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Home My WebLink About219-141MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, January 25, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-15 MILNE PT UNIT M-15 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/25/2024 M-15 50-029-23653-00-00 219-141-0 W SPT 3842 2191410 1500 684 684 683 683 4YRTST P Guy Cook 12/15/2023 Testing completed with a Little Red Services pump truck and calibrated gauges. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT M-15 Inspection Date: Tubing OA Packer Depth 173 1920 1843 1821IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC231214194052 BBL Pumped:3.3 BBL Returned:2.7 Thursday, January 25, 2024 Page 1 of 1           DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191410 Well Name/No. MILNE PT UNIT M-15 pa'j„_' Operator Hilcorp Alaska LLC MD 17150 TVD 3942 Completion Date 11/22/2019 Completion Status 1WINJ Current Status 1WINJ REQUIRED INFORMATION Mud Log No Samples No v DATA INFORMATION List of Logs Obtained: DGR, ABG, EWR Ph 4, ADR, Wellbore Prof Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data ED C 31679 Digital Data Log 31679 Log Header Scans ED C 31680 Digital Data API No. 50-029-23653-00-00 UIC Yes Directional Survey Yes (from Master Well Data/Logs) Interval OHI Start Stop CH Received Comments 105 17150 12/17/2019 Electronic Data Set, Filename: MPU M-15 LWD Final.las 5761 17112 12/17/2019 Electronic Data Set, Filename: MPU M-15 ADR Quadrants All Curves.las 12/17/2019 Electronic File: MPU M-15 LWD Final MD.cgm 12/17/2019 Electronic File: MPU M-15 LWD Final TVD.cgm 12/17/2019 Electronic File: MPU M-1 5i—Definitive Survey Report.pdf 12/17/2019 Electronic File: MPU M-1 5i—Definitive Survey Report.txt 12/17/2019 Electronic File: MPU M-15i_GIS.txt 12/17/2019 Electronic File: MPU M-15 LWD Final MD.emf 12/17/2019 Electronic File: MPU M-15 LWD Final TVD.emf 12/17/2019 Electronic File: MPU_M15_Geosteering.dlis 12/17/2019 Electronic File: MPU_M15_Geosteering.ver 12/17/2019 Electronic File: MPU M-15 LWD Final MD.pdf 12/17/2019 Electronic File: MPU M-15 LWD Final TVD.pdf 12/17/2019 Electronic File: MPU M-15 LWD Final MD.tif 12/17/2019 Electronic File: MPU M-15 LWD Final TVD.tif 0 0 2191410 MILNE PT UNIT M-15 LOG HEADERS 105 7887 12/13/2019 Electronic Data Set, Filename: MPU M-1513131 LWD Final.las AOGCC Pagel of 3 Wednesday, March 18, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3118/2020 Permit to Drill 2191410 Well Name/No. MILNE PT UNIT M-15 Operator Hilcorp Alaska LLC API No. 50-029-23653-00-00 MD 17150 TVD 3942 Completion Date 11/22/2019 Completion Status 1WINJ Current Status 1WINJ UIC Yes ED C 31680 Digital Data 5761 7850 12/13/2019 Electronic Data Set, Filename: MPU M-15PB1 ADR Quadrants All Curves.las ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15P61 LWD Final MD.cgm ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15P61 LWD Final TVD.cgm ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15i P131_Definitive Survey Report.pdf ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15i P131—Definitive Survey Report.txt ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15i PB1 GIS.txt ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -15P61 LWD Final MD.emf ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M-15PB1 LWD Final TVD.emf ED C 31680 Digital Data 12/13/2019 Electronic File: MPU_M-15P61_Geosteering.dlis ED C 31680 Digital Data 12/13/2019 Electronic File: MPU _M-15PB1_Geosteering.ver ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M -1 5P61 LWD Final MD.pdf ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M-15PB1 LWD Final TVD.pdf ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M-15PB1 LWD Final MD.tif ED C 31680 Digital Data 12/13/2019 Electronic File: MPU M-15PB1 LWD Final TVD.tif Log 31680 Log Header Scans 0 0 2191410 MILNE PT UNIT M-15 P61 LOG HEADERS Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED AOGCC Page 2 of 3 Wednesday, March 18, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191410 Well Name/No. MILNE PT UNIT M-15 Operator Hilcorp Alaska LLC API No. 50-029-23653-00-00 MD 17150 TVD 3942 Completion Date 11/22/2019 Completion Status 1WINJ Current Status 1WINJ UIC Yes Completion Report Y Directional / Inclination Data Mud Logs, Image Files, Digital Data Y Core Chips Y /(5 Production Test Information Y / ro Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data File Core Photographs Y Geologic Markers/Tops 0 Daily Operations Summary 6) Cuttings Samples Y /6) Laboratory Analyses Y /b COMPLIANCE HISTORY Completion Date: 11/22/2019 Release Date: 11/1/2019 Description Date Comments Comments: Compliance Reviewed By. Date: 5 1 f o / 2-6 AOGCC Page 3 of 3 Wednesday, March 18, 2020 STATE OF ALASKA DEC 13 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AVLOM 1a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[] 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑✓ WAG[] WDSPL ❑ No. of Completions: 1 1b. Well Class: Development ❑ Exploratory ❑ Service Q - Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 11/22/2019 14. Permit to Drill Number/ Sundry: 219-141 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: November 3, 2019 15. API Number: 50-029-23653-00-00 4a. Location of Well (Governmental Section): Surface: 4,914' FSL, 351' FEL, Sec 14,T13N, R9E, UM, AK • Top of Productive Interval: 2,417' FSL, 1,044' FWL, Sec 13, T13N, R9E, UM, AK Total Depth: 629' FSL, 516' FWL, Sec 20, T13N, R10E, UM, AK 8. Date TD Reached: November 16, 2019 16. Well Name and Number: MPU M-15 9. Ref Elevations: KB: 58.64' GL: 24.7' BF: 24.7' " 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 17,148' MD / 3,922' TVD 18. Property Designation: ADL025514, ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 533814 y- 6027766 Zone- 4 TPI: x- 535222 ` y- 6025275 Zone- 4 Total Depth: x- 545243 y- 6018262 Zone- 4 11. Total Depth MD/TVD: 17,150' MD / 3,942' TVD 19. DNR Approval Number: LONS 16-004 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,082' MD / 1,863' TVD . 5. Directional or Inclination Survey: Yes (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. MD & TVD / DGR Dual Gamma Ray / ABG At -Bit -Gamma Ray / EWR Phase 4 / ADR Azimuthal Deep Resistivity / Wellbore Profile 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 215.5# X-52 Surface 80' Surface 80' 42" 14 yards 9-5/8" 40# L-80 Surface 5,771' Surface 3,853' 12-1/4" Stg 1 L - 172 bbls/T - 82 bbls Stg 2 L - 345 bbls/T - 56 bbls 195 bbls 4-1/2" 13.5# L-80 5,601' 17,150' 3,840' 3,922' 8-1/2" Injection Liner w/ ICDs & Swell Packers 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 ICD and swell packer detail "` Liner run on 11/20/2019 COMPLETION D TE V�:zI 25. TUBING RECORD SIZE DEPTH SET (MD) IPACKER SET (MD/TVD) 3-1/2" 5,615' 5,615' MD / 3,842' TVD Liner Top Packer 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was 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: N/A Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Test Period -11110. Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casinq Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 Submit ORIGINIAL onl , B �zs(zo/ �� i `l , Z_L�BpMS.DEC 17 2019 28. CORE DATA Conventional Core(s): Yes ❑ No ❑✓ Sidewall Cores: Yes ❑ No E] 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 Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,082' 1,863' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 5,688' 3,848' s information, including reports, per 20 AAC 25.071. SV5 1,360' 1,314' SV1 2,124' 1,891' ' Ugnu LA3 4,027' 3,124' SB NA 4,873' 3,632' SB OA 5,688' 3,848' Formation at total depth: SB OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Casing and Cementing Reports 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: Cdln er hIICOr .Coni Authorized Contact Phone: 777_8389 Signature: Date: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. 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 1b: 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 Ilileorp Alaska. LLC Orig. KB Elev.: 58.6 '/ GL Elev.: 24.7 20" 9-5'8"'ES' cementer @ 2,24T NU —t t k 3 4/5 9-5/g, 6 4-1/2' Schematic Milne Point Unit Well: MPU M-15 PTD: 219-141 API: 50-029-23653-00 TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/4-1/16" 5M Cameron Wing Wellhead I Cameron 11" 5K x sliplock bottom w/ (2) 2-1/16" 5K outs OPEN HOLE / CEMENT DETAIL 42" 14 yards Type 1 12-1/4" Stg 1 –Lead 172 bbls / Tail 82 bbls Top Stg 2 –Lead 345 bbls/ Tail 56 bbls 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn DriftID Top Btm BPF 20"x 34" Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TXP 8.679" Surface 5,771' 0.0758 4-1/2" Liner 13.5 / L-80 / Hyd 625 3.795" 5,601' 17,150' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 1 2.867" 1 Surf 1 5,615' 1 0.0870 WELL INCLINATION DETAIL KOP @ 400' Hole Angle @ XN = 62 ° Hole Angle @ Liner Top = 84° Max Hole Angle = 94° JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,456' 3-1/2" X Nipple (2.813" Packing Bore) 2.813" 2 4,899' 3-1/2" XN Nipple, 2.813" Packing Bore, 2.75" No -Go, w/RHC 2.750" 3 5,252' 3-1/2" Gauge Mandrel SGM-XPQG w/ X" Wire 2.992" 4 5,605' 8.25" No Go Locater Sub (2.76' off No-go) 6.170" 5 5,606' 7.375" Tieback above the SLZXP Liner Top Packer 6.170" Lower Completion 6 5,601' 7" x 9-5/8" SLZXP Liner Top Packer with 7.38" Seal Bore 6.180" 7 17,148' Shoe (bottom @ 17,150') 3.970" Depth MD Depth ICD/Swell Packer Detail TVD See Page 2 See ICD GENERAL WELL INFO & swell Packer API#: 50-029-23653-00 Detail Completed by Doyon 14: 11/22/2019 1 71 TD =17,15(Y (MD) /TD = 3,922' (JVD) PBTD =17,148 (MD) / PBTD = 3,922(TVD) Revised By: DH 12/12/19 Depth MD Depth ND ICD/Swell Packer Detail 5,800' 3,855' Tendeka Water Swell Packer 5,988' 3,863' . Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,224' 3,871' Tendeka Water Swell Packer 6,746' 1 3,872' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,940' 1 3,865 Tendeka Water Swell Packer 7,504' 3,861' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,864' 3,855' Tendeka Water Swell Packer 8,219' 3,848' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,702' 3,840' Tendeka Water Swell Packer 8,970' 3,836' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,369' 3,851' Tendeka Water Swell Packer 9,803' 3,865' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,119' 3,864' Tendeka Water Swell Packer 10,475' 3,866' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,877' 3,861' Tendeka Water Swell Packer 11,272' 3,856' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,799' 3,866' Tendeka Water Swell Packer 12,109' 3,871' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,554' 3,886' Tendeka Water Swell Packer 12,988' 3,908' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,308' 3,920' Tendeka Water Swell Packer 13,664' 3,931' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 14,029' 3,932' Tendeka Water Swell Packer 14,468' 3,928' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 14,747' 3,938' Tendeka Water Swell Packer 15,187' 3,940' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 15,424' 3,936' Tendeka Water Swell Packer 15,907' 3,929' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 16,439' 3,924' Tendeka Water Swell Packer 16,667' 3,913' r Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge MPU M-15 Schematic 12-12-19 Page 2 of 2 DH 12/12/2019 T Well Name: Field: County/State: Location (LAT/LONG): Elevation (RKB): API #: Spud Date: Job Name: Contractor AFE #: AFE $: Hilcorp Energy Company Composite Report MP M-15 Milne Point Alaska 33.94 11/312019 1911314D MPU M-15 Drilling Doyon 14 Activity Date Present Operations Ops Summary 11/1/2019 N/U diverter system Rig Released from MPU M-21 @ 19:00. See MPU M-21 for activities.; Clean up cellar box and wellhead, Cut & cap mousehole in Cellar box. Prep rig floor and pipe shed for rig move.;Skid rig floor into moving position, Notify Pad operator for pulling off well.;Move rig off M-21. Place matting boards on east side of pad and move rig from north to south side of the pad. Move rig onto M-15. Spot, level and shim rig. Install handrails on stairs and grating at all landings. Skid rig floor into drilling position.;Hook up rig floor lines, N/U surface diverter system and install diverter lines. Sim -ops: spot rock washer & fuel tank into position. 11/2/2019 Wash to bottom @ 218' Install diverter lines. 204' from sub -structure and 103' from nearest ignition source ( well house light ) Work on acceptance with 12.25" drilling checklist. Spot shacks and power up same, set fuel trailer. Load BHA into the pipe shed, prep mud pits for fluid. Accepted Rig assembly @ 7 am.;N/U Diverter, Install riser and bell nipple. Install turn buckles, install conductor valves. C/O air boot. install mouse holes. Work on acceptance checklist. Load pipe shed with 17 joints of 5" HWDP and MWD tools. Remove liners f/ pump 2, continue to prep mud pits. Put Rig on Hi -line power @13:00. Change out saver sub, inspect grabber dies. Stock hopper room w/ mud product. Continue to go thru fluid end on #2 MP. Set upright and water pump house. Rig electrician test gas alarms. Clean and inspect TD quill, Re -torque and wire tie torque rings. Clean and C/O paddles on conveyor, Process DP, Thaw water tank valves and manifold. Make up and rack back 6 stands of 5" HWDP and Jars. Function diverter system and purge lines of air. Load spud mud to pits, mobilize BHA components to rig floor, prep equipment for BHA. SimOps: Adjust knife valve cylinder and shaft alignment. Perform diverter function test on 5" HWDP. Knife valve open in 15 sec. & diverter close in 34 sec. 3000 PSI system pressure, 1850 PSI after closure, 41 sec. 200 PSI recovery, 152 sec. full recovery. 2000 PSI avg - 6 nitrogen bottles. AOGCC rep Guy Cook waived witness for test on 11/2/2019 11:21 am. Torque 12-1/4" Kymera bit to 8" mud motor, M/U XO sub & stand of HWDP. Tag fill @ 108'w/ 1 OK. Fill mud lines for high pressure test. Change out demco valve on rig floor mud manifold. PJSM, Service rig. Pressure test to 500 PSI low / 3500 PSI high - good. Clean out conductor w/ fresh water f/ 108't/ 114'w/ 420 GPM, 400 PSI, 40 RPM, 1 K TO, 1 K WOB. Drill 12-1/4" surface hole f/ 11 4' t/ 218', 11 4'drilled 88'/hr AROP. Drill 1 st 10' with water then swap to spud mud. 450 GPM, 560 PSI, 40 RPM, 1-3K TO, 1 K WOB. 50K PU/SO/ROT. Note: Daylight savings time. 1 additional hour during this time period. BROOH f/ 218' U 124' then pull on elevators to 37'. P/U and inspect bit, like new. Blow down TopDrive. Pre -Spud Meeting & PJSM with rig crew and Sperry on M/U BHA. M/U MWD tools (DGR, EWR, directional & PWD) to 87'. Measure TF offset to motor: 314°=709/812'360.Test & initialize MWD tools. M/U three NMDC to 177'. M/U XO and stand of HWDP. Pulse test MWD good. Wash down to bottom with 400 GPM, 625 PSI. 11/3/2019 Drilling 12.25" surface Drill 12-1/4" surface hole f/ 218't/ 665' 447' 'll 5'/hr AROP. 450 GPM, 1100 PSI, 60 RPM, 1.3K TO, 7K WOB, 9.15 ppg PU hole at 2936' MW, 144 vis, / SO 80K / ROT 80K. ECD 9.44 Began 3°/100' build at 400'.;Drill 12-1/4" surface hole f/ 665't/ 1400' (1347' TVD), 735' drilled, 1227hr AROP. 450 GPM, 1180 PSI, 60 RPM, 4-5K TO, 9-1 OK WOB, 9.1 ppg MW, 118 vis, PU 90K / SO 90K / ROT 90K. ECD 10.47 Continue 3°/100' build.;Note: Mud pump 2 traction motor getting warm, shut down pump, LOTO pump, continue drilling with pump 1, electrician found that lug was not torqued down, inspect and re -torque same, put MP back on Iine.;Drill 12-1/4" surface hole f/ 1400't/ 2160' (1911' TVD), 760' drilled, 127'/hr AROP. 450 GPM, 1190 PSI, 60 RPM, 3-5K TO, 5-1 OK WOB, Max gas 97u 9.2 ppg MW, 143 vis, ECD 10.1. PU 105K / SO 92K / ROT 100K. End 3°/100' build at 1935'. Hold 49.6° tangent. Base of permafrost @ 2082' MD / 1864' TVD.;Drill 12.25" surface hole f/ 2160't/ 2936', (2343' TVD) 776' drilled, 129'/hr AROP. 500 GPM, 1560 PSI, 80 RPM, 5K TO, 10K WOB. Max gas 480u. 9.2 ppg MW, 120 vis, 10.00 ECD. 115K PU / 100K SO / 105K ROT. Hold 49.6° tangent. Top of Ugnu @ 2673' MD / 2251' TVD.;Pump hi vis sweep @ 2350' back on time w/ no increase Pump hi vis sweep @ 2750' back on time w/ 20% Last survey @ 2865.1 VMD / 2374.74' TVD, 50.82° inc, 151.04° azm, 7.62' from plan, 3.63' high and 6.70' right. 11/4/2019 Drilling 12.25" surface Drill 12.25" surface hole f/ 2936' t/ 3492', (2782' TVD) 556' drilled, 92.67hr AROP. 525 GPM, 1780 PSI, 80 RPM, 5-7K TO, 1 OK hole at 5571' WOB. Max gas 115u. 9.2 ppg MW, 150 vis, 10 ECD. 127K PU / 100K SO / 110K ROT. Hold 49.6° tangent.;Pump 30 bbl hi vis sweep @ 3300', back on time w/ 30% increase.;Drill 12.25" surface hole f/ 3492't/ 4352', (3316' TVD) 860' drilled, 143'/hr AROP. 575 GPM, 2050 PSI, 80 RPM, 7-10K TO, 5K WOB. Max gas 97u. 9.3 ppg MW, 117 vis, 10.2 ECD. 148K PU / 105K SO / 125K ROT. Hold 49.6° tangent.;Pump 30 bbl hi vis sweep @ 3970', 300 stks late, no increase.;Drill 12.25" surface hole f/ 4352' t/ 4921', (3651' TVD) 569' drilled, 957hr AROP. 575 GPM, 2150 PSI, 80 RPM, 10-14K TO, 12K WOB. Max gas 101 u. 9.2ppg MW, 138 vis, 10.2 ECD. 158K PU / 105K SO / 129K ROT. Start 4° BUR @ 4490'.;Pump 30 bbl hi vis sweep @ 4698, 200 stks late, no increase.;Drill 12.25" surface hole f/ 4921't/ 5571', (3835' TVD) 650' drilled, 108.37hr AROP. 575 GPM, 2300 PSI, 80 RPM, 10-13K TO, 18K WOB. Max gas 284u. 9.4 ppg MW, 105 vis, 10.4 ECD. 155K PU / 104K SO / 125K ROT. Continue 4° BUR.;Crossed one fault (40' DTE throw) at 5,235'. Last survey at 5339.91' MD / 3801.25' TVD, 80.33° inc, 129.15° azm, 6.25' from plan, 4.05' high, 4.76' right. 11/5/2019 Running 9.625" casing at Drill 12.25" surface hole f/ 5571'V 5778', (3854' TVD) 207' drilled, 103.5'/hr AROP. 575 GPM, 2300 PSI, 80 RPM, 10-13K TO, 163' 18K WOB. Max gas 284u. 9.4 ppg MW, 145 vis, 10.2 ECD. 155K PU / 104K SO / 125K ROT. TD in the OA-1.;Circulate and condition wellbore, pump 30 bbl hi vis sweep w/ nutplug. - Was strung out when returned and no increase in cuttings. CBU 2x, Backream f/ 5778' U 5494', rack a stand back each bottoms up. 550 gpm - 1790psi, 80 rpm - 11 k Tq, Ream stand down t/ 5589' while finish condition mud.;RIH f/ 5589'V 5778' on elevators. 157k PU, 110k SO. Monitor well f/ 10 min, Static.;BROOH F/ 5778' T/ 829", 550 GPM, 1710 PSI, 80 RPM, 12-15K TO. 10-19 fUmin pulling speed, slowing as necessary through slides. MW in 9.3, MW out 9.5+.;Monitor Well, static. Pull out of hole on elevators f/ 829' racking HWDP & jars in Derrick. BDTD. PJSM, UD 3 NMFCD. Hole took calculated hole volume for the trip out.;Down toad tools & clean up rig floor. L/D BHA from 77'. Bit Grade 1 -1 -WT -A -F -1 -CT -TD Clear BHA components and clean rig floor. 3 BPH static losses.;PJSM. Rig up to run 9-5/8" casing. M/U J Doyon Volant casing running tool with cement swivel, 4' bail extensions, 9-5/8" elevators, spiders and strap tongs. 3 BPH static r, I� " \ Iosses.;PJSM. M/U 9-5/8" 40# L-80 TXP BTC -SR casing shoe track to 163.81'- float shoe joint, spacer joint, float collar joint w/ bypass baffle installed baffle Thread lock & torque to 20,960 ft/lbs Doyon Volant and adapter. connections with tool. Check floats - good.;Two 9-5/8"x12-1/4" Expand-o-lizers w/4 stop rings installed on shoe joint, one floating on joint #2, one each with two each stop rings on joints #3 & 4. 