ _ _ - 23 Casing designs adequate for C, T, B &_ permafrost _ - _ - - - Yes - - - - - - - BTC callcul_ation_are provided_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 24 Adequate tankage_or reserve pit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - Rig has steel pits. - _ _ - - - - - - - _ _ - - - - - - - - - - - - _ - - - - _ - - - - - - - - - 25 If a_re-drill, has -a. 10-403 for abandonment been approved NA_ - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - 26 Adequate wellbore separation proposed - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes- - Close_crossing with M-17 II -18. Drilled -in OA Sandys OB_. -t -2a is ---------- - - - 27 27 If_diverter required, does it meet regulations_ _ - _ _ - - - - - Yes - - - - - - - Diverter layout is provided. _ _ _ _ _ _ _ - ---------------------------------------- Appr Date 28 Drilling fluid_ program schematic -&- equip -list-adequate _ - _ - - - - - - - - - Yes - - - - - - - Max form_ pressure =_1694 psi (8,6_ ppg EM -W) will drill with 8,9 4.5 ppg mud - Using_MPD too.- _ _ GLS 12/30/2019 29 BOPEs,-do they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Doyon 14 has_13 5/8" BOPE 5000 -psi -WP - _ _ - _ _ - _ _ - _ - - _ _ _ - - - - - - - - - - - - - - - - - - 30 BO -PE -press rating appropriate; test to -(put psig in comments)- - - - - - - - - - - - - - - - - - - - Yes - - - - - - - MASP= 1308 psi Will test6.OPEto 3000 psi- - - - - _ - _ - - - _ _ _ _ _ _ - _ _ _ - - - _ _ 31 Choke_ manifold compliesWAR RP-53(May 84)- - - - - - - - -- - - - - - - - - - - - -- - - - - - Yes - - - - - - - - - --- - - - -- - - - _ - - - - - - - - - - - - - - - - - - - - - - - - _ - 32 Work will occur withoutoperationshutdown ------------------------------ Yes____________________ 33 is presence of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - No_ _ - _ _ - - - H2S not expected. _Rig has_sensors_and alarms. - - - - - - - - - - - - - 34 Mechanical_condition of wells within AOR verified (For service well only) - - - - - - - - - NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - 35 Permit can be issued w/o hydrogen_ sulfide measures Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms_ Geology 36 Data presented on potential overpressure zones _ _ ------------------- Yes _ _ Hydrates geopressure not expected from drilling of offset wells. ------------- Appr Date 37 Seismic analysis of shallow gas zones_ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ _ _ - - Planned mud program appears_ adequate_ to control -operator's forecast formation pressures._ - _ _ _ _ SFD 12/20/2019 38 Seabed condition survey -(if off_ -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - Managed Pressure -Drilling will be used to monitor and mitigate any abnormal pressure encountered.- - 39 Contact name/phone for weekly_ progress reports [exploratory only] - - - - - - - - - - - - - - - - NA_ _ - - - - - - - - - - - - - - - _ - - - _ _ - _ _ _ - - - - - - - - - - - - - - - - - _ _ _ _ _ - - _ - - - _ _ _ _ - _ _ - - - - Geologic Engineering Publip, Schrader bluff well. Rev Circ Jet pump completion. Target is OB sand .. GIs Commissioner: Date: Commissioner: Date WrDateC