3 BPH static losses. 11/6/2019 Circulate and condition for Run 9-5/8" 40# L-80 TXP-BTC casin f/ 63' TQ to 20,960 fUlbs w/ the Volant tool. Install one 9-5/8"x12-1/4" Expand -0- 2nd stage cement job Lizer every other joint #1-26. Fill pipe on the fly & top off every 10 joints. 26 BBL losses at this point;Run 9-5/8" 40# L-80 TXP- BTC casing f/ 2480' U 2941'. TO to 20,960 ft/lbs w/ the Volant tool. Install one 9-5/8"x12-1/4" Expand-O-Lizer every other joint #26-71. Fill pipe on the fly & top off every 10 joints.;Stage up pumps to 6 BPM, 130 PSI. CBU while reciprocating 20'. 2400 strokes pumped. 9.0 ppg MW, 43 vis in and 9.5 ppg MW, 146 vis out.;Run 9-5/8" 40# L-80 TXP BTC -SR casing f/ 2941' U 5755'. Torque to 20,960 ft/lbs with Doyon Volant tool. Fill on the fly & top off every 10 joints. Install 9-5/8"x12-1/4" Expand-o-lizer on every other joint #71-81, every joint #81-85 & every other joint #94-138. P/U 225k S/O 125. Halliburton ES cementer between joints #85 & 86. Pup joints above and below ES cement have one each 9-5/8"x12-1/4" Expand-o-lizer and stop ring. AOGCC notified of upcoming BOP test at 15:49 on 06 Nov 2019. Wash down last 19' at 1 / bpm.Stage up pumps to 8 bpm while working pipe. up/dn 225/125. Full returns. Circ & condition full circulation while treating ( 1 i 47 wr mud for cmt job. Work pipe 20' while circulating. 9.2 in and out. Not much cuttings just very fine sand. 52 bbls loss while running casing. PJSM, Cmt job. R/U cmt line, Blow down top drive. Lineup to HES.and pump 5 bbl H2O. Test lines to 1 ) 1000/4000 psi. Good.; Pump 60 bbl of 10 ppg Tuned spacer with 4# red dye and Pol-E-flake in first 10 bbl. Drop bypass plug. Mix and pump 172bbl 121b lead cmt at 3-5 bpm (410 SX). Mix and pump 82 bbl of 15.8 Tail cmt at 3-4 bpm (400 SX). Rotate and Recip 20'f/ 5774't/ 5774;Drop Shut off plug. HES pump 20 bbl H'O. Line up to rig and displace with 2256 stks. (228 BBL);Line up to HES and mix and pump 82 bbl tuned spacer at 5 bpm. Displace with rig at 6 bpm 9.3 ppg mud. Saw Pol-E- flake back at 3200 total rig strokes pumped. Bump plug 1031 strokes (3287 total strokes). 16 strokes late from calculated. Hold 600 over FCP for 5 min. Bleed down and check floats good;Open EScmt tool at 300012so. Pressure dropped to 240. Pump @ 6 bpm, 250 psi. Mud push back at 1150, dump to rock washer at 1200 strokes and dump 394 bbl total. Got back mud push and 40 bbls cmt and 100 bbl contaminated interface. Circulate total of 5100 strokes. 3.4 btm ups.;UP/DN 250/125 . ROT 130 at 20K TO. Work pipe & Rot throughout cmt job until last 10 bbl. Worked pipe F/ 250K T/1 25K while displacing out cmt & spacers. Parked pipe in the upstroke @ 5771' with 250K. CIP at 01:36. Shut down and flush out BOPS with black water from hole fill. Flush surface equipment. Break out Volant tool, inspect cup & dies - good. Line back up and continue to circ through the ES cmt tool at 6 bpm at 178 psi while waiting on next stage. Break out Volant tool, inspect cup & dies - good. 11/7/2019 Testing BOPE Continue to circ at 6 bpm at 240 psi. Prep & Clean and for second stage cmt job. Waiting on cmt until 830 for set up time.; PJSM cmt job, Continue circulating at 6 bpm while waiting HES to batch up.;Line up to HES and pump 60 10.5 Tuned spacer. Mix and pump 345 bbl lead cmt(440 SX), Mix and bump 5601ibb1 of 15.8 Swift CEM tail. (270 SX) Dro closing Iu and pump 20 bbl H2O with HES to chase lines. Swap to rig and displace with 1485 strokes. Bump on calculated volumes. Pressure up and close ES CMT tool at 1430 PSI. Check for flow. No flow. Good. No losses for the second stage cmt job. 195 Skt [ bbl cmt Returned to surface. R/D ES Cmt unit. Drain and flush surface equipment with black water. Hoist annular. Install casing slips & land casing with 100K on slips. Cut casing & UD 17.13' cut joint. Set annular back down on diverter adapter. N/D flow nipple & riser. N/D diverter & diverter adapter. SimOps: Cleaning Pits;lnstall Cameron T-103 nipple and test to 500 PSI for 5 min & 2475 PSI for 10 min. Install T-103 tubing head and test to 500 PSI for 5 min. & 5000 PSI for 15 min.;N/U BOP stack, turnbuckles and kill line. Install trip nipple, load shed with test joints, mobilize test plug, wear bushing and split bushings to rig floor. R/U to test BOP equipment: install test plug and 3-1/2" test joint. Fill stack, choke and all lines with fresh water. Perform shell test. Leaking at base of trip nipple. Drain water level below trip nipple. Change O -Ring gasket 2x and re -align stack. Refill and perform good shell test. Test BOP equipment as per PTD & AOGCC requirements All tests performed against a test plug with fresh water for 5 min. each 250 PSI low / 3000 PSI high & charted. #1: Annular on 3.5" test joint, valves 1, 12, 13, 14, & 3" kill Demco. AOGCC rep Austin McLeod waived witness for BOP test @ 18:42 hrs. 11/8/2019 Laying down HWDP at Test BOPs & valves 250/ 3ono nsi Test nnrndar to 950/9500 psi. Test on 3-1/2" & 5" Test joints Test annular with 3-1/2" test 410' joint and all rams with 3-1/2" & 5" Test joints. Perform Accumulator Draw down. 1650 psi after shut in. 200 psi increase ain 46 sec. Full pressure attained in 197 sec. 6 N' bottles at 2000 psi average. Pull test plug, Blow & R/D down surface & test 'equipment . Bring BHA #2 to rig floor. Set Wear bushing. PJSM, P/U BHA #2 with used Smith 8 1/2 Bit. RIH out of derrick to 2200'. Wash down and tag cmt at 2238'. Drill ES cmt tool on depth at 2246'. Work through three times clean. Then with no pumps. Good.;TIH f/ 2302'V 5539'. Fill pipe every 20 test Fill drill Close UPR 5" drill Purge kill & lines stds.;R/U equipment. pipe. on pipe. choke with 9.2 ppg spud mud. Pressure test casing to 2600 PSI for 30 min on chart. Pumped 5.3 bbls / bled back 5.3 bbls. Wash down f/ 5539', drill cement stringers f/ 5588', drill BA on depth @ 5647', drill out 9 5/8" shoe track to 5771', cleanout rathole and drill 20' new formation to .I� 5798' 545 gpm, 1730 psi, 40 rpm, 11-15k tq, 10-15k wob.;Circulate and condition mud for FIT 550 gpm, 1700 psi, 40 rpm, 13k 1 i tq, with good 9.2 ppg MW in/out. 190k P/U, 85k S/O, 125k ROT;Rack stand back. Blow down TopDrive;Parked @ 5726', R/U test equipment, close UPR, purge air from lines, Perform FIT to 12 ppg with existing 9.2 ppq MW, apply 561 psi, bleed off pressure, open UPR, BD, R/D test equipment. Good test. 1.0 BBLS pumped, 1.0 bbls bled back. Blow Down lines & R/D. Flow check well, static, POOH on elevators racking back 5" DP f/ 5726' to 589'. Lay down 3 jts HWDP U 410'. Correct displacement onTnOH NJ 11/9/2019 Drilling 8.5" lateral section Lay down 12 jts 5" HWDP, Rack jar stand in Derrick, Drain motor, L/D remaining BHA. 8-1/2 tri-cone bit grade= 1-1-WT-A-E-1-NO- @ 6138' BHA. Clear and clean the rig floor, Mobilize RSS BHA components to the rig floor. Hold PJSM. M/U 8-1/2" production drilling BHA #3 to 83': NOV SK616MJ1 D bit, NRP sleeve, Geo-Pilot, MWD (ADR/ILS/DGR/PWD/DM/TM) initialize tools. M/U 2 float subs, TIH w/ 3 NM flex collars, HWDP & jars t/ 273'. Pulse test MWD 450 GPM, 830 PSI - good. Blow down top drive. TIH f/ 273' t/ 2178'. Fill pipe and break in Geo-Pilot seals, Blow down top drive. Continue to TIH f/ 2178't/ 5510' with stands f/ Derrick. Pick up singles from the pipe shed f/ 5510' U 5700'. Monitor Well. PJSM. Remove trip nipple and install MPD RCD. Fill lines, no leaks. Wash down from 5700't/ 5796', 350 GPM - 910 psi, 40 RPM - 13k Tq. Pull back into casing, 5769'. PJSM for displacement. Pump 30 bbl Hi- Vis spacer followed by 8.8 ppg Flo-Pro NT mud w/ 1.0% 776 lubricant @ 5.5 BPM, 500 PSI, 60 RPM, 1 OK TQ. 160K PU / 92K SO / 112K ROT. Good clean mud back, Obtain SPR's. Rack a stand back to 5700'. Shut MPD choke, monitor well - static. Install FOSV and pup jt. PJSM. Slip and cut drilling line - 73' of line cut. Service rig: grease blocks, top drive & draw works. Prep for Upper IBOP Removal. Service rig: grease blocks, top drive & draw works. Prep for Upper IBOP Removal. Remove and change out upper IBOP. Function test actuator. - Good. Install and torque the compression torque rings. Wire tie bolts. Test IBOP to 250/3000psi, 5 min charted each, Install bails and elevators on TopDrive. M/U stand of drillpipe in mousehole. RIH f/ 5700't/ 5798'. Tag bottom on depth. Drill 8-1/2" lateral f/ 5798' t/ 6138' (3872' TVD), 340' drilled, 97/hr AROP. 545 GPM, 1500 PSI, 120 RPM, 12- 15K TQ, 12-15K WOB. 8.95 ppg MW, 48 vis, 10.30 ECD, 2667u max gas. 140K PU / 90 SO / 115K ROT. Drill in the OA-1. MPD holding 200 psi during connections, 100 psi while drilling. Last survey at 6010.30' MD / 3864.42' TVD, 87.04° inc, 124.43° azm, 10.97' from plan, 7.34' high & 7.66' right'. Drilled 2 concretions for a total thickness of 18' (7.9% of the lateral). 11/10/2019 Repair TopDrive Drill 8-1/2" lateral f/ 6138't/ 6734' 3870' TVD 596 drilled, 99/hr AROP. 550 GPM, 1570 PSI, 120 RPM, 9K TQ, 8K WOB. 8.95 ppg MW, 46 vis, 10.43 ECD, 1653u max gas. 140K PU / 91 SO / 115K ROT. Pump hi vis sweep at 6364', 25% increase in cuttings. Drill in the OA-1 U 6187'& OA-2 U 6305' Encountered Fault #1 at 6440' while drilling in the OA-3. Drill 8-1/2" lateral f/ 6734' t/ 7226' (3857' TVD), 492 drilled, 82/hr AROP. 550 GPM, 1660 PSI, 120 RPM, 1 OK TQ, 1 OK WOB. 8.9 ppg MW, 47 vis, 10.57 ECD, 1123u max gas. 145K PU / 80 SO / 115K ROT. Pump hi vis sweep at 7032', return 300 stks late w/ 10% increase in cuttings. Drill 8-1/2" lateral f/ 7226't/ 7503' (3864' TVD), 277 drilled, 138/hr AROP. 550 GPM, 1660 PSI, 120 RPM, 10K TQ, 8K WOB. 8.8 ppg MW, 47 vis, 10.58 ECD, 453u max gas. 140K PU / 79 SO / 115K ROT. Last survey at 7342.92' MD / 3858.37' TVD, 88.83° inc, 122.27° azm, 23.78' from plan, 21.26' high & 10.67' right' Drilled 24 concretions for a total thickness of 112' (6.5% of the lateral). Blow down Topdrive, Troubleshoot and repair topdrive. Check and fill oil levels. Troubleshoot VFD house & sylinoid. Inspect service loop. Circ through cement line 275 GPM, 760 psi. Work string from 7503't/ 7483', pump every 10 min for 5 bbls working string. Continue Troubleshoot and repair topdrive. Check accumulators, fill N2 and test Pumped out hydraulic tank. C/O hydraulic pump. Circulate through cement line at 1.75 bpm, 340 psi. 11/11/2019 Drilling 8.5" lateral at Continue Troubleshoot and repair topdrive. C/O hydraulic pump, cartridges, filter. Circulate through cement line at 1.5 bpm, 320 6553' psi. 145K PU / 95 SO. Continue Troubleshoot and repair topdrive. Change out shot pin assembly. Circulate 1.5 bpm through cement line. Work string 10' f/ 7477't/ 7464'. Function test shot pin - Good. Post job inspection of topdrive, clear and clean rig floor. Rotate and reciprocate string f/ 7503' t/ 7413' while CBU. 525 GPM - 1600 psi, 80 RPM - 5k Tq. Drill 8-1/2" lateral f/ 7503' t/ 7793' (3851' TVD), 290 drilled, 83/hr AROP. 550 GPM, 1700 PSI, 120 RPM, 10K TQ, 1 OK WOB. 8.8 ppg MW, 49 vis, 10.47 ECD, 810u max gas. 137K PU / 83 SO / 112K ROT. Undulate up at 92° as per plan. See Top of OA-1 @ 7730' with ABG. Increase inclination to 95° and continue drilling to confirm out of zone with logs. Drill 8-1/2" lateral f/ 7793't/ 7887' (3847' TVD), 94 drilled, 94/hr AROP. 550 GPM, 1770 PSI, 120 RPM, 1 OK TQ, 10K WOB. 8.85 ppg MW, 49 vis, 10.47 ECD, 91 u max gas. 145K PU / 75 SO / 111 K ROT. Confirm Top of OA-1 on logs. Decision made to pull back and perform open hole sidetrack. Backream f/ 7887' t/ 7790'. 550 GPM - 1750 psi, 120 RPM - 7k Tq. Blow down topdrive. Line up MPD over top of hole. POOH f/ 7790't/ 6380'. Circulate 157 gpm over top of hole, MPD holding 200 psi dynamic backpressure, 150 psi static. 160k PU / 80k SO;Trough 20' observed 0.75° drop in inclination. Control drill @ 507hr until 85.73° inc. Sidetrack low side and drill f/ 6430't/ 6455'. Trip back through sidetrack point. BROOH f/ 6457' U 6365', 550 GPM, 1650 PSI, 120 RPM, 4K TQ. At bit inclination of 86° verified assembly tripped into the new hole. Drill 8-1/2" lateral f/ 6455' t/ 6553' (3890' TVD), 97' drilled, 97'/hr AROP. 550 GPM, 1670 PSI, 120 RPM, 8K TQ, 1 OK WOB. 8.9 MW, 45 vis, 10.37 ppg ECD, 338u max gas. 145K PU / 85K SO / 11 OK ROT. Drilling in the OA-3. Logged fault #1 at 6440', 8' DTS throw put wellbore into the bottom of OA-2. Dropped down into the OA-3 at 6487'. MPD holding 180 psi during connections, 80 psi while drilling. Last survey at 6483.79' MD / 3885.34' TVD, 86.68° inc, 123.82° azm, 16.03' from plan, 7.99' low & 13.9' right'. Drilled 9 concretions for a total thickness of 49' (7.1% of the lateral). 11/12/2019 Drilling 8.5" production Drill 8-1/2" production hole f/ 6553' t/ 7036', 483' drilled, 80.57hr AROP. 550 GPM, 1670 PSI, 120 RPM, 8K TQ, 5K WOB. 8.9 ppg lateral at 9068' MW, 45 vis, 10.31 ECD, max gas 340u. 145K PU / 90K SO / 115K ROT. Sweep @ 7030' on time w/ 10% increase. Drilling in OA- 3. Hold 80 PSI while drilling & 180-200 PSI on connections with MPD. Drill 8-1/2" production hole f/ 7036' U 7604', 568' drilled, 94.77hr AROP. 550 GPM, 1690 PSI, 120 RPM, 9K TQ, 11-13K WOB. 8.8 ppg MW, 52 vis, 10.46 ppg ECD, max gas 425u. 145K PU / 85K SO / 115K ROT. Drilling in OA-3. Hold 80 PSI while drilling & 180-200 PSI on connections with MPD. Drill 8-1/2" production hole f/ 7604't/ 8363', 759' drilled, 126.57hr AROP. 550 GPM, 1800 PSI, 120 RPM, 9K TQ, 8-91K WOB. 8.9 ppg MW, 53 vis, 10.69 ECD, max gas 216u. 141 K PU / 77K SO / 11 OK ROT. Sweep @ 8175' on time w/ 25% increase. Entered OA-2 @ 7798' & OA-1 @ 8074'. Hold 70 PSI while drilling & 180-200 PSI on connections with MPD. Drill 8-1/2" production hole f/ 8363' t/ 9068', 705' drilled, 117.57hr AROP. 550 GPM, 1880 PSI, 120 RPM, 9K TQ, 3-12K WOB. 9.0 ppg MW, 54 vis, 10.82 ECD, max gas 601 u. 147K PU / 75K SO / 111 K ROT. Drilling in OA-1. Choke full open w/ 60 PSI while drilling & 180-200 PSI on connections with MPD. Last survey at 8960.15' MD / 3856.20' TVD, 89.58° inc, 121.84° azm, 11.60' from plan, 11.58' high and 0.73' right. Drilled 37 concretions for a total thickness of 152' (4.9% of the lateral). 11/13/2019 Drilling 8.5" production Drill 8-1/2" production lateral f/ 9068't/ 9601', 536' drilled, 89.3'/hr AROP. 540 GPM, 2000 PSI, 120 RPM, 10K TQ, 5-7K WOB. 9.05 lateral at 11599' ppg MW, 52 vis, 11.05 ECD, max gas 269u. 160K PU / 76K SO / 110K ROT. Sweep @ 9315' back 400 stks late w/ 50% inc. Dropped from OA-1 to OA-2 @ 9265' into OA-3 @ 9435';Drill 8-1/2" production lateral f/ 9601'V 10363', 762' drilled, 1277hr AROP. 545 GPM, 2040 PSI, 120 RPM, 12K TQ, 11-12K WOB. 9.0 ppg MW, 50 vis, 10.95 ECD, max gas 2411u. 152K PU / 70K SO / 114K ROT. Drilling in OA-3. Drill 8-1/2" production lateral f/ 10363' U 11031', 668' drilled, 1117hr AROP. 550 GPM, 2150 PSI, 120 RPM, 14K TQ, 10-11 K WOB. 8.9 ppg MW, 48 vis, 11.02 ECD, max gas 665u. 162K PU / 53K SO / 114K ROT. Sweep @ 10268' back 450 stks late w/ no inc. Built from OA-3 to OA-2 @ 10827' into OA-1 @ 10957';Drill 8-1/2" production lateral f/ 11031't/ 11599', 568' drilled, 94.7'/hr AROP. 550 GPM, 2220 PSI, 120 RPM, 14K TQ, 5-12K WOB. 9.0 ppg MW, 45 vis, 10.63 ECD, max gas 644u. 166K PU / 55K SO / 110K ROT. Sweep at 11221' back 350 stks late w/ 20% inc. Drilling in OA-1. 03:00 MBT = 7.2#/bbl, perform 290 bbl dump & dilute @ 11506'. Drilled 59 concretions for a total thickness of 242' (4.2% of the lateral). Last survey @ 11530.46' MD / 3880.05' TVD, 87.91* inc, 124.49° azm, 7.58' from plan, 7.2' high and 2.36' left. 11/14/2019 Drilling 8-1/2" production Drill 8-1/2" production lateral f/ 11599't/ 12181', 582' drilled, 97'/hrAROP. 550 GPM, 2060 PSI, 120 RPM, 13K TQ, 8-10K WOB. lateral at 14074' 8.85 ppg MW, 43 vis, 10.74 ECD, max gas 859u. 170K PU / no SO / 110K ROT. Lost SO at 12170'. Drilling in OA-. ;Drill 8-1/2" production lateral f/ 12181't/ 12879', 698' drilled, 116.3'/hr AROP. 550 GPM, 2120 PSI, 120 RPM, 15K TQ, 12K WOB. 8.9 ppg MW, 51 vis, 11.42 ECD, max gas 527u. 173K PU / no SO / 109K ROT. Perform planned undulation down, entered OA -2 @ 12495' & OA -3 @ 12665'.;Drill 8-1/2" production lateral f/ 12879't/ 13441', 562' drilled, 93.77hrAROP. 550 GPM, 2100 PSI, 110 RPM, 17K TQ, 11-12K WOB. 8.9 ppg MW, 50 vis, 11.34 ECD, max gas 595u. 174K PU / no SO / 105K ROT. Sweep @ 13124' back on stks with no increase. Drilling in OA -3. 21:00 mud check MBT = 7.0. Performed 290 new mud dilution at 13386'. MBT after dilution = 6.25. ECD reduced from 11.5 to 10.95. Drill 8-1/2" production lateral f/ 13441't/ 14074', 633' drilled, 105.57hr AROP. 550 GPM, 2090 PSI, 120 RPM, 15-17K TQ, 8-18K WOB. 8.95 ppg MW, 46 vis, 11.22 ECD, max gas 591 u. 177K PU / no SO / 106K ROT. Began steering up at 13700'. Drilled in OA -3 to 13900', currently in OA-2.;Drilled 89 concretions for a total thickness of 383' (4.7% of the lateral). Last survey @ 13910.06' MD / 3953.42' TVD, 91.31' inc, 126.90° azm, 24.70' from plan, 18.05' low & 16.86' left. 11/15/2019 Drilling 8.5" production Drill 8-1/2" production lateral f/ 14074't/ 14640' 566' drilled, 94.37hr AROP. 545 GPM, 2210 PSI, 120 RPM, 15K TQ, 10-15K WOB. lateral at 16057' 9 ppg MW, 46 vis, 11.36 ECD, max gas 537u. 182K PU / no SO / 103K ROT. Drilled from OA -2 to OA -1 @ 14220'. Pump tandem sweeps at 14360', 800 stks late w/ no increase. Drill 8-1/2" production lateral f/ 14640't/ 15290', 650' drilled, 108.3'/hrAROP. 550 GPM, 2280 PSI, 120 RPM, 18K TQ, 5-15K WOB. 9.1 ppg MW, 46 vis, 11.7 ECD, max gas 433u. 180K PU / no SO / 111 K ROT. Drilling in OA -1. Drill 8-1/2" production lateral f/ 15290't/ 15437', 147' drilled, 73.57hrAROP. 550 GPM, 2330 PSI, 120 RPM, 19K TO, 8-11 K WOB. 9.0 ppg MW, 45 vis, 11.68 ECD, max gas 434u. 180K PU / no SO / 112K ROT. Crossed fault #2 @ 15350'w/ 35' DTN north placing the wellbore in the shale beneath the OA sands. Steer up at 94° inclination to re -acquire sands. Low voltage from high line after transformer- 540 volts of 600 volt system. Transformer already on highest tap setting. Start rig generators and remove rig from high line power. Shut down computers on rig for swap then re -start all systems. Drill 8-1/2" production lateral f/ 15437' t/ 15645', 208' drilled, 5271hr AROP. 550 GPM, 2420 PSI, 120 RPM, 18K TQ, 7-13K WOB. 9 ppg MW, 44 vis, 11.5 ECD, max gas 439u. 175K PU / no SO / 114K ROT. Entered the base of OA sands @ 15491, 141' drilled out of zone. Entered OA -3 @ 15573'. High vis sweep @ 15502', 400 stks late w/ no increase. Drill 8-1/2" production lateral f/ 15645't/16057', 412' drilled, 68.771hr AROP. #3 generator kicked offline. Reduce parameters to limit power load. 460-510 GPM, 1860-2110 PSI, 100-110 RPM, 15-20K TQ, 10-15K WOB. 9.1 ppg MW, 46 vis, 11.54 ECD, max gas 359u. 180K PU / no SO / 104K ROT. Briefly entered OA -4 from 15696' to 15776'. Drilling in OA -3. Fire drill: all hands responded 136 sec. Drilled 111 concretions for a total thickness of 509' (5.0% of the lateral). Last survey @ 15909' MD / 3949' TVD, 90.32° inc, 123.61' azm, 63.84' from plan, 63.81' low & 2.05' right. 11/16/2019 Begin BROOH at 17150' Drill 8-1/2" production lateral f/ 16057't/ 16420', 363' drilled, 60.57hr AROP. 495 GPM, 1830 PSI, 120 RPM, 20K TQ, 8-10K WOB. 9.1 ppg MW, 45 vis, 11.34 ECD, max gas 429u. 195K PU / no SO / 106K ROT. Built up from OA -3 and entered OA -2 at 16385'. Drill 8-1/2" r 12.37hr AROP. TO of well called by geologist. 500 GPM, 2130 PSI, 120 RPM, 22K TQ, 5-15K WOB. 9.1 ppg MW, 46 vis, 11.7 ECD, max gas 531 u. 185K PU / no SO / 115K ROT. Drilled from OA -2 and entered OA -1 at 16600'. Performed 290 bbls new mud dilution at 16540'. Drilled 124 concretions for a total thickness of 638' (5.6% of the lateral). Last survey @ 17081.25' MD / 3938.51' TVD, 86.67° inc, 122.48' azm, 66.45' from plan, 65.95' low & 8.15' left. Obtain final survey and pump 30 bbl high vis sweep, back 400 stks late w/ no increase. Pump 550 GPM, 2440 PSI, 120 RPM, 17K TQ. Rack back a stand every bottoms up f/ 17150' t/ 16840'. Pumped 4.8 total bottoms up pumped Wash in hole f/ 16840't/ 17150' with 220 GPM, 860 PSI, 80 RPM, 18K TQ. Pump 30 bbls high vis spacer, 40 bbls seawater, 30 bbls SAPP pill #1, 40 bbls seawater, 30 bbls SAPP pill #2, 40 bbls seawater, 30 bbls SAPP pill #3, then 300 bbls seawater. Pump 30 bbls high vis spacer, then displace to 8.45 ppg 2% KCI brine w/ 4% lube (2% LoTorq & 2% 776). Wall cake observed over the shakers at 10700 strokes with the SAPP. Good lubed brine back at 16800 strokes, shut down at 17200 strokes. MPD held 135 PSI and dropped to 110 PSI. Bleed to 60 PSI and built to 90 PSI in 5 min. Clean pit #3 & prepare to BROOH. Obtain slow pump rates. 180K PU / 65K SO / 113K ROT. 25K available down weight after lubed brine displacement. Production Screen Test: New brine: 9.68, 9.52 & 10.27 sec. Returned brine at flow line: 11.24, 12.08, 11.96 sec. 11/17/2019 BROOH at 7602' BROOH f/ 17150't/ 14743'@ 5 min/stand. Lay down stands in the mousehole. 500 GPM, 1410 PSI, 120 RPM, 16K TQ. MPD full open choke while reaming (10.22 ECD), hold 110 PSI on connections (9.0 ppg EMW). Max gas 51u. BROOH f/ 14743't/ 12300'@ 5 min/stand. Lay down stands in the mousehole. 500 GPM, 1410 PSI, 120 RPM, 12K TQ. MPD full open choke while reaming (10.14 ECD), hold 110 PSI on connections (9.0 ppg EMW). 175K PU. Max gas 171 u. BROOH f/ 12300' t/ 10078'@ 5 min/stand. Lay down stands in the mousehole. 500 GPM, 1340 PSI, 120 RPM, 10K TQ. MPD full open choke while reaming (9.80 ECD), hold 110 PSI on connections (9.0 ppg EMW). 150K PU. Max gas 56u. BROOH f/ 10078'V 7602'@ 5 min/stand. Lay down stands in the mousehole. 500 GPM, 1210 PSI, 120 RPM, 8K TQ. Max gas 56u. MPD full open choke while reaming (9.84 ECD), hold 110 PSI on connections (9.0 ppg EMW). Kick while tripping drill- well secure 60 sec & all responded in 104 sec. 11/18/2019 Rigging up to run 4.5" BROOH F/ 7602' T/ 5700'. 500 GPM, 120 RPM, 10K TQ, 1350 PSI. UD stands in the mousehole while backreaming. Circ high vis injection liner sweep around at 550 GPM, 60 RPM, 4-5 K TQ. Brought back 10% Increase in cutings. ( Sand) UP/DN 140K/65K. Shut in and monitor pressure., built to 39 PSI in 14 min. Bled down to 0 and shut in and built to 22 PSI in 12 min. Last one 20 PSI in 10 min. Decided to bring wt to 9.0. Bring up weight in pits to 9.0 ppg. 6.5 BPM, 60 RPM, 3K TQ. Circulate 9.0 ppg viscosified brine around. 9.0+ in and out. Monitor well. Static. Monitor well while removing RCD head and install trip nipple. Slight losses at 2 BPH. Slip & cut drilling line. Monitor well on TT. 3 BPH losses. Inspect saver sub. Remove Geo -Span from the rig floor. POOH laying down 5" drill pipe f/ 5700't/ 1226'. Pumped 27 bbl 9.8 ppg dry job at 4278'. Rack back 10 stands of drill pipe f/ 1226't/ 275' for liner run. 37 bbls loss. UD NMDC to 83'. Read MWD tools, 3 BPH static losses. Unable to read ADR & gamma ray data. UD MWD tools, Geo -Pilot & bit f/ 83'. In-line stabilizer blades worn. MWD wear sleeves had flat crested wear on downhole edge. Near bit stabilizer had wear on up hole edge. Bit grade: 2 -3 -BT -N -X -I -WT -TD. Clean & clear rig floor. Mobilize casing equipment to the rig floor. R/U double stack hydraulic tongs, 4-1/2" elevators and air slips. Load one row of 5" HWDP, ICDs and swell packers in the pipe shed. 2.5 BPH losses. 124 bbls daily losses, 289 bbls cumulative for interval. 11/19/2019 Running 4-1/2" liner on 5"Load pipe shed with ICDs & swell packers. M/U XO on safety valve and P/U safetyjoint. PJSM. HWDP at 14200' P/U 4-1/2" shoe ( float shoe w/ ports welded closed ) tubing joint w/ 2 each 7.1" centralizers. Run 4-1/2"" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 41' U 2615'. TQ to 9600 ft/lbs, install 1 stop ring & 7.5" centralizer on ea. jt. 3 bph loss rate, ensure pipe filling. PU/SO 69K. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 2615't/ 10451'. Tq to 9600 fUlbs, install 1 stop ring & 7.5" centralizer on ea. jt. PU/SO 96K/82K before exiting shoe @ 5771' . PIU 110k, S/O 73k. 3 bph loss rate. Total liner completion ran: 259 joints of 4-1/2" 13.5# Hydril 625 L-80 liner, 15 Tendeka water swell packers, 15 Tendeka ICDs with 250L mesh & sliding sleeve w/ 258 centralizers (7.5" O.D.) w/ 258 stop rings and two 7.1" O.D. centralizers with 4 stop rings. Service rig. 2 BPH losses. Cable on pipe skate hydraulic line pull back counterweight broke. Replace cable. 2 BPH losses. Run 4-1/2" 13.5# L- 80 Hydril 625 Wedge liner as per tally f/ 10451't/ 11523'. Tq to 9600 fUlbs, install 1 stop ring & 7.5" centralizer on ea. jt. 106K PU / 70K SO. 3 BPH losses. 38.6 bbls total lost while running liner / 2.2 BPH avg. Change to 5" elevators. P/U & M/U 7"x9-5/8" Baker SLZXP liner top packer to 11560'. UD 5" safety joint & XO from safety valve. RIH with 5" drill pipe f/ 11 560' U 11655'. Fill pipe. Obtain parameters: 1 BPM, 120 PSI, 2 BPM, 220 PSI, 3 BPM, 370 PSI. 15 RPM, 4K TQ. 109K PU / 77K SO / 94K ROT. TIH w/ 4- 1/2" liner on 5" DP f/ 11 655' U 12417' out of the derrick. 11 OK PU / 71 K SO. Single in w/ 5" HWDP f/ 12417' U 14200'. 160K PU / 105K SO. 3.5 BPH losses. Daily losses: 55 bbls, Interval total: 344 bbls. 11/20/2019 Swapped to completions Run 4-1/2" 13.5# Hydril 625 L-80 liner on 5" HWDP f/ 14200't/17071'(25K set down @ 14886' and 16718',P/U working thru easily AFE / report ) 151 jts HWDP. 4 bph loss rate. M/U std 5" DP, Tag TD on depth @ 17150', set down 15k to verify on bottom, Verify pipe count. Drop 29/32" phenolic ball, M/U TD, P/U to 250k putting string in tension, 58 BBL losses running liner. PU/SO 250k/140k. R/U test pump and chart recorder. Pump down at 3 BPM, 650 PSI. Slow to 1 BPM, 350 PSI at 337 stks. Ball on seat at 515 stks. Pressure up to 2500 psi and set packer and hold 5 min. S/O 50K, continue to pressure up to 3700 psi with rig pump then swap over to test pump. Pressure up & neutralize pusher tool @ 4363 PSI w/ test pump. Pressure bleed off indicating tool neutralized and ball seat sheared at same time. Bleed off shut in pump pressure and pick up 5.5' to confirm release. Break over w/ 220K PU. Close annular & test annulus x 7" x 9-5/8" packer to 1650 psi for 10 charted min, good test, bleed off pressure, open annular. TOL @ 5600'. Rack 1 stand 5" DP back & blow down injection line & TD, R/D test equipment. Flow check well, 3 bph static loss rate. POOH f/ 5555'V 5370', pump dry job, TOOH to surface, racking 5" DP & HWDP in Derrick. Inspect & L/D running tool. Loss rate 2 bph. Submit 24 hr BOP test notification @ 16:15 hrs;Swap to completions report. Run 4-1/2" 13.5# Hydril 625 L-80 liner to 17150' and set packer. POOH racking back HWDP & drill pipe in the derrick. Notified AOGCC of upcoming BOP test at 16:15 on 20 Nov. 2019. Remove split bushings & install master bushings w/ inserts. Pull wear bushing, M/U XO on 5" drill pipe landing joint, perform tubing hanger dummy run & re -install wear bushing. M/U 3-1/2" wash joint & 8.25" O.D. no-go to 15.82'. TIH w/ 9 stands + single of 5" drill pipe, 50 stands HWDP then one stand of 5" drill pipe to 5615'. 220K PU / 184K SO. Wash down w/ 260 GPM, 450 PSI & tag liner top w/ no-go on depth w/ 5K. Pump 350 GPM, 650 PSI while pulling out of liner tie back. Circulate the 9-5/8" casing clean above the liner top w/ 515 GPM, 1160 PSI, 40 RPM, 5K TQ. 100% increase of sand at bottoms up & cleaned up by second bottoms up. PJSM for displacement. Pump 28 bbl high vis sweep. Perform displacement to 9.0 ppg 2% KCI/NaCl brine. Sweep back on strokes & fluid cleaned up after 80 bbls of interface. No losses. Pumped a total of 454 bbls of brine. Perform 5 min. flow check - static. Obtain new slow pump rates. UD single to 5591'. Slip & cut drilling line. 47' of line cut off. Service top drive, draw works and blocks. 2 BPH static Iosses.,POOH laying down 5" drill pipe & 5" HWDP f/ 5591't/ 5066'. W1 Well Name: Field: County/State: Location (LAT/LONG): Elevation (RKB): API #: Spud Date: Job Name: Contractor AFE #: AFE $: Hilcorp Energy Company Composite Report MP M-15 Milne Point Alaska 1911314C MPU M-15 Completion Doyon 14 Present Activity Date Operations Ops Summary 11/20/2019 POOH laying Run 4-1/2" 13.5# Hydril 625 L-80 liner on 5" HWDP f/ 14200't/17071' ( 25K set down @ 14886' and 16718',P/U working thru down 5" HWDP easily ) 151 jts HWDP. 4 bph loss rate. M/U std 5" DP, Tag TD on depth @ 17150', set down 15k to verify on bottom, Verify at 5066' pipe count, Drop 29/32" phenolic ball, M/U TD, P/U to 250k putting string in tension, 58 BBL losses running liner. PU/SO 250k/140k. R/U test pump and chart recorder. Pump down at 3 BPM, 650 PSI. Slow to 1 BPM, 350 PSI at 337 stks. Ball on seat at 515 stks. Pressure up to 2500 psi and set packer and hold 5 min. S/O 50K, continue to pressure up to 3700 psi with rig pump then swap over to test pump. Pressure up & neutralize pusher tool @ 4363 PSI w/ test pump. Pressure bleed off indicating tool neutralized and ball seat sheared at same time. Bleed off shut in pump pressure and pick up 5.5' to confirm release. Break over w/ 220K PU. Close annular & test annulus x 7" x 9-5/8" packer to 1650 psi for 10 charted min, good test, bleed off pressure, open annular. TOL @ 5600'. Rack 1 stand 5" DP back & blow down injection line & TD, R/D test equipment. Flow check well, 3 bph static loss rate. POOH f/ 5555't/ 5370', pump dry job, TOOH to surface, racking 5" DP & HWDP in Derrick. Inspect & L/D running tool. Loss rate 2 bph. Submit 24 hr BOP test notification @ 16:15 hrs;Swap to completions report. Run 4-1/2" 13.5# Hydril 625 L-80 liner to 17150' and set packer. POOH racking back HWDP & drill pipe in the derrick. Notified AOGCC of upcoming BOP test at 16:15 on 20 Nov. 2019. Remove split bushings & install master bushings w/ inserts. Pull wear bushing, M/U XO on 5" drill pipe landing joint, perform tubing hanger dummy run & re -install wear bushing. M/U 3-1/2" wash joint & 8.25" O.D. no-go to 15.82'. TIH w/ 9 stands + single of 5" drill pipe, 50 stands HWDP then one stand of 5" drill pipe to 5615'. 220K PU / 184K SO. Wash down w/ 260 GPM, 450 PSI & tag liner top w/ no-go on depth w/ 5K. Pump 350 GPM, 650 PSI while pulling out of liner tie back. Circulate the 9-5/8" casing clean above the liner top w/ 515 GPM, 1160 PSI, 40 RPM, 5K TQ. 100% increase of sand at bottoms up & cleaned up by second bottoms up. PJSM for displacement. Pump 28 bbl high vis sweep. Perform displacement to 9.0 ppg 2% KCI/NaCl brine. Sweep back on strokes & fluid cleaned up after 80 bbls of interface. No losses. Pumped a total of 454 bbls of brine. Perform 5 min. flow check - static. Obtain new slow pump rates. L/D single to 5591'. Slip & cut drilling line. 47' of line cut off. Service top drive, draw works and blocks. 2 BPH static losses. POOH laying down 5" drill pipe & 5" HWDP f/ 5591't/ 5066'. 11/21/2019 Running 3-1/2" TOOH L/D 5" HWDP f/ 5066' t/ surface, L/D NO-GO and wash tool 18 bbl losses on TOOK Submit 24 hr notification to AOGCC tubing at 4363' for upcoming MIT. Pull 9" ID wear bushing, clear rig floor, R/U to test BOP equipment: install test plug and 3-1/2"" test joint. Fill stack, choke and all lines with fresh water. Perform shell test, good. Test BOP equipment as per PTD & AOGCC requirements. All tests performed against a test plug with fresh water for 5 min. each 250 PSI low / 3000 PSI high & charted. #1: Annular on (�� 3.5" test joint, valves 1, 12, 13, 14, & 3" kill Demco, upper IBOP. #2: Upper rams, choke valves 9, 11, HCR kill, lower IBOP #3: �✓ Choke valves 5,8,10, manual kill, 5" TIW #1. #4: Choke valves 4,6,5,7, 5" dart. #5: Choke valve 2. #6: HCR choke. #7: Manual choke. #8: Lower rams w/ 3.5" test jt. Perform accumulator drawdown test. System= 3000 psi, after closure 1600 psi, 200 psi in 38 sec, full pressure in 187 sec. N2 bottle avg 2025 psi. #9: Blind rams, choke valve3 #10: Hyd choke A. #11: Manual choke B. Rig electrician tested gas alarms. AOGCC rep Guy Cook witnessed test. R/D test equipment & pull test plug. Blow down choke lines, kill line & top drive. Clear rig floor of test equipment. Monitor well on trip tank. Mobilize 3-1/2" completion equipment to the rig floor: casing tongs, Cannon clamps, TEC spool. R/U TEC spool & sheave, Doyon double stack tongs, slips & elevators. PJSM for running tubing. Review well control plan w/ TEC wire across BOPs. AOGCC inspector Guy Cook waived witness of the upcoming MIT at 20:40 on 21 Nov 2019. M/U Baker 7.38" ported bullet seal assy to 18'. Run 11 joints of 3.5" 9.3# EUE L-80 tubing to 352'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. M/U Baker gauge carrier assy to 373'. Install Zenith gauge (S/N P5539) w/ gauge retaining clamp & connect to TEC wire. Test gauge - good. Run 3.5" 9.3# EUE L-80 tubing from 352' t/ 4363'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. Install Cannon clamps on TEC wire first 10 connections, then every other joint. Also above & below XN & X nipples. Check Zenith gauge every 1000'. 11/22/2019 Rigging down / Run 3-1/2" 9.3# EUE L-80 tubing from 4363' to 5553' atjt 179, M/U 3 more jts, see seals entering TOL, NO GO out on TOL @ Preparing for rig 5608' with EOP @ 5618' setting down 5k, L/D 4 jts tbg to 5520', space out as per Baker rep with 2- 8' and 1 -10' pup jts, M/U jt move 179, hanger and landing jt, 14 bbl losses on TIH. PU/SO 76K / 70K, Centralift get final reading and terminate tech wire thru hanger. Drain stack RIH with hanger to 2' above landing mark. R/U, circ sub and 5' pup jt. close bag and pressure up to 400 psi. P/U until pressure dumped plus 6". Test lines to 1000 psi. 93 full cannon clamps ran. PJSM. Reverse circulate 203 bbls �i corrosion inhibited 9 ppg brine @ 4 BPM, 450 PSI. Pump down OA taking returns out of the 3 1/2" tbg, line up and reverse circ 160 bbls diesel from vac truck 4 bpm, 450 psi ICP freeze protecting 9-5/8" x 3-1/2" annulus to 2500' FCP 770 psi, S/O closing +p L ports, drain stack to cellar. Land hanger w/ Sok on hanger, EOP @ 5615.21'( 2.76' off NO GO ) RILDS, R/D lines f/ pump in sub and XO, R/U test equipment, pre-injection MIT 3 1/2" x 9 5/8"" annulus with diesel to 2500 psi for 30 charted min. Good test. bleed off pressure. AOGCC representative Guy Cook waived witness for MIT on 11/21/19 @ 20:40. R/D test equipment, blow down lines, back out and L/D landing jt, WH rep install BPV. L/D mouse holes. PJSM, remove both mouseholes, remove MPD drip pan, pull trip nipple, remove kill line, N/D BOPs & rack back on stump. Notified AOGCC of upcoming diverter test on M-26 at 18:32 on 22 Nov 2019. Clean hanger void, install adapter flange and perform TEC wire penetration. Baker representative took final gauge readings. NIU tree and tighten all bolts. Test hanger void to 500 PSI low for 5 min & 5000 PSI high for 10 min. R/U test equipment. Test tree with diesel to 250 PSI low 5 min. and 5000 PSI high 10 min. R/D test equipment & R/U to freeze protect 3-1/2" tubing. Bullhead 30 bbls diesel down the tubing thorugh BPV @ 2 BPM, 560 ICP, 1050 FCP. Freeze protect to 3450' MD. Release rig f/ M-15 @ 03:00. Flush mud pumps with water. Blow down lines. Suck out cellar and cuttings tank. Disconnect rockwasher & fuel trailer. Move fuel trailer. Preparing for rig move. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-15 500292365300 :Sperry Drilling Definitive Survey Report 26 November, 2019 ALL.IBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M-1 5i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA 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 Well MPU M -15i Well Position +N/ -S 0.00 usft Northing: 6,027,765.69 usft Latitude: 70° 29' 12.784 N +EI -W 0.00 usft Easting: 533,813.87 usft Longitude: 149'43'25.061 W Position Uncertainty 0.50 usft Wellhead Elevation: 0.00 usft Ground Level: 24.70 usft Wellbore MPU M-15 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1) (1) (nT) BGGM2018 11/12/2019 16.37 80.94 57,407.89257023 Design MPU M -15i Date 11/18/2019 Audit Notes: From To Version: 1.0 Phase: ACTUAL Tie On Depth: 6,294.84 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction 5,721.79 MPU M-15PB1 MWD+IFR2+MS+Sag (1) (usft) (usft) (usft) (1) 5,818.31 33.94 0.00 0.00 125.00 Survey Program Date 11/18/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 161.93 5,721.79 MPU M-15PB1 MWD+IFR2+MS+Sag (1) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 10/28/2019 5,818.31 6,294.84 MPU M-15PB1 MWD+IFR2+MS+Sag (2) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 11/06/2019 6,380.00 17,081.25 MPU M-15 MWD+IFR2+MS+Sag (3) (MP 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 11/12/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 33.94 0.00 0.00 33.94 -24.70 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 UNDEFINED 161.93 0.25 243.95 161.93 103.29 -0.12 -0.25 6,027,765.57 533,813.62 0.20 -0.14 3_MWD+IFR2+MS+Sag (1) 209.01 0.24 252.35 209.01 150.37 -0.20 -0.44 6,027,765.49 533,813.43 0.08 -0.24 3_MWD+IFR2+MS+Sag (1) 301.41 0.79 265.97 301.41 242.77 -0.30 -1.26 6,027,765.38 533,812.61 0.61 -0.86 3_MWD+IFR2+MS+Sag (1) 395.27 1.20 190.22 395.25 336.61 -1.31 -2.08 6,027,764.37 533,811.80 1.35 -0.95 3_MWD+IFR2+MS+Sag (1) 489.12 2.80 163.96 489.05 430.41 -4.48 -1.62 6,027,761.20 533,812.27 1.92 1.25 3_MWD+IFR2+MS+Sag (1) 581.71 5.65 156.46 581.38 522.74 -10.84 0.83 6,027,754.86 533,814.75 3.13 6.89 3_MWD+IFR2+MS+Sag (1) 674.63 9.45 152.69 673.47 614.83 -21.81 6.16 6,027,743.91 533,820.13 4.12 17.55 3_MWD+IFR2+MS+Sag(1) 770.53 11.83 151.53 767.72 709.08 -37.45 14.46 6,027,728.31 533,828.49 2.49 33.32 3_MWD+IFR2+MS+Sag (1) 863.35 15.12 152.70 857.97 799.33 -56.58 24.55 6,027,709.23 533,838.67 3.56 52.56 3_MWD+IFR2+MS+Sag (1) 957.64 18.38 152.04 948.25 889.61 -80.64 37.16 6,027,685.22 533,851.39 3.46 76.69 3_MWD+IFR2+MS+Sag (1) 1,054.45 21.48 152.50 1,039.25 980.61 -109.85 52.50 6,027,656.09 533,866.87 3.21 106.02 3_MWD+IFR2+MS+Sag (1) 11/26/2019 3:45.27PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M -15i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA Survey 11/26/2019 3:45:27PM Page 3 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,151.92 25.42 152.68 1,128.65 1,070.01 -144.28 70.35 6,027,621.74 533,884.87 4.04 140.39 3_MWD+IFR2+MS+Sag (1) 1,247.13 26.35 153.88 1,214.31 1,155.67 -181.41 89.03 6,027,584.70 533,903.72 1.12 176.99 3_MWD+IFR2+MS+Sag (1) 1,340.61 29.09 152.49 1,297.05 1,238.41 -220.20 108.67 6,027,546.01 533,923.53 3.01 215.32 3_MWD+IFR2+MS+Sag(1) 1,436.69 31.70 152.18 1,379.92 1,321.28 -263.25 131.24 6,027,503.07 533,946.29 2.72 258.50 3_MWD+IFR2+MS+Sag (1) 1,530.94 34.45 152.61 1,458.89 1,400.25 -308.83 155.07 6,027,457.60 533,970.32 2.93 304.16 3_MWD+IFR2+MS+Sag (1) 1,626.98 36.31 153.23 1,537.19 1,478.55 -358.34 180.37 6,027,408.21 533,995.85 1.97 353.29 3_MWD+IFR2+MS+Sag (1) 1,722.61 39.05 153.10 1,612.87 1,554.23 410.49 206.76 6,027,356.18 534,022.47 2.87 404.82 3_MWD+IFR2+MS+Sag (1) 1,816.51 42.84 152.03 1,683.78 1,625.14 -465.09 235.13 6,027,301.72 534,051.08 4.10 459.37 3_MWD+IFR2+MS+Sag (1) 1,912.84 48.01 149.89 1,751.37 1,692.73 -525.02 268.47 6,027,241.94 534,084.70 5.59 521.06 3_MWD+IFR2+MS+Sag (1) 2,007.45 48.93 149.63 1,814.10 1,755.46 -586.21 304.14 6,027,180.93 534,120.64 0.99 585.37 3_MWD+IFR2+MS+Sag (1) 2,102.96 48.40 149.60 1,877.18 1,818.54 -648.07 340.41 6,027,119.23 534,157.19 0.56 650.57 3_MWD+IFR2+MS+Sag (1) 2,198.67 49.21 150.81 1,940.22 1,881.58 -710.57 376.19 6,027,056.91 534,193.25 1.27 715.73 3_MWD+IFR2+MS+Sag(1) 2,293.63 49.54 151.61 2,002.05 1,943.41 -773.74 410.90 6,026,993.91 534,228.24 0.73 780.39 3_MWD+IFR2+MS+Sag (1) 2,389.17 48.84 152.34 2,064.49 2,005.85 -837.57 444.88 6,026,930.24 534,262.51 0.93 844.83 3_MWD+IFR2+MS+Sag (1) 2,484.52 48.03 152.61 2,127.75 2,069.11 -900.83 477.85 6,026,867.13 534,295.76 0.88 908.13 3_MWD+IFR2+MS+Sag(1) 2,579.07 49.49 151.11 2,190.08 2,131.44 -963.52 511.39 6,026,804.60 534,329.58 1.95 971.55 3_MWD+IFR2+MS+Sag (1) 2,673.84 49.71 151.62 2,251.50 2,192.86 -1,026.86 545.97 6,026,741.42 534,364.45 0.47 1,036.22 3_MWD+IFR2+MS+Sag (1) 2,769.53 49.49 152.36 2,313.52 2,254.88 -1,091.19 580.20 6,026,677.25 534,398.96 0.63 1,101.15 3_MWD+IFR2+MS+Sag (1) 2,865.11 50.82 151.04 2,374.76 2,316.12 -1,155.80 614.99 6,026,612.81 534,434.05 1.75 1,166.71 3_MWD+IFR2+MS+Sag(1) 2,959.05 50.29 151.11 2,434.44 2,375.80 -1,219.29 650.08 6,026,549.49 534,469.42 0.57 1,231.87 3_MWD+IFR2+MS+Sag (1) 3,055.28 49.45 149.56 2,496.47 2,437.83 -1,283.22 686.49 6,026,485.73 534,506.11 1.51 1,298.36 3_MWD+IFR2+MS+Sag (1) 3,149.82 49.77 150.44 2,557.73 2,499.09 -1,345.58 722.49 6,026,423.54 534,542.40 0.79 1,363.62 3_MWD+IFR2+MS+Sag (1) 3,245.15 49.90 150.00 2,619.22 2,560.58 -1,408.81 758.67 6,026,360.48 534,578.86 0.38 1,429.53 3_MWD+IFR2+MS+Sag (1) 3,340.66 49.34 150.98 2,681.09 2,622.45 -1,472.13 794.51 6,026,297.34 534,614.99 0.98 1,495.20 3_MWD+IFR2+MS+Sag (1) 3,435.73 48.76 150.93 2,743.40 2,684.76 -1,534.90 829.37 6,026,234.73 534,650.13 0.61 1,559.76 3_MWD+IFR2+MS+Sag (1) 3,529.67 49.27 150.52 2,805.01 2,746.37 -1,596.76 864.05 6,026,173.03 534,685.08 0.64 1,623.65 3_MWD+IFR2+MS+Sag (1) 3,626.79 50.26 150.56 2,867.74 2,809.10 -1,661.31 900.51 6,026,108.65 534,721.84 1.02 1,690.54 3_MWD+IFR2+MS+Sag (1) 3,721.75 50.36 150.81 2,928.39 2,869.75 -1,725.03 936.29 6,026,045.11 534,757.90 0.23 1,756.40 3_MWD+IFR2+MS+Sag(1) 3,817.03 50.02 151.30 2,989.39 2,930.75 -1,789.07 971.71 6,025,981.23 534,793.61 0.53 1,822.15 3_MWD+IFR2+MS+Sag (1) 3,912.06 50.58 151.06 3,050.09 2,991.45 -1,853.13 1,006.96 6,025,917.34 534,829.14 0.62 1,887.76 3_MWD+IFR2+MS+Sag (1) 4,007.51 49.70 151.29 3,111.27 3,052.63 -1,917.32 1,042.28 6,025,853.31 534,864.76 0.94 1,953.52 3_MWD+IFR2+MS+Sag (1) 4,103.15 50.29 150.46 3,172.75 3,114.11 -1,981.32 1,077.94 6,025,789.49 534,900.70 0.91 2,019.43 3_MWD+IFR2+MS+Sag (1) 4,198.17 50.09 150.06 3,233.59 3,174.95 -2,044.69 1,114.15 6,025,726.28 534,937.19 0.39 2,085.45 3_MWD+IFR2+MS+Sag (1) 4,293.04 49.71 149.47 3,294.70 3,236.06 -2,107.39 1,150.69 6,025,663.76 534,974.01 0.62 2,151.34 3_MWD+IFR2+MS+Sag (1) 4,388.04 49.21 149.90 3,356.44 3,297.80 -2,169.71 1,187.13 6,025,601.61 535,010.74 0.63 2,216.94 3_MWD+IFR2+MS+Sag (1) 4,482.70 49.80 150.65 3,417.91 3,359.27 -2,232.23 1,222.82 6,025,539.27 535,046.71 0.87 2,282.03 3_MWD+IFR2+MS+Sag (1) 4,578.22 52.66 149.97 3,477.72 3,419.08 -2,296.91 1,259.71 6,025,474.76 535,083.89 3.05 2,349.35 3_MWD+IFR2+MS+Sag (1) 4,673.76 57.33 148.11 3,532.52 3,473.88 -2,363.98 1,299.99 6,025,407.88 535,124.46 5.14 2,420.81 3_MWD+IFR2+MS+Sag(1) 4,768.59 60.17 144.41 3,581.72 3,523.08 -2,431.35 1,345.03 6,025,340.72 535,169.81 4.48 2,496.35 3_MWD+IFR2+MS+Sag (1) 4,864.58 61.88 139.36 3,628.24 3,569.60 -2,497.36 1,396.86 6,025,274.95 535,221.93 4.93 2,576.67 3_MWD+IFR2+MS+Sag (1) 11/26/2019 3:45:27PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M -15i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA Survey 11/26/2019 3:45:27PM Page 4 COMPASS 5000.15 Build 91 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 4,959.59 63.61 134.45 3,671.77 3,613.13 -2,558.99 1,454.56 6,025,213.59 535,279.91 4.94 2,659.28 3_MWD+IFR2+MS+Sag (1) 5,055.48 64.74 133.58 3,713.54 3,654.90 -2,618.96 1,516.63 6,025,153.91 535,342.25 1.43 2,744.53 3_MWD+IFR2+MS+Sag (1) 5,151.03 68.90 132.06 3,751.15 3,692.51 -2,678.63 1,581.06 6,025,094.54 535,406.93 4.59 2,831.53 3_MWD+IFR2+MS+Sag (1) 5,244.27 74.50 131.25 3,780.41 3,721.77 -2,737.44 1,647.18 6,025,036.04 535,473.32 6.06 2,919.42 3_MWD+IFR2+MS+Sag (1) 5,339.91 80.33 129.15 3,801.24 3,742.60 -2,797.64 1,718.45 6,024,976.16 535,544.85 6.46 3,012.34 3_MWD+IFR2+MS+Sag (1) 5,434.99 81.33 125.42 3,816.40 3,757.76 -2,854.49 1,793.12 6,024,919.66 535,619.77 4.01 3,106.11 3_MWD+IFR2+MS+Sag (1) 5,530.38 80.95 124.38 3,831.09 3,772.45 -2,908.42 1,870.42 6,024,866.09 535,697.31 1.15 3,200.36 3_MWD+IFR2+MS+Sag (1) 5,625.49 84.74 125.25 3,842.94 3,784.30 -2,962.29 1,947.88 6,024,812.58 535,775.01 4.09 3,294.71 3_MWD+IFR2+MS+Sag (1) 5,721.79 86.17 125.09 3,850.57 3,791.93 -3,017.58 2,026.35 6,024,757.65 535,853.72 1.49 3,390.70 3_MWD+IFR2+MS+Sag(1) 5,818.31 87.67 126.13 3,855.75 3,797.11 -3,073.70 2,104.71 6,024,701.90 535,932.32 1.89 3,487.07 3_MWD+IFR2+MS+Sag (2) 5,915.13 87.48 126.89 3,859.85 3,801.21 -3,131.25 2,182.45 6,024,644.70 536,010.32 0.81 3,583.77 3_MWD+IFR2+MS+Sag (2) 6,010.30 87.04 124.43 3,864.40 3,805.76 -3,186.66 2,259.68 6,024,589.65 536,087.80 2.62 3,678.82 3_MWD+IFR2+MS+Sag (2) 6,105.28 90.27 127.96 3,866.63 3,807.99 -3,242.72 2,336.29 6,024,533.94 536,164.65 5.04 3,773.73 3_MWD+IFR2+MS+Sag (2) 6,200.66 86.36 128.67 3,869.44 3,810.80 -3,301.82 2,411.08 6,024,475.19 536,239.70 4.17 3,868.89 3_MWD+IFR2+MS+Sag (2) 6,294.84 87.11 125.64 3,874.80 3,816.16 -3,358.60 2,486.01 6,024,418.76 536,314.88 3.31 3,962.83 3_MWD+IFR2+MS+Sag (2) 6,380.00 87.06 122.75 3,879.13 3,820.49 -3,406.39 2,556.35 6,024,371.29 536,385.43 3.39 4,047.87 3_MWD+IFR2+MS+Sag (3) 6,388.40 86.73 122.43 3,879.59 3,820.95 -3,410.91 2,563.42 6,024,366.80 536,392.51 5.47 4,056.25 3_MWD+IFR2+MS+Sag (3) 6,483.79 86.68 123.82 3,885.07 3,826.43 -3,462.95 2,643.17 6,024,315.13 536,472.50 1.46 4,151.43 3_MWD+IFR2+MS+Sag (3) 6,580.06 89.95 124.99 3,887.90 3,829.26 -3,517.32 2,722.55 6,024,261.13 536,552.12 3.61 4,247.63 3_MWD+IFR2+MS+Sag (3) 6,675.07 90.38 125.13 3,887.63 3,828.99 -3,571.89 2,800.32 6,024,206.92 536,630.13 0.48 4,342.64 3_MWD+IFR2+MS+Sag (3) 6,769.06 91.68 125.34 3,885.94 3,827.30 -3,626.11 2,877.08 6,024,153.06 536,707.12 1.40 4,436.62 3_MWD+IFR2+MS+Sag (3) 6,866.24 91.06 124.84 3,883.61 3,824.97 -3,681.96 2,956.57 6,024,097.57 536,786.86 0.82 4,533.77 3_MWD+IFR2+MS+Sag (3) 6,961.11 91.00 125.96 3,881.91 3,823.27 -3,736.90 3,033.89 6,024,042.99 536,864.42 1.18 4,628.62 3_MWD+IFR2+MS+Sag (3) 7,056.56 91.31 123.70 3,879.98 3,821.34 -3,791.41 3,112.22 6,023,988.85 536,942.99 2.39 4,724.04 3_MWD+IFR2+MS+Sag (3) 7,151.75 89.70 120.14 3,879.15 3,820.51 -3,841.72 3,193.00 6,023,938.90 537,023.98 4.10 4,819.07 3_MWD+IFR2+MS+Sag (3) 7,247.87 91.25 120.53 3,878.35 3,819.71 -3,890.27 3,275.95 6,023,890.74 537,107.15 1.66 4,914.87 3_MWD+1FR2+MS+Sag (3) 7,340.87 90.13 122.36 3,877.23 3,818.59 -3,938.78 3,355.28 6,023,842.60 537,186.69 2.31 5,007.68 3_MWD+IFR2+MS+Sag (3) 7,437.65 87.91 122.30 3,878.88 3,820.24 -3,990.52 3,437.04 6,023,791.23 537,268.68 2.29 5,104.33 3_MWD+IFR2+MS+Sag (3) 7,533.51 88.59 123.32 3,881.81 3,823.17 -4,042.44 3,517.57 6,023,739.68 537,349.44 1.28 5,200.07 3_MWD+IFR2+MS+Sag (3) 7,628.32 91.62 125.51 3,881.64 3,823.00 -4,096.02 3,595.77 6,023,686.47 537,427.87 3.94 5,294.86 3_MWD+IFR2+MS+Sag (3) 7,724.00 91.74 125.06 3,878.83 3,820.19 -4,151.26 3,673.84 6,023,631.58 537,506.18 0.49 5,390.50 3_MWD+IFR2+MS+Sag (3) 7,817.15 91.80 125.10 3,875.96 3,817.32 -4,204.77 3,750.03 6,023,578.43 537,582.61 0.08 5,483.61 3_MWD+IFR2+MS+Sag (3) 7,914.22 91.06 124.96 3,873.53 3,814.89 -4,260.47 3,829.50 6,023,523.09 537,662.32 0.78 5,580.64 3_MWD+IFR2+MS+Sag (3) 8,010.29 90.75 125.38 3,872.02 3,813.38 4,315.80 3,908.02 6,023,468.13 537,741.08 0.54 5,676.70 3_MWD+IFR2+MS+Sag (3) 8,104.28 92.05 126.21 3,869.72 3,811.08 4,370.76 3,984.23 6,023,413.52 537,817.53 1.64 5,770.65 3_MWD+IFR2+MS+Sag (3) 8,198.05 89.75 125.71 3,868.25 3,809.61 -4,425.81 4,060.11 6,023,358.82 537,893.66 2.51 5,864.39 3_MWD+IFR2+MS+Sag (3) 8,294.60 89.64 126.39 3,868.76 3,810.12 -4,482.63 4,138.17 6,023,302.37 537,971.97 0.71 5,960.92 3_MWD+1FR2+MS+Sag (3) 8,390.00 91.12 126.54 3,868.13 3,809.49 4,539.32 4,214.89 6,023,246.02 538,048.94 1.56 6,056.29 3_MWD+IFR2+MS+Sag (3) 8,485.30 91.43 126.67 3,866.01 3,807.37 4,596.14 4,291.38 6,023,189.56 538,125.67 0.35 6,151.53 3_MWD+IFR2+MS+Sag (3) 8,580.25 91.68 126.66 3,863.43 3,804.79 4,652.81 4,367.51 6,023,133.24 538,202.06 0.26 6,246.40 3_MWD+IFR2+MS+Sag (3) 11/26/2019 3:45:27PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M -15i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA Survey 11/26/2019 3:45:27PM Page 5 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N1S +E1 -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,675.49 91.74 127.72 3,860.59 3,801.95 -4,710.35 4,443.35 6,023,076.05 538,278.15 1.11 6,341.53 3_MWD+IFR2+MS+Sag (3) 8,769.84 92.30 125.15 3,857.26 3,798.62 -4,766.35 4,519.20 6,023,020.40 538,354.25 2.79 6,435.78 3_MWD+IFR2+MS+Sag (3) 8,864.54 89.88 123.11 3,855.46 3,796.82 -4,819.47 4,597.57 6,022,967.65 538,432.85 3.34 6,530.44 3_MWD+IFR2+MS+Sag (3) 8,960.15 89.58 121.84 3,855.91 3,797.27 -4,870.80 4,678.22 6,022,916.69 538,513.73 1.36 6,625.95 3_MWD+IFR2+MS+Sag (3) 9,055.36 87.97 123.11 3,857.95 3,799.31 " 4,921.91 4,758.52 6,022,865.95 538,594.25 2.15 6,721.04 3_MWD+1FR2+MS+Sag (3) 9,150.74 87.54 123.94 3,861.68 3,803.04 -4,974.55 4,837.97 6,022,813.68 538,673.93 0.98 6,816.32 3_MWD+IFR2+MS+Sag (3) 9,246.07 87.54 125.99 3,865.78 3,807.14 -5,029.12 4,916.02 6,022,759.46 538,752.22 2.15 6,911.56 3_MWD+IFR2+MS+Sag (3) 9,341.09 87.35 126.16 3,870.01 3,811.37 -5,085.02 4,992.74 6,022,703.92 538,829.19 0.27 7,006.46 3_MWD+IFR2+MS+Sag (3) 9,436.90 87.73 125.64 3,874.12 3,815.48 -5,141.15 5,070.28 6,022,648.15 538,906.97 0.67 7,102.17 3_MWD+IFR2+MS+Sag (3) 9,531.85 87.11 125.88 3,878.40 3,819.76 -5,196.58 5,147.25 6,022,593.08 538,984.19 0.70 7,197.02 3_MWD+IFR2+MS+Sag (3) 9,627.27 88.22 125.07 3,882.28 3,823.64 -5,251.91 5,224.89 6,022,538.11 539,062.07 1.44 7,292.35 3_MWD+IFR2+MS+Sag (3) 9,722.51 89.52 125.20 3,884.16 3,825.52 -5,306.71 5,302.76 6,022,483.67 539,140.18 1.37 7,387.57 3_MWD+1FR2+MS+Sag (3) 9,817.34 89.76 125.86 3,884.76 3,826.12 -5,361.82 5,379.94 6,022,428.92 539,217.60 0.74 7,482.40 3_MWD+IFR2+MS+Sag (3) 9,912.43 89.64 126.01 3,885.26 3,826.62 -5,417.62 5,456.93 6,022,373.47 539,294.83 0.20 7,577.47 3_MWD+IFR2+MS+Sag (3) 10,007.62 90.38 125.91 3,885.24 3,826.60 -5,473.52 5,533.98 6,022,317.93 539,372.13 0.78 7,672.65 3_MWD+IFR2+MS+Sag (3) 10,102.62 90.57 125.46 3,884.45 3,825.81 -5,528.93 5,611.14 6,022,262.87 539,449.53 0.51 7,767.64 3_MWD+IFR2+MS+Sag (3) 10,197.80 90.19 125.31 3,883.82 3,825.18 -5,584.05 5,688.73 6,022,208.12 539,527.37 0.43 7,862.81 3_MWD+IFR2+MS+Sag (3) 10,293.40 89.64 124.87 3,883.96 3,825.32 -5,639.00 5,766.96 6,022,153.52 539,605.83 0.74 7,958.41 3_MWD+IFR2+MS+Sag (3) 10,387.34 88.65 124.38 3,885.36 3,826.72 -5,692.37 5,844.25 6,022,100.51 539,683.36 1.18 8,052.34 3_MWD+IFR2+MS+Sag (3) 10,481.98 90.14 124.85 3,886.36 3,827.72 -5,746.13 5,922.13 6,022,047.11 539,761.48 1.65 8,146.97 3_MWD+IFR2+MS+Sag (3) 10,578.20 89.58 125.24 3,886.60 3,827.96 -5,801.38 6,000.91 6,021,992.22 539,840.49 0.71 8,243.19 3_MWD+IFR2+MS+Sag (3) 10,669.85 89.89 124.74 3,887.02 3,828.38 -5,853.93 6,075.99 6,021,940.02 539,915.81 0.64 8,334.84 3_MWD+IFR2+MS+Sag (3) 10,767.46 92.61 123.68 3,884.89 3,826.25 -5,908.79 6,156.68 6,021,885.53 539,996.74 2.99 8,432.40 3_MWD+IFR2+MS+Sag (3) 10,862.32 92.17 123.17 3,880.94 3,822.30 -5,961.00 6,235.78 6,021,833.69 540,076.07 0.71 8,527.14 3_MWD+IFR2+MS+Sag (3) 10,959.86 91.18 123.67 3,878.09 3,819.45 -6,014.70 6,317.16 6,021,780.36 540,157.68 1.14 8,624.60 3_MWD+IFR2+MS+Sag (3) 11,055.46 90.87 123.75 3,876.38 3,817.74 -6,067.75 6,396.67 6,021,727.68 540,237.43 0.33 8,720.16 3_MWD+IFR2+MS+Sag (3) 11,150.66 89.95 124.95 3,875.70 3,817.06 -6,121.46 6,475.27 6,021,674.33 540,316.26 1.59 8,815.35 3_MWD+IFR2+MS+Sag (3) 11,243.34 89.45 125.45 3,876.18 3,817.54 -6,174.88 6,551.00 6,021,621.26 540,392.23 0.76 8,908.03 3_MWD+IFR2+MS+Sag (3) 11,337.32 89.95 126.35 3,876.67 3,818.03 -6,229.99 6,627.12 6,021,566.51 540,468.59 1.10 9,002.00 3_MWD+IFR2+MS+Sag (3) 11,435.52 89.08 126.30 3,877.50 3,818.86 -6,288.16 6,706.24 6,021,508.71 540,547.96 0.89 9,100.17 3_MWD+IFR2+MS+Sag (3) 11,530.46 87.91 124.49 3,880.00 3,821.36 -6,343.13 6,783.60 6,021,454.09 540,625.56 2.27 9,195.07 3_MWD+IFR2+MS+Sag (3) 11,624.87 89.27 124.35 3,882.32 3,823.68 -6,396.47 6,861.45 6,021,401.11 540,703.65 1.45 9,289.44 3_MWD+IFR2+MS+Sag (3) 11,720.74 88.84 125.19 3,883.90 3,825.26 -6,451.14 6,940.19 6,021,346.81 540,782.63 0.98 9,385.30 3_MWD+IFR2+MS+Sag (3) 11,815.18 88.59 125.40 3,886.02 3,827.38 -6,505.69 7,017.25 6,021,292.61 540,859.94 0.35 9,479.71 3_MWD+IFR2+MS+Sag (3) 11,911.21 88.78 125.50 3,888.22 3,829.58 -6,561.37 7,095.46 6,021,237.29 540,938.39 0.22 9,575.71 3_MWD+IFR2+MS+Sag (3) 12,006.47 89.21 126.06 3,889.89 3,831.25 -6,617.06 7,172.73 6,021,181.96 541,015.90 0.74 9,670.95 3_MWD+IFR2+MS+Sag (3) 12,100.21 89.76 125.63 3,890.74 3,832.10 -6,671.95 7,248.71 6,021,127.42 541,092.13 0.74 9,764.67 3_MWD+IFR2+MS+Sag (3) 12,196.59 89.14 125.45 3,891.66 3,833.02 -6,727.97 7,327.13 6,021,071.76 541,170.79 0.67 9,861.04 3_MWD+IFR2+MS+Sag (3) 12,292.35 88.90 122.72 3,893.30 3,834.66 -6,781.63 7,406.42 6,021,018.47 541,250.32 2.86 9,956.77 3_MWD+IFR2+MS+Sag (3) 12,387.22 87.73 122.32 3,896.09 3,837.45 -6,832.60 7,486.38 6,020,967.87 541,330.50 1.30 10,051.51 3_MWD+IFR2+MS+Sag (3) 11/26/2019 3:45:27PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-1 5i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M-1 5i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA Survey 11/26/2019 3:45:27PM Page 6 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) IN (ft) (°1100') (ft) Survey Tool Name 12,482.29 86.24 122.64 3,901.09 3,842.45 -6,883.58 7,566.47 6,020,917.25 541,410.81 1.60 10,146.35 3_MWD+IFR2+MS+Sag (3) 12,577.57 86.24 124.50 3,907.34 3,848.70 -6,936.15 7,645.68 6,020,865.05 541,490.25 1.95 10,241.39 3_MWD+IFR2+MS+Sag (3) 12,670.59 86.74 126.40 3,913.03 3,854.39 -6,990.00 7,721.31 6,020,811.55 541,566.12 2.11 10,334.23 3_MWD+IFR2+MS+Sag (3) 12,767.89 86.49 126.28 3,918.78 3,860.14 -7,047.56 7,799.55 6,020,754.36 541,644.61 0.28 10,431.33 3_MWD+IFR2+MS+Sag (3) 12,861.65 87.36 126.52 3,923.81 3,865.17 -7,103.12 7,874.91 6,020,699.15 541,720.21 0.96 10,524.93 3_MWD+IFR2+MS+Sag (3) 12,958.38 88.59 126.69 3,927.23 3,868.59 -7,160.76 7,952.51 6,020,641.86 541,798.07 1.28 10,621.56 3_MWD+IFR2+MS+Sag (3) 13,054.49 87.85 126.06 3,930.21 3,871.57 -7,217.73 8,029.86 6,020,585.25 541,875.66 1.01 10,717.59 3_MWD+IFR2+MS+Sag (3) 13,149.98 87.04 125.74 3,934.47 3,875.83 -7,273.67 8,107.13 6,020,529.67 541,953.18 0.91 10,812.98 3_MWD+IFR2+MS+Sag (3) 13,244.90 88.10 125.41 3,938.49 3,879.85 -7,328.84 8,184.26 6,020,474.86 542,030.56 1.17 10,907.80 3_MWD+IFR2+MS+Sag (3) 13,339.06 88.47 125.01 3,941.31 3,882.67 -7,383.10 8,261.16 6,020,420.95 542,107.70 0.58 11,001.92 3_MWD+IFR2+MS+Sag (3) 13,434.77 88.65 124.18 3,943.72 3,885.08 -7,437.43 8,339.92 6,020,366.99 542,186.69 0.89 11,097.60 3_MWD+IFR2+MS+Sag (3) 13,529.63 88.65 122.29 3,945.95 3,887.31 -7,489.40 8,419.24 6,020,315.38 542,266.24 1.99 11,192.38 3_MWD+IFR2+MS+Sag (3) 13,624.71 87.66 120.73 3,949.01 3,890.37 -7,539.07 8,500.26 6,020,266.09 542,347.47 1.94 11,287.23 3_MWD+IFR2+MS+Sag (3) 13,720.26 88.04 121.98 3,952.60 3,893.96 -7,588.75 8,581.79 6,020,216.78 542,429.23 1.37 11,382.52 3_MWD+IFR2+MS+Sag (3) 13,815.54 89.89 123.36 3,954.32 3,895.68 -7,640.17 8,661.98 6,020,165.73 542,509.64 2.42 11,477.70 3_MWD+IFR2+MS+Sag (3) 13,910.06 91.31 126.90 3,953.33 3,894.69 -7,694.55 8,739.26 6,020,111.71 542,587.16 4.04 11,572.20 3_MWD+IFR2+MS+Sag (3) 14,005.68 90.50 127.14 3,951.82 3,893.18 -7,752.11 8,815.60 6,020,054.50 542,663.75 0.88 11,667.74 3_MWD+IFR2+MS+Sag (3) 14,100.05 89.95 127.31 3,951.45 3,892.81 -7,809.20 8,890.74 6,019,997.76 542,739.14 0.61 11,762.04 3_MWD+IFR2+MS+Sag (3) 14,195.29 91.31 126.90 3,950.40 3,891.76 -7,866.65 8,966.69 6,019,940.66 542,815.35 1.49 11,857.21 3_MWD+IFR2+MS+Sag (3) 14,290.71 92.85 126.43 3,946.94 3,888.30 -7,923.59 9,043.18 6,019,884.08 542,892.09 1.69 11,952.52 3_MWD+IFR2+MS+Sag (3) 14,386.06 88.96 124.33 3,945.43 3,886.79 -7,978.78 9,120.89 6,019,829.25 542,970.04 4.64 12,047.84 3_MWD+IFR2+MS+Sag (3) 14,481.55 87.85 122.33 3,948.09 3,889.45 -8,031.22 9,200.64 6,019,777.17 543,050.02 2.39 12,143.24 3_MWD+IFR2+MS+Sag (3) 14,577.10 87.97 122.72 3,951.57 3,892.93 -8,082.56 9,281.15 6,019,726.20 543,130.75 0.43 12,238.64 3_MWD+IFR2+MS+Sag (3) 14,672.29 87.04 125.61 3,955.72 3,897.08 -8,135.96 9,359.83 6,019,673.17 543,209.67 3.19 12,333.72 3_MWD+IFR2+MS+Sag (3) 14,767.71 89.89 128.01 3,958.28 3,899.64 -8,193.10 9,436.18 6,019,616.38 543,286.27 3.90 12,429.04 3_MWD+IFR2+MS+Sag (3) 14,862.94 89.39 128.44 3,958.87 3,900.23 -8,252.02 9,510.99 6,019,557.80 543,361.34 0.69 12,524.12 3_MWD+IFR2+MS+Sag (3) 14,958.37 89.14 128.19 3,960.10 3,901.46 -8,311.18 9,585.86 6,019,498.99 543,436.47 0.37 12,619.38 3_MWD+IFR2+MS+Sag (3) 15,053.44 90.01 126.29 3,960.80 3,902.16 -8,368.71 9,661.54 6,019,441.81 543,512.40 2.20 12,714.37 3_MWD+IFR2+MS+Sag (3) 15,148.26 91.00 125.15 3,959.97 3,901.33 -8,424.07 9,738.52 6,019,386.81 543,589.62 1.59 12,809.17 3_MWD+IFR2+MS+Sag (3) 15,242.75 90.50 125.62 3,958.73 3,900.09 -8,478.78 9,815.55 6,019,332.46 543,666.89 0.73 12,903.65 3_MWD+IFR2+MS+Sag (3) 15,338.47 90.01 125.63 3,958.30 3,899.66 -8,534.53 9,893.35 6,019,277.07 543,744.94 0.51 12,999.37 3_MWD+IFR2+MS+Sag (3) 15,433.36 93.04 125.52 3,955.78 3,897.14 -8,589.71 9,970.50 6,019,222.24 543,822.33 3.20 13,094.21 3_MWD+IFR2+MS+Sag (3) 15,529.40 92.54 124.66 3,951.11 3,892.47 -8,644.85 10,048.99 6,019,167.46 543,901.06 1.03 13,190.13 3_MWD+IFR2+MS+Sag (3) 15,624.31 89.58 123.72 3,949.35 3,890.71 -8,698.17 10,127.47 6,019,114.51 543,979.78 3.27 13,285.00 3_MWD+IFR2+MS+Sag (3) 15,718.92 89.39 123.54 3,950.20 3,891.56 -8,750.57 10,206.24 6,019,062.48 544,058.78 0.28 13,379.58 3_MWD+IFR2+MS+Sag (3) 15,813.51 90.63 123.68 3,950.18 3,891.54 -8,802.92 10,285.02 6,019,010.48 544,137.79 1.32 13,474.14 3_MWD+IFR2+MS+Sag (3) 15,909.29 90.32 123.61 3,949.39 3,890.75 -8,855.99 10,364.75 6,018,957.79 544,217.75 0.33 13,569.89 3_MWD+IFR2+MS+Sag (3) 16,003.19 89.27 123.28 3,949.73 3,891.09 -8,907.74 10,443.10 6,018,906.40 544,296.33 1.17 13,663.76 3_MWD+IFR2+MS+Sag (3) 16,099.82 87.23 123.99 3,952.68 3,894.04 -8,961.23 10,523.51 6,018,853.27 544,376.97 2.24 13,760.31 3_MWD+IFR2+MS+Sag (3) 16,193.73 91.37 127.35 3,953.82 3,895.18 -9,015.97 10,599.77 6,018,798.89 544,453.47 5.68 13,854.17 3_MWD+IFR2+MS+Sag (3) 11/26/2019 3:45:27PM Page 6 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M -15i North Reference: True Wellbore: MPU M-15 Survey Calculation Method: Minimum Curvature Design: MPU M -15i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 16,290.21 91.86 126.09 3,951.10 3,892.46 -9,073.63 10,677.07 6,018,741.59 544,531.03 1.40 13,950.57 3_MWD+IFR2+MS+Sag (3) 16,385.03 93.53 125.62 3,946.65 3,688.01 -9,129.11 10,753.83 6,018,686.46 544,608.03 1.83 14,045.27 3_MWD+IFR2+MS+Sag (3) 16,480.30 92.73 125.31 3,941.44 3,882.80 -9,184.30 10,831.31 6,018,631.63 544,685.76 0.90 14,140.39 3_MWD+IFR2+MS+Sag (3) 16,575.77 92.60 125.61 3,937.01 3,878.37 -9,239.63 10,908.99 6,018,576.66 544,763.68 0.34 14,235.76 3_MWD+IFR2+MS+Sag (3) 16,670.67 92.67 125.46 3,932.64 3,874.00 -9,294.73 10,986.14 6,018,521.92 544,841.06 0.17 14,330.55 3_MWD+IFR2+MS+Sag (3) 16,765.94 91.24 123.56 3,929.39 3,870.75 -9,348.67 11,064.59 6,018,468.35 544,919.75 2.50 14,425.76 3_MWD+IFR2+MS+Sag (3) 16,861.18 89.89 122.67 3,928.45 3,869.81 -9,400.69 11,144.35 6,018,416.69 544,999.75 1.70 14,520.94 3_MWD+IFR2+MS+Sag (3) 16,955.92 86.80 122.78 3,931.19 3,872.55 -9,451.88 11,224.01 6,018,365.86 545,079.63 3.26 14,615.55 3_MWD+IFR2+MS+Sag (3) 17,049.95 86.61 122.36 3,936.59 3,877.95 -9,502.42 11,303.12 6,018,315.69 545,158.96 0.49 14,709.34 3_MWD+IFR2+MS+Sag (3) 17,081.25 86.67 122.48 3,938.43 3,879.79 -9,519.17 11,329.50 6,018,299.06 545,185.41 0.43 14,740.55 3_MWD+IFR2+MS+Sag (3) 17,150.00 86.67 122.48 3,942.42 3,883.78 -9,556.03 11,387.40 6,018,262.47 545,243.47 0.00 14,809.12 PROJECTED to TD 14t,11y,igned byChecked B Benjamin HandD.., Date:2y9.11.2ned 6y:42:31Tyler arr By: Approved By: Tyler Marr Date:2o,9.,,.26,6:423,-aroo• Date: 11/26/2019 11/26/2019 3:45:27PM Page 7 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-15PB1 500292365370 Sperry Drilling Definitive Survey Report 26 November, 2019 HALLIBURTQN Sperry Orillinq Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M-151 North Reference: True Wellbore: MPU M-15PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-15PB1 Database: NORTH US + CANADA 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 Well MPU M -15i Well Position +N/ -S 0.00 usft Northing: 6,027,765.69 usft Latitude: 70° 29' 12.784 N +E/ -W 0.00 usft Easting: 533,813.87 usft Longitude: 149° 43'25,061 W Position Uncertainty 0.50 usft Wellhead Elevation: 0.00 usft Ground Level: 24.70 usft Wellbore MPU M-15PB1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I (°I (nT) BGGM2018 11/1/2019 16.39 80.94 57,409.01739771 Design MPU M -15P61 Audit Notes: Map Version: 1.0 Phase: ACTUAL Tie On Depth: 33.94 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction +N/ -S (usft) (usft) (usft) V) DLS 33.94 0.00 0.00 125.00 Survey Program Date 11/12/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 161.93 5,721.79 MPU M-15PB1 MWD+IFR2+MS+Sag (1) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 10/28/2019 5,818.31 7,817.99 MPU M -15P131 MWD+IFR2+MS+Sag (2) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sag 11/06/2019 Survey 11/26/2019 3:46:39PM Page 2 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (I (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 33.94 0.00 0.00 33.94 -24.70 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 UNDEFINED 161.93 0.25 243.95 161.93 103.29 -0.12 -0.25 6,027,765.57 533,813.62 0.20 -0.14 3_MWD+IFR2+MS+Sag(1) 209.01 0.24 252.35 209.01 150.37 -0.20 -044 6,027,765 49 533,813.43 008 -024 3_MWD+IFR2+MS+Sag (1) 301.41 0.79 265.97 301.41 242.77 -0.30 -1.26 6,027,765.38 533,812.61 0.61 -0.86 3_MWD+IFR2+MS+Sag(1) 395.27 1.20 19022 395.25 336.61 -1.31 -2.08 6,027,764.37 533,811.80 1.35 -0.95 3_MWD+IFR2+MS+Sag(1) 489.12 2.80 163.96 489.05 430.41 -4.48 -1.62 6,027,76120 533,812.27 1.92 1.25 3_MWD+IFR2+MS+Sag(1) 581.71 5.65 156.46 581.38 522.74 -10.84 0.83 6,027,754.86 533,814.75 3.13 6.89 3_MWD+IFR2+MS+Sag(1) 674.63 9.45 152.69 673.47 614.83 -21.81 6.16 6,027,743.91 533,820.13 4.12 17.55 3_MWD+IFR2+MS+Sag(1) 770.53 11.83 151.53 767.72 709.08 -37.45 14.46 6,027,728.31 533,828.49 2.49 33.32 3_MWD+IFR2+MS+Sag(1) 863.35 15.12 152.70 857.97 799.33 -56.58 24.55 6,027,709.23 533,838.67 3.56 52.56 3_MWD+IFR2+MS+Sag (1) 957.64 18.38 152.04 948.25 889.61 -80.64 37.16 6,027,685.22 533,851.39 3.46 76.69 3_MWD+IFR2+MS+Sag(1) 1,054.45 21.48 152.50 1,039.25 980.61 -109.85 52.50 6,027,656.09 533,866.87 3.21 106.02 3_MWD+IFR2+MS+Sag(1) 1,151.92 25.42 152.68 1,128.65 1,070.01 -144.28 70.35 6,027,621.74 533,884.87 4.04 140.39 3_MWD+IFR2+MS+Sag(1) 11/26/2019 3:46:39PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -15i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M-1 5i North Reference: True Wellbore: MPU M-15PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-15PB1 Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,247.13 26.35 153.88 1,214.31 1,155.67 -181.41 89.03 6,027,584.70 533,903.72 1.12 176.99 3_MWD+IFR2+MS+Sag(1) 1,340.61 29.09 152.49 1,297.05 1,238.41 -220.20 108.67 6,027,546.01 533,923.53 3.01 215.32 3_MWD+IFR2+MS+Sag(1) 1,436.69 31.70 152.18 1,379.92 1,321.28 -263.25 131.24 6,027,503.07 533,946.29 2.72 258.50 3_MWD+IFR2+MS+Sag (1) 1,530.94 34.45 152.61 1,458.89 1,400.25 -308.83 155.07 6,027,457.60 533,970.32 2.93 304.16 3_MWD+IFR2+MS+Sag(1) 1,626.98 36.31 153.23 1,537.19 1,478.55 -358.34 180.37 6,027,408.21 533,995.85 1.97 353.29 3_MWD+IFR2+MS+Sag(1) 1,722.61 39.05 153.10 1,612.87 1,554.23 410.49 206.76 6,027,356.18 534,022.47 2.87 404.82 3_MWD+IFR2+MS+Sag(1) 1,816.51 42.84 152.03 1,683.78 1,625.14 -465.09 235.13 6,027,301.72 534,051.08 4.10 459.37 3_MWD+IFR2+MS+Sag(1) 1,912.84 48.01 149.89 1,751.37 1,692.73 -525.02 268.47 6,027,241.94 534,084.70 5.59 521.06 3_MWD+IFR2+MS+Sag(1) 2,007.45 48.93 149.63 1,814.10 1,755.46 -586.21 304.14 6,027,180.93 534,120.64 0.99 585.37 3_MWD+IFR2+MS+Sag(1) 2,102.96 48.40 149.60 1,877.18 1,818.54 -648.07 340.41 6,027,119.23 534,157.19 0.56 650.57 3_MWD+IFR2+MS+Sag(1) 2,198.67 49.21 150.81 1,940.22 1,881.58 -710.57 376.19 6,027,056.91 534,193.25 1.27 715.73 3_MWD+IFR2+MS+Sag(1) 2,293.63 49.54 151.61 2,002.05 1,943.41 -773.74 410.90 6,026,993.91 534,228.24 0.73 780.39 3_MWD+IFR2+MS+Sag(1) 2,389.17 48.84 152.34 2,064.49 2,005.85 -837.57 444.88 6,026,930.24 534,262.51 0.93 844.83 3_MWD+IFR2+MS+Sag (1) 2,484.52 48.03 152.61 2,127.75 2,069.11 -900.83 477.85 6,026,867.13 534,295.76 0.88 908.13 3_MWD+IFR2+MS+Sag(1) 2,579.07 49.49 151.11 2,190.08 2,131.44 -963.52 511.39 6,026,804.60 534,329.58 1.95 971.55 3_MWD+IFR2+MS+Sag(1) 2,673.84 49.71 151.62 2,251.50 2,192.86 -1,026.86 545.97 6,026,741.42 534,364.45 0.47 1,036.22 3_MWD+IFR2+MS+Sag(1) 2,769.53 49.49 152.36 2,313.52 2,254.88 -1,091.19 580.20 6,026,677.25 534,398.96 0.63 1,101.15 3_MWD+IFR2+MS+Sag(1) 2,865.11 50.82 151.04 2,374.76 2,316.12 -1,155.80 614.99 6,026,612.81 534,434.05 1.75 1,166.71 3_MWD+IFR2+MS+Sag(1) 2,959.05 50.29 151.11 2,434.44 2,375.80 -1,219.29 650.08 6,026,549.49 534,469.42 0.57 1,231.87 3_MWD+IFR2+MS+Sag(1) 3,055.28 49.45 149.56 2,496.47 2,437.83 -1,283.22 686.49 6,026,485.73 534,506.11 1.51 1,298.36 3_MWD+IFR2+MS+Sag(1) 3,149.82 49.77 150.44 2,557.73 2,499.09 -1,345.58 722.49 6,026,423.54 534,542.40 0.79 1,363.62 3_MWD+IFR2+MS+Sag(1) 3,245.15 49.90 150.00 2,619.22 2,560.58 -1,408.81 758.67 6,026,360.48 534,578.86 0.38 1,429.53 3_MWD+IFR2+MS+Sag(1) 3,340.66 49.34 150.98 2,681.09 2,622.45 -1,472.13 794.51 6,026,297.34 534,614.99 0.98 1,495.20 3_MWD+IFR2+MS+Sag (1) 3,435.73 48.76 150.93 2,743.40 2,684.76 -1,534.90 829.37 6,026,234.73 534,650.13 0.61 1,559.76 3_MWD+IFR2+MS+Sag (1) 3,529.67 49.27 150.52 2,805.01 2,746.37 -1,596.76 864.05 6,026,173.03 534,685.08 0.64 1,623.65 3_MWD+IFR2+MS+Sag(1) 3,626.79 50.26 150.56 2,867.74 2,809.10 -1,661.31 900.51 6,026, 1 OB.65 534,721.84 1.02 1,690.54 3_MWD+IFR2+MS+Sag(1) 3,721.75 50.36 150.81 2,928.39 2,869.75 -1,725.03 936.29 6,026,045.11 534,757.90 0.23 1,756.40 3_MWD+IFR2+MS+Sag(1) 3,817.03 50.02 151.30 2,989.39 2,930.75 -1,789.07 971.71 6,025,981.23 534,793.61 0.53 1,822.15 3 MWD+IFR2+MS+Sag(1) 3,912.06 50.58 151.06 3,050.09 2,991.45 -1,853.13 1,006.96 6,025,917.34 534,829.14 0.62 1,887.76 3_MWD+IFR2+MS+Sag(1) 4,007.51 49.70 151.29 3,111.27 3,052.63 -1,917.32 1,042.28 6,025,853.31 534,864.76 0.94 1,953.52 3_MWD+IFR2+MS+Sag(1) 4,103.15 50.29 150.46 3,172.75 3,114.11 -1,981.32 1,077.94 6,025,789.49 534,900.70 0.91 2,019.43 3_MWD+IFR2+MS+Sag(1) 4,198.17 50.09 150.06 3,233.59 3,174.95 -2,044.69 1,114.15 6,025,726.28 534,937.19 0.39 2,085.45 3_MWD+IFR2+MS+Sag(1) 4,293.04 49.71 149.47 3,294.70 3,236.06 -2,107.39 1,150.69 6,025,663.76 534,974.01 0.62 2,151.34 3_MWD+IFR2+MS+Sag(1) 4,388.04 49.21 149.90 3,356.44 3,297.80 -2,169.71 1,187.13 6,025,601.61 535,010.74 0.63 2,216.94 3_MWD+IFR2+MS+Sag(1) 4,482.70 49.80 150.65 3,417.91 3,359.27 -2,232.23 1,222.82 6,025,539.27 535,046.71 0.87 2,282.03 3_MWD+IFR2+MS+Sag(1) 4,578.22 52.66 149.97 3,477.72 3,419.08 -2,296.91 1,259.71 6,025,474.76 535,083.89 3.05 2,349.35 3_MWD+IFR2+MS+Sag (1) 4,673.76 57.33 148.11 3,532.52 3,473.88 -2,363.98 1,299.99 6,025,407.88 535,124.46 5.14 2,420.81 3_MWD+IFR2+MS+Sag(1) 4,768.59 60.17 144.41 3,581.72 3,523.08 -2,431.35 1,345.03 6,025,340.72 535,169.81 4.48 2,496.35 3_MWD+IFR2+MS+Sag(1) 4,864.58 61.88 139.36 3,628.24 3,569.60 -2,497.36 1,396.86 6,025,274.95 535,221.93 4.93 2,576.67 3_MWD+IFR2+MS+Sag(1) 4,959.59 63.61 134.45 3,671.77 3,613.13 -2,558.99 1,454.56 6,025,213.59 535,279.91 4.94 2,659.28 3_MWD+IFR2+MS+Sag(1) 11126/2019 3:46:39PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-1 5i Project: Milne Point TVD Reference: MPU M-15 Actual RKB @ 58.64usft Site: M Pt Moose Pad MD Reference: MPU M-15 Actual RKB @ 58.64usft Well: MPU M -15i North Reference: True Wellbore: MPU M -15P61 Survey Calculation Method: Minimum Curvature Design: MPU M-15PB1 Database: NORTH US + CANADA Survey 11/2612019 3 46:39PM Page 4 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,055.48 64.74 13358 3,713.54 3,654.90 -2,618.96 1,516.63 6,025,153.91 535,342.25 1.43 2,744.53 3_MWD+IFR2+MS+Sag(1) 5,151.03 68.90 132.06 3,751.15 3,692.51 -2,678.63 1,581.06 6,025,094.54 535,406.93 4.59 2,831.53 3 MWD+IFR2+MS+Sag(1) 5,244.27 74.50 131.25 3,780.41 3,721.77 -2,737.44 1,647.18 6,025,036.04 535,473.32 6.06 2,919.42 3_MWD+IFR2+MS+Sag(1) 5,339.91 80.33 129.15 3,801.24 3,742.60 -2,797.64 1,718.45 6,024,976.16 535,544.85 6.46 3,012.34 3_MWD+IFR2+MS+Sag(1) 5,434.99 81.33 125.42 3,816.40 3,757.76 -2,854.49 1,793.12 6,024,919.66 535,619.77 4.01 3,106.11 3_MWD+IFR2+MS+Sag(1) 5,530.38 80.95 124.38 3,831.09 3,772.45 -2,908.42 1,870.42 6,024,866.09 535,697.31 1.15 3,200.36 3_MWD+IFR2+MS+Sag(1) 5,625.49 84.74 125.25 3,842.94 3,784.30 -2,962.29 1,947.88 6,024,812.58 535,775.01 4.09 3,294.71 3_MWD+IFR2+MS+Sag(1) 5,721.79 86.17 125.09 3,850.57 3,791.93 -3,017.58 2,026.35 6,024,757.65 535,853.72 1.49 3,390.70 3_MWD+IFR2+MS+Sag(1) 5,818.31 87.67 126.13 3,855.75 3,797.11 -3,073.70 2,104.71 6,024,701.90 535,932.32 1.89 3,487.07 3_MWD+IFR2+MS+Sag (2) 5,915.13 87.48 126.89 3,859.85 3,801.21 -3,131.25 2,182.45 6,024,644.70 536,010.32 0.81 3,583.77 3 MWD+IFR2+MS+Sag(2) 6,010.30 87.04 124.43 3,864.40 3,805.76 -3,186.66 2,259.68 6,024,589.65 536,087.80 2.62 3,678.82 3_MWD+IFR2+MS+Sag(2) 6,105.28 90.27 127.96 3,866.63 3,807.99 -3,242.72 2,336.29 6,024,533.94 536,164.65 5.04 3,773.73 3_MWD+IFR2+MS+Sag(2) 6,200.66 86.36 128.67 3,869.44 3,810.80 -3,301.82 2,411.08 6,024,475.19 536,239.70 4.17 3,868.89 3_MWD+IFR2+MS+Sag (2) 6,294.84 87.11 125.64 3,874.60 3,816.16 -3,358.60 2,486.01 6,024,418.76 536,314.88 3.31 3,962.83 3_MWD+IFR2+MS+Sag (2) 6,390.87 87.05 122.38 3,879.69 3,821.05 -3,412.24 2,565.50 6,024,365.49 536,394.60 3.39 4,058.71 3_MWD+IFR2+MS+Sag (2) 6,485.78 90.70 122.07 3,881.56 3,822.92 -3,462.83 2,645.76 6,024,315.27 536,475.08 3.86 4,153.48 3_MWD+IFR2+MS+Sag(2) 6,581.09 92.11 123.11 3,879.22 3,820.58 -3,514.15 2,726.04 6,024,264.32 536,555.59 1.84 4,248.67 3_MWD+IFR2+MS+Sag (2) 6,676.13 92.85 123.32 3,875.11 3,816.47 -3,566.16 2,805.47 6,024,212.67 536,635.25 0.81 4,343.57 3_MWD+IFR2+MS+Sag (2) 6,771.58 92.23 123.90 3,870.88 3,812.24 -3,618.94 2,884.89 6,024,160.26 536,714.90 0.89 4,438.90 3_MWD+IFR2+MS+Sag(2) 6,865.24 92.05 124.06 3,867.38 3,808.74 -3,671.25 2,962.50 6,024,108.31 536,792.74 0.26 4,532.48 3_MWD+IFR2+MS+Sag (2) 6,961.29 92.23 124.20 3,863.79 3,605.15 -3,725.11 3,041.95 6,024,054.82 536,872.42 0.24 4,628.45 3_MWD+IFR2+MS+Sag (2) 7,056.85 91.74 124.42 3,860.48 3,801.84 -3,778.94 3,120.84 6,024,001.35 536,951.55 0.56 4,723.95 3_MWD+IFR2+MS+Sag (2) 7,150.60 90.87 123.07 3,858.35 3,799.71 -3,831.00 3,198.77 6,023,949.65 537,029.71 1.71 4,817.65 3_MWD+IFR2+MS+Sag (2) 7,247.87 90.13 122.93 3,857.50 3,798.86 -3,883.97 3,280.34 6,023,897.05 537,111.51 0.77 4,914.86 3_MWD+IFR2+MS+Sag (2) 7,342.92 88.83 122.27 3,858.36 3,799.72 -3,935.18 3,360.41 6,023,846.22 537,191.81 1.53 5,009.82 3_MWD+IFR2+MS+Sag (2) 7,439.13 89.08 123.01 3,860.12 3,801.48 -3,987.06 3,441.41 6,023,794.71 537,273.03 0.81 5,105.93 3_MWD+IFR2+MS+Sag (2) 7,534.44 90.07 125.04 3,860.82 3,802.18 -4,040.39 3,520.40 6,023,741.75 537,352.25 2.37 5,201.21 3_MWD+IFR2+MS+Sag (2) 7,627.15 92.23 126.86 3,858.96 3,800.32 -4,094.80 3,595.43 6,023,687.68 537,427.52 3.05 5,293.88 3_MWD+IFR2+MS+Sag (2) 7,723.65 91.68 127.20 3,855.67 3,797.03 -4,152.88 3,672.42 6,023,629.96 537,504.77 0.67 5,390.27 3_MWD+IFR2+MS+Sag (2) 7,817.99 93.41 127.77 3,651.48 3,792.84 -4,210.23 3,747.20 6,023,572.95 537,579.81 1.93 5,484.42 3_MWD+IFR2+MS+Sag (2) 7,887.00 93.41 127.77 3,847.38 3,788.74 -4,252.43 3,801.66 6,023,531.01 537,634.45 0.00 5,553.23 PROJECTED to TO Checked By. Benjamin HandD.t.,20159.112612:5653-09'W Approved By. Tyler Marr by Benjamin Hand oaeazo;9;;.26164 36-07,00 Date: 11/26/2019 11/2612019 3 46:39PM Page 4 COMPASS 5000.15 Build 91 Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. County TD 5.778.00 Shoe Denth, MP M-15 State Alaska CASING RECORD Surface 5 771 00 Date Run 6 -Nov -19 Supv. S. Sunderland / J. Vanderpool PRTr Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. Hrs to Run: Csg Wt. On Slips: 100,000 Type of Shoe: Innovex _ Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes _ No Ft. Min. 9.3 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: 91 each 9-5/8" x 12-1/2" Expando-lizer centralizers ran. Shoe @ 5771 Preflush (Spacer) Type: Tuned Spacer Lead Slurry Type: Lead Density (ppg) Tail Slurry T e Tail FC @ 5,688.00 Density (ppg) 12 Volume pumped (BBLs) Top of Liner 10 Volume pumped (BBLs) 60 Sacks: 410 Yield: 2.35 172 Mixing / Pump' to (bpm): 4 Sacks: 400 Yield 116 Lu F Density (ppg) 15.8 Volume pumped (BBLs) 82 Casing (Or Liner) Detail 3 N Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 Type: Spud Mud Density (ppg) TXP BTC -SR Innovex 1.60 5,771.00 5,769.40 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 80.20 5,769.40 5,689.20 1 Float Collar 103/4 40.0 2,247 TXP BTC -SR Innovex 1.30 5,689.20 5,687.90 1 Casing 95/8 50.0 L-80 TXP BTC -SR Tenaris 39.96 5,687.90 5,647.94 1 Baffle Adapter 103/4 40.0 TXP BTC -SR HES 1.49 5,647.94 5,646.45 86 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 3,378.10 5,646.45 2,268.35 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.90 2,268.35 2,249.45 1 ESC II 103/4 40.0 N TXP BTC -SR HES 2.89 2,249.45 2,246.56 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.11 2,246.56 2,228.45 55 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,174.76 2,228.45 53.69 1 ut Joint of Casin 9 5/8 40.0 L-80 TXP BTC -SR Tenaris 21.24 53.69 32.45 Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. Hrs to Run: Csg Wt. On Slips: 100,000 Type of Shoe: Innovex _ Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes _ No Ft. Min. 9.3 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: 91 each 9-5/8" x 12-1/2" Expando-lizer centralizers ran. Shoe @ 5771 Preflush (Spacer) Type: Tuned Spacer Lead Slurry Type: Lead Density (ppg) Tail Slurry T e Tail FC @ 5,688.00 Density (ppg) 12 Volume pumped (BBLs) Top of Liner 10 Volume pumped (BBLs) 60 Sacks: 410 Yield: 2.35 172 Mixing / Pump' to (bpm): 4 Sacks: 400 Yield 116 Lu F Density (ppg) 15.8 Volume pumped (BBLs) 82 Mixing / Pumping Rate (bpm): 3 N Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: a Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 431.6/429.99 FCP (psi): 560 Pump used for disp: Rig Bump Plug? X Yes _ No Bump press 1190 Casing Rotated? X Yes _ No Reciprocated? X Yes No % Returns during job 100 Cement returns to surface? X Yes -No Spacer retums? X Yes _ No Vol to Surf: 40 Cement In Place At: 1:36 Date: 11!7/2019 Estimated TOC: 2,247 Method Used To Determine TOC: Calculated & Cement returns to surface Stage Collar @ 2246 Type ESC II Closure OK Y Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Permafrost L Sacks: 440 Yield: 4.41 Density (ppg) 10.7 Volume pumped (BBLs) 345 Mixing / Pump ate (bpm): 5 Tail Slurry w Type: Tail Sacks: 270 Yield: 1.17 N Density (ppg) 15.8 Volume pumped (BBLs) 56.2 Mixing /P umpi ate (bpm): 5 c3 Post Flush (Spacer) 0 Type: Density (ppg) Rate (bpm): Volume: W w Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 169.98/169.98 FCP (psi): 580 Pump used for disp: Rig Bump Plug? X Yes _No Bump press 1190 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 ' Cement returns to surface? X Yes -No Spacer returns? _Yes X No Vol to Surf: 195 Cement In Place At: 12:00 Date: 11/8/2019 Estimated TOC: 34 Method Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 355.94 Total Volume cmt Pumped: 655.2 Cmt returned to surface: 235 Calculated cement left in wellbore: 420.2 OH volume Calculated: 315.66 OH volume actual: 379.92 Actual % Washout: 20 DATE: 12/12/2019 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: AOGCC Natural Resources Technician 333 W. 7th Ave. Ste# 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-15 (PTD 219-141 M-15 PBi :MPU MPU M-15 & M-15 PB1 CGM Definitive Survey EMF LAS PDF TIFF DEC 13 0' AOGCC 21 91 41 31680 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 HilMirp Almoka, UA: DATE: 12/12/2019 ...... d Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: AOGCC Natural Resources Technician 333 W. 7th Ave. Ste# 100 Anchorage, AK 99501 MPU M-15 (PTD 219-141 MPU M-15 PB1 MPU M-15 & M-15 PB1 CGM Definitive Survey EMF LAS PDF TIFF 21 91 41 31679 RECEIVED DEC 13 2019 AOGCC Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 MEMORANDUM TO: Jim Regg--'(�,,/ P.I. Supervisor ' - ; � I ��V/t FROM: Adam Earl Petroleum Inspector Well Name MILNE PT UNIT M-15 Insp Num: mitAGE191208181741 Rel Insp Num: Mate of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, December 10, 2019 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC M-15 MILNE PT UNIT M-15 Src: Inspector Reviewed By: P.I. Supry J� NON -CONFIDENTIAL Comm API Well Number 50-029-23653-00-00 Inspector Name: Adam Earl Permit Number: 219-141-0 Inspection Date: 12/8/2019 Pretest Initial 15 Min 30 Min 45 Min 60 Min 812 -j 817 811 811 207 1808 1732 1711 - 1 Tuesday, December 10, 2019 Page 1 of I Packer Depth_____ Well M-15 T e In' w TVD /� -- -- 3840 Tubing PTD _191410 " .Type Test sPT !Test psi lsoo IA -- BBL Pumped: -- 2.7 BBL Returned: I 2.7 - OA Interval INITAL 1P/FT— P Notes: MIT -IA -well does not have an OA Pretest Initial 15 Min 30 Min 45 Min 60 Min 812 -j 817 811 811 207 1808 1732 1711 - 1 Tuesday, December 10, 2019 Page 1 of I THE STA i °'ALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas :,onservation Commission 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-15 Hilcorp Alaska, LLC Permit to Drill Number: 219-141 Surface Location: 4914' FSL, 351' FEL, Sec. 14, TI 3N, R9E, UM, AK Bottomhole Location: 628' FSL, 499' FWL, Sec. 20, TUN, RIDE, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service 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, :9, e Chair DATED this I day of November, 2019. STATE OF ALASKA i_ ,SKA OIL AND GAS CONSERVATION CON,, SION PERMIT TO DRILL 20 AAC 25.005 OCT 17 2019 1 a. Type of Work: 1b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ 1c. sed for: Drill ❑� Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑� ' Single Zone D Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-15 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,143' TVD: 3,872' Milne Point Field Schrader Bluff Oil Pool , 4a. Location of Well (Governmental Section): 7. Property Designation: r Surface: 4914' FSL, 351' FEL, Sec 14, T1 3N, R9E, UM, AK ADL025514, ADL025515 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1804' FSL, 1809' FWL, Sec 13, T13N, R9E, UM, AK LONS 16-004 11/8/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 628' FSL, 499' FWL, Sec 20, T1 3N, RI OE, UM, AK 5104 3919' 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-533813 y- 6027765 Zone -4 GL / BF Elevation above MSL (ft): 24.7 to Same Pool: 815' to MPU M-16 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93.2 degrees Downhole: 1699 Surface: 1314 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" - X52 Weld 113' Surface Surface 113' 113' -270 ft3 Stg 1 - L - 948 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP 5,828' Surface Surface 5,828' 3,864' Stg 2 - L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 11,465' 5,678' 3,859' 17,143 3,872' 1 Cementless Injection Liner ]CDs T4olm k 3-1/2" 9.3# L-80 EUE 8RD 1 5,678' Surface I Surface 1 5,678' 1 3,859' 1 Tieback 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 Q 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot e ❑ 8 Shallow Hazard Analysis B 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: 'gn el hIICOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 F-t•1L �^nn?`r' /w`1 E� Authorized Signature: Date: 119-1 -1-0/ Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: % 4-, 50- 02 g ., — Q0 —QQ 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: [9_11 Other:r�� 3f li<% py to Samples req'd: Yes ❑ No[ No / Mud log req'd: Yes E][�] HzS measures: Yes ❑ No &;/ Directional svy req'd: Yes No ❑ } (�_ ( C a i" Z"�-...� Spacing exception req'd: Yes ❑ No B Inclination -only svy req'd: Yes�o l.� t o If ✓ ` l Post initial injection MIT req'd: Yee I No ❑ APPROVED BY 1 Approved by: v COMMISSIONER THE COMMISSION Date:1 Submit Form and F o1 �r i a0�� < This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Attachments in Duplicate `-' 1 6ii - 10 3 i- 11 n D I (` I ISI A I R(M* -�Zre_$ rolzzln M-2 32-14 1\\\\ 44 \\ \ 32-14 I 11A1103 I /I L -M=T2� �= - — — M.1.0- -M-26 u.1_0-M2d L I \ \ M-13 Al, M-14\ \\ Al\\m.15wp�5 \;\/�\\ \\M-16/ PA, / / 1/-4�P62 L -3X �ESAD01 /�/\� L-47 II\ k / 1A\\ /%/ I\ �\ L-45 L-50 \ �/ \\ \\ \\ \\ /M-10�Ar1 -17 \\ '4'-,LIVIA!P051 LIVI 5*,XS \ \ \ \ HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP M-15 Injector (Proposed) 0 I.Q00 z o0o FEET WELL SYMBOLS D — — — — — —�� . &A \ 0 NJ WeII IW_Flaoa) \\ \ PeA 011 \ KUPARUK RIVER UNIT J - 20A REMARKS Zy \ Well Symbols at top of Schrader Bluff OA Sand \ Black dash circle = 1320' radius from OA sand in heel \ and toe of proposed M-15 drill well J-241_1 \ J-19 J-24\ Jza7_ v Area of Review MPM-15 CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD API WELL STATUS OA (MD) OA (TVD) (MD) (TVD) status Zonal Isolation 219-040 50-029-23625-00-00 MPM-14 SB Producer 4,765' 3,854' Surface Surface Open Open to injection support 219-061 50-029-23631-00-00 MPM-16 SB Producer 6,651' 3,809' Surface Surface Open Open to injection support 207-014 20-029-23343-00-00 Liviano 01 P&A'd 3,948' 3,819' Surface Surface Closed Well fully P&A'd with cement to surface 207-021 50-029-23343-01-00 Liviano 01A P&A'd 3,892' 3,823' Surface Surface Closed Well fully P&A'd with cement to surface Surface casing was run to 8,664' MD and cemented back to surface. 200-149 50-029-22976-00-00 MPJ -24 P&A'd 8,253' 3,852' Surface Surface Closed Lateral was drilled in SB and sander later abandoned. Retainin set at 7,576' MD and pump 193 sx / 46 bbls of cement thru. Well was sidetracked directly after abandonement. Surface casing was run to 8,664' MD 200-150 50-029-22976-60-00 MPJ -24L1 P&A'd 8,253' 3,852' Surface Surface Closed and cemented back to surface. Lateral was drilled in SB OB sand. Hilcorp Alaska, LLC Milne Point Unit (MPU) M-15 Drilling Program Version 1 10/17/19 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 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 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................37 18.0 RDMO............................................................................................................................................38 19.0 Doyon 14 Diverter Schematic.......................................................................................................39 20.0 Doyon 14 BOP Schematic.............................................................................................................40 21.0 Wellhead Schematic......................................................................................................................41 22.0 Days Vs Depth................................................................................................................................42 23.0 Formation Tops & Information...................................................................................................43 24.0 Anticipated Drilling Hazards.......................................................................................................44 25.0 Doyon 14 Layout............................................................................................................................47 26.0 FIT Procedure................................................................................................................................48 27.0 Doyon 14 Choke Manifold Schematic..........................................................................................49 28.0 Casing Design.................................................................................................................................50 29.0 8-1/2" Hole Section MASP............................................................................................................51 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 31.0 Surface Plat (As Built) (NAD 27).................................................................................................53 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................54 33.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................55 HilmE. -By Company 1.0 Well Summary Milne Point Unit M-15 SB Injector Drilling Procedure Well MPU M-15 Pad Milne Point "M" Pad Planned Completion Type 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 17,143' MD / 5,828' TVD PBTD, MD / TVD 17,133' MD / 5,828' TVD Surface Location (Governmental) 4914' FSL, 351' FEL, Sec 14, TON, R9E, UM, AK Surface Location (NAD 27) X= 533,813 Y= 6,027,765 Top of Productive Horizon (Governmental) 1804' FSL, 1809' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 535,990 Y= 6,024,666 BHL (Governmental) 628' FSL, 499' FWL, Sec 20, TON, R10E, UM, AK BHL (NAD 27) X= 545,225 Y=6,018,261 AFE Number 1911314M (D,C,F) AFE Drilling Days 21 days AFE Completion Das 4 days AFE Drilling Amount $4,645,840 AFE Completion Amount $1,677,872 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1314 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1699 psi Work String 5" 19.5# 5-135 DS -50 & NC 50 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 Milne Point Unit M-15 SB Injector Drilling Procedure Management of Change Information Hilcorp Alaska, LLC Hilco EOM Changes to Approved Permit to Drill Date: 1 011 7/201 9 Subject: Changes to Approved Permit to Drill for MPU M-15 File #: MPU M-15 Drilling and Completion Program Any modifications to MPU M-15 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance by the AOGCC. Approval: Prepared: Page 3 Approved Drilling Manager Date Drilling Engineer Date 3.0 Tubular Program: Milne Point Unit M-15 SB Injector Drilling Procedure Hole Section OD (in) ID in Drift in Conn OD (in) Wt (#/ft) G—radej Conn Burst (psi) Collapse (psi)(k-lbs Tensio Cond 20" 19.25" - - - X-52 Weld 560klb Surface & 5" 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 8-1/2" 4-1/2" 3.96" 1 3.795" 1 4.714" 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2" 2.992" 2.867" 1 4.500" 9.3 L-80 EUE 8xn 9289 7399 163 4.0 Drill Pipe Information: Hole OD ID(in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section lfb ; in in(#/ft) 6.625" GPDS50 Min ,(Max)((k-lbs 36,100 43,100 560klb Surface & 5" 4.276" 3.25" 19.5 S-135 Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Milne Point Unit M-15 SB Injector Hilco}+}+� Drilling Procedure Energy compmy 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcom jengel@hilcorp.com and cdinger@hilcorp.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 -Run" Casing tally to mm, ers o,hilcorp,com jengel@hilcorp.com and cdinizer@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyershilcorp.com jengel ckhilcorp.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 lenel@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 kflemine@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 6.0 Planned Wellbore Schematic O�g K6 Eev: 5&'Y/GL Eev.: W1 TD= L,133 (fvL`} 1TD=3472'(rm PBTD=L7,13o INN/PMD =3,5:Y(TVV Page 6 Milne Point Unit M-15 SB Injector Drilling Procedure Milne Paint Unit Well: MPU M-15 Proposed Schematic PTD: TBE) APL TBD ------------------------ -- ---------------------- TREE &WELLHEAD Tree I Cameron 31/r" SMI w/ 4-1116" SM Cameron Wellhead I Cameron 11` SK x 4UbrA bssttam w/ 121 2.1116" 5K auts •-------------------------------- i------------------- OPEN HOLE CEMENT DETAIL ------ 42" SE1 bbU(10 Yards &WUztt&dumpeddawn backsidel 12-+14" StS1-Lead948ft3/Tail 458ft3 5 2- Lead 1937 ft31 Tail 314 ft3 9-112" C=Wztl= Iri ection Liner in S -11T' hale ----------------- 6iiiii DETAIL Ske I Type 0 Grade/ Conn Drift ID Tcp I 8£m I BPP 24'k34" Conductarltnsulatedl 215.51X-42YWetd N/A Surfa.e 114' N1A 8" Surface 40/L -80I 8.67VI Surface I 5,828' 1 0,0759 4.112" 1 liner 135/L-801 625 3.795" 1`.E78' 17,143' 1 OD149 TUBING DETAIL C &[H ZKP Liner Trp Packer 3 -IM, 1 Tubing 93 L-80 EUEBRD 1 2.867' 1 - G 7 X 0067] WELL INCLINATION DETAIL XQP @ 400' llde An e@)N=TBD I lde Angle @ Uner TDp = TRO Max IWeAngle =TOO '----------------------------------------------------' JEWELRY DETAIL NO Top hto roam �D upper Comp etlon !2,3Q' 3.S" X Ni Ia 12.813" Packin 6 see) 2.813" 3.5" IN Nipple (2813" Paddrp, Bare; 2-75" No -Go) 2.750" Gauge Mandmi SGr6)(POG wJ)V Wire 2.896" 1 S,iGt! 8.W ND Ga Laster v i 7-375' Se�sl AssemhM 2.992" 7.375'Tsebackabo�retheSlDIFL'merTa Packer 2.992" tt311rerconlp tion C &[H ZKP Liner Trp Packer - - 1',13£ VAV IBai an Seat/ Closed) - or>1h Dalh M➢ TVD ";s..1 Pickce 0.uil ea THD TBD -------------------- - ------------ GENERAL WELL INFO � APIT TPD Completed by Dayon 14: Future A_ _4 9v: CK, 1 17;:.;94 7.0 Drilling / Completion Summary Milne Point Unit M-15 SB Injector Drilling Procedure MPU M-15 is a grassroots infector planned to be drilled in the Schrader Bluff OA sand. M-15 is partof 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 OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD injection liner will be run in the open hole section. 0 The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately November 8, 2019, pending rig schedule. Surface casing will be run to 5,828 MD / 3,864' 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 & test 13-5/8" x 5M BOP. Install MPD Riser 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner. 6. Run 3-1/2" tubing. 7. 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 Milne Point Unit M-15 SB Injector Hilco+Tf�^+f Drilling Procedure Energy Compmy 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-15. 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: Hilcorp Alaska LLC does not request any variances at this time. Page 8 Hilcorp En.V Summary of BOP Equipment & Notifications Milne Point Unit M-15 SB Injector Drilling Procedure 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 MPL Double Gate Initial Test: 250/3000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 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,�cgalaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loepp2alaska. gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsgalaska.gov Test/Inspection notification standardization format: hM2://doa.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 4 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure Energy C m� 9.0 RX and Preparatory Work 9.1 M-15 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 R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @110 spm @ 95% volumetric efficiency. Page 10 Milne Point Unit M-15 SB Injector Hilcorp Drilling Procedure E-WC.m 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 HilcmE -W 10.4 Rig & Diverter Orientation: • May change on location Milne Point Unit M-15 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources D verter Line MPU MPad *[}cawing Not To Scale i Page 12 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-15 SB Injector 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. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig 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 Ix Milne Point Unit M-15 SB Injector 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 • Past wells on E pad have increased MW and added 1-1.5ppb of Lecithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • 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. • AC: There are no offset wells with a clearance factors <1.0 M-08 DSW is a planned well and does not exist yet, its planned path has a clearance factor of 1.08 11.4 12-1/4" hole mud program summary: J• 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. Page 14 J 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) BARACARBsBAROFIBRE/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. Milne Point Unit M-15 SB Injector 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�]_ Pkg Plastic Viscosit Yield Point API FL pH Tem Surface 8.8-9.8 75-175 1 20-40 1 25-45 1 <10 8.5-9.0 <- 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 LTL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 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. • 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 V/ 0 Milne Point Unit M-15 SB Injector Hilco+rp Drilling Procedure Energy C—p.ny 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 locking 120' shoe track assembly consisting of - 9 -5/8" £ 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 C/ 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 Baffle Adapter {if used) IDLJ _ Depth Bypass or Shut-off Baffle ID Depth Float Cofiar Depth iqgi� Float Shoe Depth Hole TD "Reference Casing sales Manual Section 5 Page 17 "A 9verall Length B Mo. ID After Drillout C Max. ToDl CD D Opening Seat ID E Closing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit M-15 SB Injector Drilling Procedure Hikorp ES41 Running Order ES41 Cementer Shut Off Plug BaPBe Adapter By -Pass Plug t; By Pass Baffle Float Collar Float Shoe f Milne Point Unit M-15 SB Injector Hilco Drilling Procedure En�� yam 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: Verify depth of lowest Ugnu water sand for isolation with Geologist Depth Interval Centralization Shoe —1000' Above Shoe 1/jt 1000' above Shoe — 2000' above Shoe 1/ 2 its (Top of Ugnu) • 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 (— 2,500' 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 f/ Milne Point Unit M-15 SB Injector Hilco Drilling Procedure >� C—PP TXP(R•BTC __ IVOW2018 PERFORMANCE Body Yard Stengh 916x1Dppids lrlemafY!�. _kI 5750 psi SMYS 860D0psi Cciia;se 3090 -.psi CWAectvi OD 10.625 in. Gauplirg1wTh 10125,-,, Connection ID 8.823 it Make-up loss .4.831 in. Threads per iin 5 Connection OD JpScn REGULAR PERFORMANCE Tr cion Efficiency 100.0 `S 26mr5 *41 Stiemgth 916.000 x1000 nternal Pressure Capac� lit 5750.000 psi lbs Compression Eircienuy 100 `.,: Compression Str&i h 9%000x1000 Max. Alowable Bending 36 ",100 R lbs Eremal P—e-Ss.j r=_ Cacaciry 3090.0091 psi MAKE-UP TORQUES Pr_;rimum 188601t4ts Optimum 20960fi4b=- Maximum 2' EW t-IbE OPERATION LIMIT TORQUES Operating Tcq is 356001-i_> Yield Torque 53400 P.. -lbs Notes This connection is fully interchangeable vrith: TXP9, BTC - 9.625 in. - 36 143.5147953.5158.4 lbsi'R [1] Internal Pressure Capacity related to structural resistance ority. Internal pressure leak resistance as per section 10.3 API 5C3 I ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face toad, which vain be reduced. Please contact a local Tena€€s technical sales representative. Page 19 V/ Outside Diameter 9625 ;a Min. Wall 87-5% Thickness I-) Grade Le low Type 1 Wall Thickness 0.395r. Connection OD REGULAR Option COUPLING PIPE BODY Lody: Red 1st Band: Red Grade L80 Type 1" Drift Standard API Standd 1st Bard: Brown Yrd Band: 2rd Bard: - Brown Type Casing 3rd Band: - Bre Band: - 4th Band: - GEOMETRY Nominal C0? 9.625 in. Nbrninal lNeight 40 Ibstft Drift 8.679 in. ekminal ID 8.83'. in. 4'ara'°Thickness 0.395 an. Ptah End LL1?ight 38.97 Ibs,Yt OD lance AN PERFORMANCE Body Yard Stengh 916x1Dppids lrlemafY!�. _kI 5750 psi SMYS 860D0psi Cciia;se 3090 -.psi CWAectvi OD 10.625 in. Gauplirg1wTh 10125,-,, Connection ID 8.823 it Make-up loss .4.831 in. Threads per iin 5 Connection OD JpScn REGULAR PERFORMANCE Tr cion Efficiency 100.0 `S 26mr5 *41 Stiemgth 916.000 x1000 nternal Pressure Capac� lit 5750.000 psi lbs Compression Eircienuy 100 `.,: Compression Str&i h 9%000x1000 Max. Alowable Bending 36 ",100 R lbs Eremal P—e-Ss.j r=_ Cacaciry 3090.0091 psi MAKE-UP TORQUES Pr_;rimum 188601t4ts Optimum 20960fi4b=- Maximum 2' EW t-IbE OPERATION LIMIT TORQUES Operating Tcq is 356001-i_> Yield Torque 53400 P.. -lbs Notes This connection is fully interchangeable vrith: TXP9, BTC - 9.625 in. - 36 143.5147953.5158.4 lbsi'R [1] Internal Pressure Capacity related to structural resistance ority. Internal pressure leak resistance as per section 10.3 API 5C3 I ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face toad, which vain be reduced. Please contact a local Tena€€s technical sales representative. Page 19 V/ Milne Point Unit M-15 SB Injector 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. Page 20 ff Hilcorp Energy Campny 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-15 SB Injector 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" (4,828'- 2500') x .0558 bpf x 1.3 = 168.8 948.2 J Casing Total Lead 168.8 948.2 12-1/4" OH x 9-5/8" (5,828'- 4,828') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 1 458 Page 21 Milne Point Unit M-15 SB Injector Drilling Procedure Cement Slurry Design (Ist Stage Cement Job): Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,708' x.0758 bpf = 432.6 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement i `I`�' stage tool &that sufficient spacer_wll be above the tool to exit when circulation is blished. 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 System ExtendaCEM TM System SwiftCEM TM System Density 11.7 Ib/gal 15.81b/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,708' x.0758 bpf = 432.6 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement i `I`�' stage tool &that sufficient spacer_wll be above the tool to exit when circulation is blished. 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 Milne Point Unit M-15 SB Injector 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 prematurely opened. 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. • If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II Stage tool 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 Hilcorp E—V C—e.Rr Second Stage Surface Cement Job: Milne Point Unit M-15 SB Injector Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 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 2°d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM TM System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 v 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 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM System (Hal Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 Milne Point Unit M-15 SB Injector 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 cdingerghilcorp. com This will be included with the EDW documentation that goes to the AOGCC. Page 25 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure Energy �2 14.0 BOP N/U and 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 1-11, • 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" VBRsl--,— • 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 Run 5" BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 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-15 SB Injector 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. 15.4 RX and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every 1/4 bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 11 5.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 5.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 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" 19.5# S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: J• 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. Use appropriate SAFECARB blend on this well Page 27 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure �� J • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameterl 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 F1oPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids I MBT HPHT I Hardness Production 1 8.9-9.5 5-25 - ALAP 1 15-30 1 4-6 1 <10% 1 <8 1 <11.0 I<100 System Forrri'vlfition: Page 28 Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 VM (8.5 gal/ 100 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-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-15 SB Injector Drilling Procedure 15.13 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 undulate between Schrader OA1 & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • 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 • Offset injection pressure from F-110 & L-50 has been seen on recent M -Pad wells. Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections • AC: • There are no offset wells that have a clearance factor of <1.0. • 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% 15.15 Reference: Open hole sidetracking practice: • 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. Page 29 Milne Point Unit M-15 SB Injector Drilling Procedure • 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 • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (x3 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Injection Control Devices (ICDs) are wire wrapped, and require passing PST with 250µ Coupons • Circulate and condition mud as much as needed to pass the production screen test • If not passing after first test, call Completion Engineer 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe 15.20 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 30 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure EneW c2 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 4-1/2" Injection Liner (Lower Completion) Milne Point Unit M-15 SB Injector Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" liner. With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2" and 5" test joints to 250 psi low/3000 psi high. 16.3. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner 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. 16.5. Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-%2" liner with PST passed mud (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement X40' • The ICD connection is 4-1/2" 13.5# Hydril 625 • Remove protective packaging on swell packers just prior to picking up If liner length exceeds surface casing length, ensure centralizers are placed I Jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Page 32 Hilcorp �c— Milne Point Unit M-15 SB Injector Drilling Procedure • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 33 Hilcorp E—V c-, For the latest performance data. always visit our website: Ww'w.tenaris.com Wedge 6251-) Milne Point Unit M-15 SB Injector Drilling Procedure .—., 12M4J2017 Outside Diameter 0.500 in. Min. Wall 97.5% 3.049 n, Make-up loss 3.930:in. Thickness 359 (`) Grade LBO i PERFORMANCE Type i Walt Thickness 0290 in. Connection OD REGULAR Tension E16ciensy 91,0% Joint Yield Svenglh Option Internal Pressure Capacity COUPLING PIPE BODY --- lbs Body. Red tst Bane: Red - Grade LBO Typt1• Drift AP1Standard I st Band: Brown 2nd Band: 73.T'MrX Et 2nd Band: - Brown Type Casing 3rd Band: - 3.+d Band: - 4th Band - GEOMETRY Nominal DD 3.500 r Nominal Wei,^M Nominal 10 3320 'rn. Wall Thickness CO Tolerance APr 13.50 ks'$ Drift 3.795 ,. 0290 :r. Rain End Weight 13.05 ibshl PERFORMANCE Body Yeld Strength 307 x$YZ Itis Internal Yield 9026 psi SM'fs 90006 psi CollaaSe 9530 ps I a��tdrtt=3—,�pdr"iTa Connect- , OD 4714 in. Cone,[ ID 3.049 n, Make-up loss 3.930:in. ThreaWs W in 359 Connecta, OD Option REGULAR PERFORMANCE Tension E16ciensy 91,0% Joint Yield Svenglh 279270 x1000 Internal Pressure Capacity 9020.000 psi lbs Compression eficiercy 94.556 Compression SneTVth 290.115 AOX Max.APmable Bending 73.T'MrX Et Itis External Pressure Capacity 9540.000 ..psi MAKE-UP TORQU ES Minimum BODO R -lbs optimum 9600 r[ -lbs Ma noun 128DD A -lbs OPERATION LIMIT TORQUES Operating Torque 12900 °Nbs Yield Twq�- 15000 ft -lbs Notes For further inlOrmation on concepts indicated in Mt s datasheet, download the Datasheet PMarual from %ww.tenans-com 16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 16.7. R/U false rotary and run 2-3/8" 6.49/ft inner string. Page 34 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure �C� 16.8. 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. 16.9. M/U Baker SLZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.13. 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. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 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 to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 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. Page 35 Milne Point Unit M-15 SB Injector Drilling Procedure 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. Displace 2-3/8" x Liner, pump 2 circulations. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean out run 16.25. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.26. Flush liner top at max rate while displacing out well to clean brine. 16.27. POOH LD Remaining 5" DP. 16.28. Once running tools are L/D, Swap to Completion AFE. Page 36 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure Energy E.. 17.0 R � -1/2" Tubing (Upper Completion) 17. Noti e AOGCC at least 24 hours in advance of the IA pressure test after running the mpletion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivardghilcorp.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-'/z" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-'/z" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3—%2" 9.3#/ft, L-80 EUE 8RD tubing • 3-1/2" "XN" nipple at TBD • 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3-1/2" "X" nipple at TBD MD • 3-%2" 9.3#/ft, L-80 EUE 8RD space out pups • 1 joint 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 37 Hilcorp Milne Point Unit M-15 SB Injector Drilling Procedure 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 — 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Page 38 Hilcorp E -W C=pay 19.0 Doyon 14 Diverter Schematic 21-1t4' Al R ser- 21-itS- 2MM-- D"rw •i' 21-1[ 1' 2A Spacer Spat 16 -WW) i 21-V4"2M 2M DSA Page 39 Milne Point Unit M-15 SB Injector Drilling Procedure —16' run Openng Kntla V*va 1 B' Dvefler Lane Milne Point Unit M-15 SB Injector Hilco Drilling Procedure E,cw �2 20.0 Doyon 14 BOP Schematic Kill Line�"�� Page 40 2-7/8" x 5" VBR Blind Rams xVMHCR :txAw line W Gate VaNe 2-7/8" x 5" VBR 21.0 Wellhead Schematic 0 Milne Point Unit M-15 SB Injector Drilling Procedure Note, Dimexc �io�n3�a iinOfnon rel7�sea re on this 3 uti�3m es-bnmted meat/ wnnnz oni}'_ Page 41 22.0 Days Vs Depth J1 COR mm 6000 t CL 8000 a� 0 v 10000 2 Page 42 Milne Point Unit M-15 SB Injector Drilling Procedure MPU M-15 SB OA Injector Days vs Depth 12000 14000 16000 18000 0 5 10 15 20 25 30 Days 23.0 Formation Tops & Information Milne Point Unit M-15 SB Injector Drilling Procedure MPU M-15 Formations (wp05) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2095 -1814 1872 823.68 8.46 LA3 4049 -3080 3138 1380.72 8.46 Schrader Bluff NA 4923 -3605 3663 1611.72 8.46 Schrader Bluff OA 5812 -3804 3862 1699.28 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST - SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS &1wa! NOTE: See individual Well Program for _ T Gubik specific casing design, depths, sizes. •.. nm 6 weights, grades and connections. a Unconsolidated coarse to medium sand and small gravel P with minor silts tone. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000 a ARE ENCOUNTERED WHEN DRILLING THE -4*m SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE +Iso• Base permafrost EFFECTIVE HOLE CLEANING. Inierbeds of sand, clays and sittslenas with occasional 2,000 show of coal. Watch possible sidetracking while washinyreandng. L33 d L•15. Sagav •nook -4*na No hydrates encountered on L -Pad wells drilled to date. Continued €rderbeds of sand• clays and sillsiones with occasional shows of coal. Traces of pyrite at H• 3100 It. 3,000• Interval at ♦1. 3400 it can be sticky and tight (L-01). Clay Interbods between 3000 and 4500 ft C 3472'- L A 3657` Kuno. Y UGNU: Series of coarsening upward sands which are f•Ae.ci)) made up of: (from top to bottom) coarse sand. fine sand. silty shale Better developed inhimening shales as you UGNU progress into the Land M (deeper). flan and Schrader Bluff Possible hydrocarbons limited t'a^a to SW corner of Milne development Norihem area is 1•A81 dowrstructwe and wet. '3739' tseand. (aAlsc) .4000. (NA) Schrader Bluff Sands: 4,000 t-AS.0 D. Continuad layering coarsening upward sands as above .m Schrader Bluff: Possible lost circulation E.F) asceptmore condensed and with occasional coal. zone while drilling brig strings and running •4170' o5anm Clay rich shale interval 4300 to 460Qrt Ugnu and Schrader Bluff Possible hydrocarbons limited casing. Recommend deep setting surface (OA) tdl&C, to S W com r of Milne dowlopment L37 and 1. 45 are casing for Kuparuk long strings. Also, the Dx•n completed In the Schrader Bluff sand. Northern area of Schrader Bluff sands are a potential Schrader L -Pad is dowrotnicture and wet. differential stuck pipe interval if left un -cased Bluff C surface casing poll* In shale below for Kuparuk long strings. Sands:SSchrader Bluff OB sand for longer reach wells. I Page 43 Hilcorp ff 24.0 Anticipated Drilling Hazards Milne Point Unit M-15 SB Injector Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have 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 a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. 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 44 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure Energy nom 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 45 Hilcorp E -W C—P.EY 8-1/2" Hole Section: Milne Point Unit M-15 SB Injector Drilling Procedure 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 H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S 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. There are no wells with a separation factor of <1. Specific AC risk addressed in 8.5" hole section, 15. Page 46 25.0 Doyon 14 Layout Milne Point Unit M-15 SB Injector Drilling Procedure Page 47 Milne Point Unit M-15 SB Injector Hilco Drilling Procedure En� c2 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 48 Wa7yc7�7 CHOKE MANIFOLD IZI LEGEND White Handled Valves QDNormally Open Red Handled Valves qVNormally Closed Date: 08-22-14 Rev. 3 NOTES: I) Valve A is a 3-1/16" 5M Remote Operated Hydraulic Choke Valve, 2) Valve B is a 3-118" 5M Adjustable Choke Valve. 3) Valve I is a 2-I/16" 5M Manual Gate Valve. 4) Valves 2-14 are 3-1/8" 5M Manual Gate Valves. Divert Line From BOP Divert Line To Mud/Gas Separator L d !' O ~ � U -p N dl U 0 O CL N a w n 0) C � C c° C� O V O 0 A N Wa7yc7�7 CHOKE MANIFOLD IZI LEGEND White Handled Valves QDNormally Open Red Handled Valves qVNormally Closed Date: 08-22-14 Rev. 3 NOTES: I) Valve A is a 3-1/16" 5M Remote Operated Hydraulic Choke Valve, 2) Valve B is a 3-118" 5M Adjustable Choke Valve. 3) Valve I is a 2-I/16" 5M Manual Gate Valve. 4) Valves 2-14 are 3-1/8" 5M Manual Gate Valves. Divert Line From BOP Divert Line To Mud/Gas Separator HilmEnew vmr Milne Point Unit M-15 SB Injector Drilling Procedure 28.0 Casing Design Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Drilling Mode MASP: 1314 MASP: DATE: 10/17/2019 WELL: MPU M45 DESIGN BY: Joe Engel Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: attached MASP determination & calculation Production Mode MASP: 1314 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 50 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 4-1/2" Top (MD) 0 5,828 Top (TVD) 0 3,864 Bottom (MD) 5,828 17,143 Bottom (TVD) 3,864 3,872 Length 5,828 11,315 Weight (ppf) 40 13.5 Grade L-80 L-80 Connection TXP H625 Weight w/o Bouyancy Factor (lbs) 233,120 152,753 Tension at Top of Section (lbs) 233,120 152,753 Min strength Tension (1000 lbs) 916 279 Worst Case Safety Factor (Tension) 3.93 V 1.83 Collapse Pressure at bottom (Psi) 1,909 1,913 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.62 v 4.46 " MASP (psi) 1,314 1,314 Minimum Yield (psi) 5,750 91020 Worst case safety factor (Burst) 4.38 v 6.86 Page 50 Milne Point Unit M-15 SB Injector Hileo Drilling Procedure E—W 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 Hilc�or�p 8-1/2" Hole Section MPU M-15 Milne Point Unit MD TVD Planned Top: 5828 3864 Planned TD: 17143 3872 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sandi 3,864 1700 1 Oil 8.46 1 0.440 Offset Well Mud Densities Well MW ranee TOD (TVD) Bottom (TVD) Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 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: 3,864 (ft) x 0.78(psi/ft)= 3014 3014(psi) - [0.1(psi/ft)*3864(ft)]= 2628 psi MASP from pore pressure (complete evacuation of wellbore togas from Schrader uff-Oksa.nd) /f 3864 (ft) x 0.44(psi/ft)= 1700 psi 1700(psi)-0.1(psi/ft)*3864(ft) 1314 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure -eroaeuati-on - of entire wellbore to gas at 0.1 psi/ft. Page 51 HilmEncrey pa�y 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 52 Milne Point Unit M-15 SB Injector Drilling Procedure 1 6Up DEW: 1V1712D19 Milne Point Unit MPU M-1 5i Well wp_05 Alaska State Plane Zone 4 NAD 1927 0 1,100 2.200 Feet i"' / 1 ♦ F'' Pfi` 1 _ PE �'`L C7 \ r! L.C':A ADL388235r A- .CrEec 7�Srtr�l�,{/rr €ec..11 •Fal Sec- 12 Sec.B\t` , ADL02550� /., 1628)' \ \ ADL3550T3 1 • i r tt tt ,r/rF i,. `•`.rll r / Ir trtrl r — — � r i ! % \ ♦ r -- � •rte°L-4dP3'- NIPL' M I5i_SHL • �` ' v `+A C± PE�:,�� \ ♦ v/ PESFCO IA 1 / Lt' ` L18PB3 \ F'";+`' r I Esc. 14 / Se'. 13 ` ' 1 ,�� / , / r Sec. 12 ! ! Sec. 17 r f. f i63CG r ` %7PU Rt-ISi TPFi r : 1 I t 1Vrr ` .4 �1 t ! r Ai.•4Fe.l . r / ♦ 'S r , ` _ -1911Ll)IE P INT UNIT rr + e-4ADL02551 U013N009E• 1 — MID -�ADL025515- --_U01l3NN, / Alt DFB3 , r e�' r L..± t 1 "� 1 L'''I"�-'• 1 ..se r r � y r t L'STiE' ` 24 L rr ♦ �P� Z Ai- I' 1 •.n9 I � 1 . .J ' Sec. t9 ��, Sec. 23 M 22Pe •. . . Sec. -24.. M 20Fe'{ 1 P__. • r � I �` . ' S 21� 16331 kL 13 I AF It a r rih610. � � 1:3sAPezL3,A :-:aA \SP1: �t-ISt_BItL '2A —-24L'PEi 3K.24 EQUIPMEN-T PAD „�__..-__---_-- to Legend •� _ _ _ - - - - • " _2 A - •'. • • MPU M-15i_SHL Other Surface Holes (SHL) ADL025S1T Sec. 24 X_ Other Bottom Hales (BHL) MPU M -15i FPH J23A " - Other Well Paths MPU M-15i_EHL • — — — — J._3_i',.2_— — — at+ Oil and Gas Unit Boundary Pad Footprintze // It 1 6Up DEW: 1V1712D19 Milne Point Unit MPU M-1 5i Well wp_05 Alaska State Plane Zone 4 NAD 1927 0 1,100 2.200 Feet 31.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-15 SB Injector Drilling Procedure TM RTOJEC m Y PAD �` 18 YIFE StiE E�, mm • 0 t SURVEYOR'S CERTIFICATE LEGEND: NOTES; I HERE6Y CMTIFY'THAT 1 AM 1- ALASKA STAGE PLANE 000F AMATES .AK rUC27, ZONE 4. PROPERLY FIEGISTERM AND UCENSM - A$-%tLT CCMGUCTOR T9 PRACTICE UV411 SURIVEM0 IN 2 OECOETIC F'04110MS Aid NM47. THAT SIS BABA -Bu LLT BTE OF �ESETI�T$ WY ■ COSTING CONWCRTR E BASS OF HOR134TAL AMG %ER7,CA: UNTROL S MADE BY WE OR UhMER YY CIR@CT SMJLLCAP S"no I£ SL FRWSIDN Am THAT ALL �,--YyLfi PWINSOMS A44 O1HCA! OCIAILS ARE CORRECT AS OF FEBRUARY 25, =11. � GATE d 9RVEr, YEBRUAMY 21 1019. 6. FEF'E;E4OE. FIMD BOOK HCIB-C1 POI ",1F1 WC LOCATED WITHIN PROTRACTED SEC, 14, T. 13 N., R. 9 E.. UMIAT MERID[kN. ALASKA 'HELL A.S.P. P YcG 12 -Sm 2 - - CELLAR _ SCG 11 COORDINATES SEC 14 5 POSITION 0,01) I M -IG ■ BOX EL I _per N= 1,168.04 70'29'12.776' 70.4868822' ( 25.0' 24.7' M-13 ■ X= 533,993.a4 E= 1.995.03 ilyS 149.7231572' 171' FEL M-14 Y- 6,027,765.67 H-12 ■ 70'29'12.780" 70,4868933' 4.913' FSL 250' 24.7' +M-14 X- 533.903.80 E- 1,904,98 149'43'22.415" M -?13 + 281' FEL 23 M-15 Y- 6,027,765.69 N- 1,168.04 M-15 70.4868845' 4,914' FSL 25.1' 24.7' M-16 X- 533,813.87 E-- 1,815.05 149'43'25,061" 149,7236281' 351' FEL M-16 Y- 6,027.765.37 N- 1,167.73 70'29'17.766' 70.4868847' 4,914' FSL 25.1' 24.9' X= 5331724.10 W -o ■ 145'43'27.703" 149.7243619' 441' FEL GRAPFIC SCALEI MOOSE PAD M-20 Y= 6,027.889.58 N= 1.291.95 0 124 200 4tia 5,039' FSL 25-0' ( IN FEET } X= 533„543.66 E= 1,844.64 149'43`24.16$' 149-7233800' 1 iMh - 2200 fL Milne Point Unit M-15 SB Injector Drilling Procedure TM RTOJEC m Y PAD �` 18 YIFE StiE E�, mm • 0 t SURVEYOR'S CERTIFICATE LEGEND: NOTES; I HERE6Y CMTIFY'THAT 1 AM 1- ALASKA STAGE PLANE 000F AMATES .AK rUC27, ZONE 4. PROPERLY FIEGISTERM AND UCENSM - A$-%tLT CCMGUCTOR T9 PRACTICE UV411 SURIVEM0 IN 2 OECOETIC F'04110MS Aid NM47. THAT SIS BABA -Bu LLT BTE OF �ESETI�T$ WY ■ COSTING CONWCRTR E BASS OF HOR134TAL AMG %ER7,CA: UNTROL S MADE BY WE OR UhMER YY CIR@CT Page 53 1 w I SMJLLCAP S"no I£ SL FRWSIDN Am THAT ALL 4, YPU MOM AVQj dg PAD =" FACTOR 1% Sk044CG13. PWINSOMS A44 O1HCA! OCIAILS ARE CORRECT AS OF FEBRUARY 25, =11. � GATE d 9RVEr, YEBRUAMY 21 1019. 6. FEF'E;E4OE. FIMD BOOK HCIB-C1 POI ",1F1 LOCATED WITHIN PROTRACTED SEC, 14, T. 13 N., R. 9 E.. UMIAT MERID[kN. ALASKA 'HELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR NO, COORDINATES COCRDNATES POSITION OMS POSITION 0,01) OFFSETS EL.EVA71CN BOX EL M-13 Y= 6'027.765.70 N= 1,168.04 70'29'12.776' 70.4868822' 4,913' FSL 25.0' 24.7' X= 533,993.a4 E= 1.995.03 149'43'19.766' 149.7231572' 171' FEL M-14 Y- 6,027,765.67 N= 1,168.02 70'29'12.780" 70,4868933' 4.913' FSL 250' 24.7' X- 533.903.80 E- 1,904,98 149'43'22.415" 149.7228931' 281' FEL M-15 Y- 6,027,765.69 N- 1,168.04 70'29'12.782" 70.4868845' 4,914' FSL 25.1' 24.7' X- 533,813.87 E-- 1,815.05 149'43'25,061" 149,7236281' 351' FEL M-16 Y- 6,027.765.37 N- 1,167.73 70'29'17.766' 70.4868847' 4,914' FSL 25.1' 24.9' X= 5331724.10 E= 1,725.26 145'43'27.703" 149.7243619' 441' FEL M-20 Y= 6,027.889.58 N= 1.291.95 70'29'14.001 70.4872226' 5,039' FSL 25-0' X= 533„543.66 E= 1,844.64 149'43`24.16$' 149-7233800' 321' FEL IgIffillowp Alaska a 1 4h1 e.� "MPU MOOSE PAD AS -BUILT CONDUCTORS HELLS 13,14,15,16,20 Page 53 1 w I Milne Point Unit M-15 SB Injector Hilco Drilling Procedure F-- 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, PPg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110.3 10.5 0 1 11111 500 1000 1500 2000 O 2500 3000 3500 4000 4500 Page 54 MPU L-46 (2015) MPU L-47 (2015) ----MPU L-48 (20 15) MPU L-49 (2015) MPU L-50 (2015) MPU F-106 (2017) MPU F-107 (2017) MPU F-108 (2017) MPU F-109 (2017) MPU F-110 (2017) Hil=E,ew Comp Milne Point Unit M-15 SB Injector Drilling Procedure 33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD uol 5.000 Pipe Body Wall Thickness (ml 0.362 Pipe Body Grade S-135 Drdl Pipe Length Tool Joint SPAYS Connection GPOS50 Tool Joint OD 6.625 Tool Joint ID t-.13-250 Pin Tong 19 Box Tong ni 12 80 % inspection Class Nominal Nominal Weight Designation 19.50 Drill Pipe Approximate Length Elevator SmoothEdge Height nn13132 Raised Tool Joint SPAYS (p-4il 120.000 Upset Type I IEU Max Upset OD (DTE) n1 5.125 Friction Factor 1.0 1.24 Nelle: Tong space may Include Nard'apng. Drill Pipe Performance Drill -Pipe Length Range2 of Drill Pipe with Pipe Body at rr +cst Mair . MUT 43.100 Tension Nominal fleasl ac=1naW 2329 0.36 0.0085 0.72 3Mn,Tension Only 0 564},800 xnun MIJr 36100 Drift Size +In1 3.125 can 1- toaana 32.100 467.400 Note- Od MILL Darnel equal. 42 U9 gallons. Node: Onll ppm assemNy val- ale best a tma0es and tray vary d4[ to ppe body roll doter , Internal plas$l ..aalnp a d other 1acl rz- Connection Performance GPDS50 ( 6.625 ON OD x 3.250 - ID ) 120,000 -) Q JAMSd M* p IT.rsswn at rh-ld x Tenalcrl an I:aisi[cdon I Tool Joint Dimensions Balanced 00 {Int 6.435 Mlrinn-Teat Jcirlt OD 1. API 5.930 P_UChas {In; Mirantm TOW JoIrn 001w 5.93 COL;rd.rb- ""- NV=- The ma i -m make-up %trace should be appiled whena:z pB[ NCtr. Tn rn_lmlm cpn-ci apersdpnal tenzte. a MUT ,T4, - 37,2CC (11.-mz;. zhaul] be .;pled Nominal Tool Joint Torsional Strength tl4lha) 71,800 API Premium Class Tool Joint Tensile Strenath t66) 1.250,000 Elevator Shoulder Information SmoothEdge Height Y32 Raised BOX OD 41e, 6.812 Elevator Capacity 41-111,658,000 Elevator OD 3132 Raised 6.812 (in) Tool Joint Worn to Bevel Worn to Min TJ OD for OD I Diameter I API Premium Class 1&063 15.930 5219 N-: Elevalcr capacity to Man sun e azi E4evancr Pore, no wear factor, and cmlacl %teed or t 10,10Cps1. Assumed Elevator Bore Diameter N6`.e: A raised elevator OD Increa ez eWvaicr caps ty Mthcuf arteci/np make-up torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration ( 5 - OD 0.362 t,n) Wail S-135) Nominal 1 80 brew Inspection Class I API Premium Class IslipCrushing Capacity tme: 498.300 396.500 396.500 dLYe: Sip v'.r:annp SIP mmt-ft lead Is Cal -ft &tn to Sprt.Re JxAd e4uanxr trurn vTM Cees OWPye Assumed Sli Len tIt tn> 16.5 Fat in Te _ir, A.:r Ab b Ca, 1W9'or ale yp WKM ata trait: se 1= factor stW ara Is tF of ne pa ". lip chshirc'i cependert ars plc 9C 0-0 and r"Son, c.1taern or fli t- i; dm cm'167me, ane n Transverse Load Factor (Kl 4.2 ttp&1"1MOD=wai Yanz0w.wV12hlrt9axs. La'GJI LMin die 5la marulatY.(er hx aa33a-isl eft- an. Pipe Bodv Performance Pipe Body Configuration ( 5 tin) OD 0.362 my Wall S-135) Page 55 Note: N-1-1 Buret caculated at 57.5% R84V per AFI. Nominal 80 % Inspection Class API Premium Class Pipe Tensile Strep (1-1712,100 560 800 560 800 Pipe Torsional Strength t1r_itsl 74,100 58.100 58,100 TJ/PipeBody Torsional Ratio 0.97 1.24 124 80% Pipe Torsional Strength a -Its, 59,30D 46.500 46,500 Burst sps t 17,105 15,638 15,638 Colla +ps, 15.672 10.029 10,029 Pipe OD On 1 5.000 4.855 4.855 Wall Thickness m, 0.362 0290 0290 Nominal Pipe ID (in, 4.276 4.276 4276 Cross Sectional Area of Pipe Body -21 5275 4.154 4.154 Cross Sectional Area of OD tut -2i 19.635 18.514 18.514 Cross Sectional Area of ID In12, 14.360 14.360 14.360 Section Modulus tm•aa 5.708 4-476 4.476 Polar Section Modulus (11,31 111.415 18,953 18.953 Note: N-1-1 Buret caculated at 57.5% R84V per AFI. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -15i MPU M -15i Plan: MPU M -15i wp05 Standard Proposal Report 04 October, 2019 Ila] L'N Sperry Drilling Services Project. Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M-151 Design: MPUM-15i wp05 Hilcorp Alaska, LLC Calwlation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Appmach 3D Error Surf- Pedal Curve Waming Method: Error Ratio HALLIBURTON r+P - -.1- Co-ordinate (N/E) Reference: Well Plan: MPU M -15i, True North Vertical (TVD) Reference: M -15i D14 RKR @ 58 40USR Measured Depth Reference: M -15i D14 RK13 @ 58.40usft Calculation Method: Minimum Curvature Longitude Depth From Depth To Survey/Plan Tool FORMATION TOP DETAILS SECTION DETAILS TVDPain T 'Pam MDPath Formation 1331.40 1273.00 137294 S Inc 872.10 1814.00 2095.52 8 R +N/ -S 1908.40 3138.40 1850.00 2151.07 SVt 3080.00 4049.25 LA3 TF- 36&3.40 360.5.00 4923.80 SB NA Annotation 3862.40 3804.00 5812.79 SB OA 0.00 0.00 CASING DETAILS L�4j DSS MD Size Name 0.00 5.fi0 5628.09 9-5/e 95/8x121/4'3.60 0.00 17143.12 6-5/8 6 5/8" x 8 1 /2" ® WELL DETAILS: Plan: MPU M -15i Ground Level: 24.70 SURVEY PROGRAM Date: 2016-06-22700:00:00 Validated: Yes Version: +N/ -S +E/ -W Northing Easting Latittude Longitude Depth From Depth To Survey/Plan Tool SECTION DETAILS N 149° 43'25.061 W 33.70 5828.09 MPU M -15i wp05 (MPU M -15i) 2 MWD+IFR2+MS+Sag Sec MD Inc Azi ND +N/ -S +E/ -W Dleg TF- VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 Ar3 ,' ee ar 0 00 ,1,0' n. ,oA mn m ^ A O- o 4- ^SO Po N O' �i n°jO O, tiN r• on• rrS y n ,off O. 2 400-000.00 we �c ^. F eo. �O' �. O' F 'F A A 1 O p eye O ,yA 'S 0 O h 0.00 400.00 0.00 0.00 0.00 0.00 0.00 0 Stan Dir 3°/100' : 400' MD, 400'lVD 3 1600.00 36.00 153.00 1522.59 -325.00 165.59 3.00 153.00 322.06 Start Dir 4°/100' : 1600' MD, 1522.59TVD 4 1941.96 49.61 150.97 1772.89 -529.37 274.94 4.00 -6.56 528.85 MPU M-15 5 Heel MPU M-15 wp05 CP2 0� 1 r'yil MPU M-15 wp05 Tae I MPU M-15 wp05 CP4 MPU M-15 wp05 CP6 Fault End Dir : 1941.96' MD, 1772.89' ND 5 4490.01 49.61 150.97 3424.01 -2226.21 1216.82 0.00 0.00 2273.67 Start Dir 4°/100' : 4490.01' MD, 3424.01'ND 6 5528.09 84.00 124.99 3832.64 -2897.50 1859.98 4.00 41.08 3185.55 End Dir : 5528.09' MD, 3832.64' ND 7 5828.09 84.00 124.99 3864.00 -3068.59 2104.41 0.00 0.00 3483.90 MPU M-15 wp05 Heel Start Dir 4°/100' : 5828.09' MD, 3864'ND 8 5973.21 89.80 125.00 3871.84 .3151 .67 2223.06 4.00 0.15 3628.75End Dir : 5973.21' MD, 3871.64' ND 9 6313.96 89.80 125.00 3873.00 -3347.13 2502.17 0.00 0.00 3969.49 MPU M-15 wp05 CP1 Start Dir 3°/100' : 6313.96' MD, 3873'ND 10 6351.83 88.67 125.03 3873.50 -3368.86 2533.18 3.00 178.70 4007.36 End Dir : 6351.83' MD, 3873.5' ND 11 6522.94 88.67 125.03 3877.48 -3467.05 2673.25 0.00 0.00 4178.42 Start Dir 3°/100' : 6522.94' MD, 3877.48TVD 12 6564.00 89.90 125-00 3677.99 -3490.61 2706.88 3.00 -1.42 4219.47 End Dir : 6564' MD, 3877.99' ND 13 7714.00 89.90 125.00 3880.00 -4150.22 3648.90 0.00 0.00 5369.47 MPU M-15 wp05 CP2 Start Dir 3°1100' : 7714' MD, 3880TVD 14 7824.80 93.22 125.02 3876.98 4213.76 3739.61 3.00 0.40 5480.22 End Dir : 7824.8' MD, 3876.98' ND 15 8003.57 93.22 125.02 3866.93 -4316.20 3885.77 0.00 0.00 5658.71 Start Dir 3°/100' : 8003.57' MD, 3866.93'ND 16 8114.38 89.90 125.00 3863.91 -4379.74 3976.48 3.00 -179.60 5769.46 End Dir : 8114.38' MD, 3863.91' ND 17 9314.38 89.90 125.00 3866.00 -5068.03 4959.46 0.00 0.00 6969.45 MPU M-15 wp05 CP3 Start Dir 3°/100' : 9314.38' MD, 3866'ND 1 B 9439.04 86.16 125.03 3870.28 .5139.51 5061.48 3.00 179.51 7094.02 End Dir : 9439.04' MD, 3870.28' TVD 19 9561.93 66.16 125.03 3878.51 -5209.89 5161.88 0.00 0.00 7216.64 Start Dir 3'/100': 9561.93' MD, 3878.51'ND 20 9664.93 B9.25 125.00 3882.64 -5268.94 5246.16 3.00 .0.59 7319.54 End Dir : 9664.93' MD, 3882.64' ND 21 10914.93 89.25 125.00 3899.00 -5985.85 6270.01 0.00 0.00 8569.43 MPU M-15 wp05 CP4 Start Dir 3°/100' : 10914.93' MD, 3899TVD 22 11027.86 92.64 125.02 3897.14 -6050.62 6362.48 3.00 0.34 8882.33 End Dir : 11027.86' MO, 3897.147VDO' RT 23 11252.38 92.64 125.02 3886.81 -6179.33 6546.16 0.00 0.00 8906.62 Start Dir 3°/100' : 11252.38' MD, 3886.81TVD 24 11365.31 89.25 125.00 3884.95 -6244.10 6638.63 3.00 -179.66 9019.51 End Dir : 11365.31' MD, 3884.95' ND 25 12515.31 89.25 125.00 3900.00 -6903.66 7580.57 0.00 0.00 10169.41 MPU M-15 Wp05 CP5 Start Dir 3°/100' : 12515.31' MD, 3900TVD 26 12635.51 85.64 125.02 3905.35 -6972.54 7678.90 3.00 179.63 10289.47 End Dir : 12635.51' M0, 3905.35' ND 27 12794.24 85.64 125.02 3917.41 -7063.37 7808.52 0.00 0.00 10447.75 Start Dir Y/100': 12794.24' MD, 3917.41'ND 28 12916.10 89.30 125.00 3922.78 -7133.21 7908.21 3.00 -0.37 10569.47 End Dir : 12916.1' MD, 3922.78' ND 29 13916.10 89.30 125.00 3935.00 -7706.75 8727.31 0.00 0.00 11569.40 MPU M-15 wp05 CPS Start Dir Y/100': 13916.1' MD, 3935'N 30 13979.49 91.20 125.01 3934.72 -7743.11 8779.22 3.00 0.39 11632.78 End Dir : 13979.49' MD, 3934.72' ND 31 14315.89 91.20 125.01 3927.67 -7936.08 9054.68 0.00 0.00 11969.11 Start Dir 3.1100': 14315.89' MD, 3927.67'ND 32 14316.32 91.20 125.00 3927.66 -7936.33 9055.03 3.00 -96.63 11969.54 Start Dir 3°1100' : 14315.89' MD, 3927.67TVD 33 15016.32 91.20 125.00 3913.00 -8337.74 9628.31 0.00 0.00 12669.39 MPU M-15 vp05 CP7 Start Dir 3°1100' : 15016.32' MD, 3913TVD 34 15035.24 91.77 125.01 3912.51 -8348.59 9643.80 3.00 0.78 12688.29 End Dir : 15035.24' MD, 3912.51' ND 35 16192.54 91.77 125.01 3876.82 -9012.20 10591.27 0.00 0.00 13845.04 Start Dir 3°/100': 16192.54'MD, 3876.82 TVD 36 16243.12 90.25 125.00 3875.93 -9041.21 10632.69 3.00 -179.71 13895.61 End Dir : 16243.12' MD, 3875.93' ND 37 17143.12 90.25 125.00 3872.00 -9557.42 11369.92 0.00 0.00 14795.61 MPU M-15 wp05 Toe Total Depth : 17143.12' MD, 3872' ND ® WELL DETAILS: Plan: MPU M -15i Ground Level: 24.70 SURVEY PROGRAM Date: 2016-06-22700:00:00 Validated: Yes Version: +N/ -S +E/ -W Northing Easting Latittude Longitude Depth From Depth To Survey/Plan Tool 0.00 0.00 6027765.69 533813.87 70' 29' 12.784 N 149° 43'25.061 W 33.70 5828.09 MPU M -15i wp05 (MPU M -15i) 2 MWD+IFR2+MS+Sag 5828.09 17143.12 MPU MA5i wp05(MPU M-151) 2_MWD+IFR2+MS+Sag -1000 Start Dir 3°/100' : 400' MD, 400TVD U Stan Dir 411..': 1(10.' MD, 1522591VD o^ O O ti O O F End Dir :1941.96' MD, 1772.89' TVD 500 SCO neery �O' ^ O? ^"'^1 �O �]O ere 0�O O O O o X10 �O ZO O 1000 1000 Q SVS ... .. .... O ^ h ZO m� �°° n^' O N Ar3 ,' ee ar 0 00 ,1,0' n. ,oA mn m ^ A O- o 4- ^SO Po N O' �i n°jO O, tiN r• on• rrS y n ,off O. 8PRF eco A O we �c ^. F eo. �O' �. O' F 'F A A 1 O p eye O ,yA 'S 0 O h a 2000 m Q p ..: ... _, ryy a o .` .. - O O o O' A. o me F O^ ^� �S ti O- ^ �S ^ry m' a a`O g^ e`o h ,sa' F e FO. e6' �O' ^. 0 c,Ory od eor SVt 00 m a O O' 8 ee O� - " m a 4 0 1= LA3 O00 , �F 4i ,ec ^ y 3000. � 1 i �e a� dao q-6 -, oy .� ' �`,'V� 4?4 � ear O 58_NA O D , ^ .,� c mZ, 65/8"X81/2' H 5 4000 Se_OA - ` _ _ _ - _ - _ - _ __ _ __ 95/ 8" z 12 1/4° on c� rn 'a cn o v 'MPU MAN wp05 o o ' MPU M-15 5 Heel MPU M-15 wp05 CP2 0� 1 r'yil MPU M-15 wp05 Tae I MPU M-15 wp05 CP4 MPU M-15 wp05 CP6 Fault 5000 MPU M-15 Wp05 CP3 MPU M-15 wp05 CP1 MPU M-15 05 CPS � MPU M-15 wp05 CP7 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 Vertical Section at 125.00° (2000 usfUin) Project: Milne Point WELL DETAMS: ?I—: WUM-15i Site: M Pt Moose Pad Ground1-1: 14.11 Well: Plan: MPU M-151 +N.' -S +E/ -W Northing Emting Wtitw& 3ungiw& o_ Start Dir YAW: 400' MD, 400'ND ---- Wellbore: MPU M -15i O.W 0.00 6027765.69 533813.87 O'29'12.784N 49'43'25.O61W Start Dir4"/100': IfiORMD, 1522.597VD Plan: MPU M-151 wp05 CASTNG DETATLS _ _ - - - - Ed Dir . 1941.96' MD, 1772.89' WD ND -750 HALL16UgTCN _ l3Perry orunos ® 3864.00 3872.00 TVDSS MD Size Name 3805.61 7828.09 9-5/8 95/8"x121/4„ 3813.60 17143.12 6-5/8 6 5/8" r 8 1/2" -1500 Stan Dir4°/100' :4490.01' MD, 3424.01TVD REFERENCE INFORMATION End DM :552&09- MD, 3832.64' TVD C inale (NIE) Reference: Well Plan: MPU M -15i, True NOM Venice] (Ml Reference: W 5i 014 Rn ® M.40usft Measuretl Depth Reference: W 5i D14 RKB ® MAOft Slaty Dir4'/100': 5828.09'MD, 38647VD Calculation Meth :Minimum C—r. -2250 End Du : 5973 21' MD, 3871.84' TVD Start Dir 3'/100' : 6313.96' MD, 3873'TVD " End Dir : 1311,13'111D, 3873.5' TVD -3000 9 5/8" x 12 I/4"_-' MPI: N1-15 wp05 Hccl -� ��''---_- End Dir :6564'MD,3877.99'TVD Start Dir 3°/100' : 7714' NO, 3830'TVD C -3750 MPU M-15 Wp05 CP I ' End Dir : 7824.8' MD, 3876.98' WD Dir 3'/100': 8003.57' MD, 3866.939VD C '� _-_ ____- End Dir: 8114.38'MD, 3863.9 P TVD -4500 MPU M-15 upO5 CP2 Stan Dir 3'/100': 9314.38'MD, 38669 -VD Ed - Di, : 9439.04' NO, 3870.28' TVD z MPL'NI-15xp05 CP3= Stan Dir 3'/100': 9561.93' MD, 3878.517VD 5'50 - End Dir :9664.93' MD, 3882.64' TVD Stan Dir3°/100': 1091493' MD, 3899rVD N End Dir : 11017.86' MD, 3897.I49VD -6000 - - - � Start Dir 3'/IM" 1125238' MD, 3886.81'TVD NIPU M-15 xp05 CT4 - _ - End Dir :11365.31' MD,1884.95' TVD -6750-- End Dir : 12635.51' MD, 3905.35' TVD -' "- Start Dir3°/100':12794.24'MD,3917.41'WD hfPU M-15 xp05 CP5--______ End Dv :12916.1' MD, 3922.78' TVD -7500 S— Dir 3'/100': 13916. V MD, 3935TVD _ _ _ _ _ _ - Ed Dv : 13979.49' MD, 3934.72' TVD NfPL'NI-I5 wpO5 CP6 _ Start Di, 3°/100': 14315.89' KBI 392767nVD -8250 End Dir : 14316.32' MD, 3927.66' TVD -- --'-Stan Di, 3°/100': 15016.32' MD, 3913'rVD MPU M-15 x,05 CP7 land Dix : 15035.24' MD, 3912.51' TVD P;mlt Stan Dn 3°/100': 16191.54MD, 3876.82rVD -9000 - - - - - - - --End Dir :16243.12' MD, 7875.93' TVD Total Depth: 17143.12' MD, 3872' TVD MPU M-15 xp05 Toe- -9750 MPU M -15i up05 6 5/8" a 8 1/2" 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 West( -)/East(+) (1500 ustUin) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M -15i Design: MPU M-1 5i wp05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -15i TVD Reference: M -15i D14 RKB @ 58.40usft MD Reference: M -15i D14 RKB @ 58.40usft 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 Site M Pt Moose Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Plan: MPU M -15i Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation Wellbore MPU M -15i Magnetics Model Name Sample Date BGGM2018 11/1/2019 Design MPU M-1 5i wp05 Audit Notes: Version: Vertical Section: 6,027,877.65usft Latitude: 533,363.92 usft Longitude: 13-3/16" Grid Convergence: 70° 29' 13.905 N 149° 43'38.286 W 0.26 ° 6,027,765.69 usfl Latitude: 70° 29' 12.784 N 533,813.87 usfl Longitude: 149° 43'25.061 W 0.00 usfl Ground Level: 24.70 usft Declination Dip Angle Field Strength (') (') (nT) 16.39 80.94 57,409.01739771 Phase: PLAN Tie On Depth Depth From (TVD) +N/ -S +E/ -W (usft) (usft) (usft) 33.70 0.00 0.00 33.70 Direction (I 125.00 10/4/2019 1:47:50PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -15i Company: Hilcorp Alaska, LLC TVD Reference: M-1 5i D14 RKB @ 58.40usft Project: Milne Point MD Reference: M -15i D14 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -15i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -15i Design: MPU M -15i wp05 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +Nl-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 0.00 400.00 0.00 0.00 400.00 341.60 0.00 0.00 0.00 0.00 0.00 0.00 1,600.00 36.00 153.00 1,522.59 1,464.19 -325.00 165.59 3.00 3.00 0.00 153.00 1,941.96 49.61 150.97 1,772.89 1,714.49 -529.37 274.94 4.00 3.98 -0.59 -6.56 4,490.01 49.61 150.97 3,424.01 3,365.61 -2,226.21 1,216.82 0.00 0.00 0.00 0.00 5,528.09 84.00 124.99 3,832.64 3,774.24 -2,897.50 1,859.98 4.00 3.31 -2.50 -41.08 5,828.09 84.00 124.99 3,864.00 3,805.60 -3,068.59 2,104.41 0.00 0.00 0.00 0.00 5,973.21 89.80 125.00 3,871.84 3,813.44 -3,151.67 2,223.06 4.00 4.00 0.01 0.15 6,313.96 89.80 125.00 3,873.00 3,814.60 -3,347.13 2,502.17 0.00 0.00 0.00 0.00 6,351.83 88.67 125.03 3,873.50 3,815.10 -3,368.86 2,533.18 3.00 -3.00 0.07 178.70 6,522.94 88.67 125.03 3,877.48 3,819.08 -3,467.05 2,673.25 0.00 0.00 0.00 0.00 6,564.00 89.90 125.00 3,877.99 3,819.59 -3,490.61 2,706.88 3.00 3.00 -0.07 -1.42 7,714.00 89.90 125.00 3,880.00 3,821.60 -4,150.22 3,648.90 0.00 0.00 0.00 0.00 7,824.80 93.22 125.02 3,876.98 3,818.58 -4,213.76 3,739.61 3.00 3.00 0.02 0.40 8,003.57 93.22 125.02 3,866.93 3,808.53 -4,316.20 3,885.77 0.00 0.00 0.00 0.00 8,114.38 89.90 125.00 3,863.91 3,805.51 -4,379.74 3,976.48 3.00 -3.00 -0.02 -179.60 9,314.38 89.90 125.00 3,866.00 3,807.60 -5,068.03 4,959.46 0.00 0.00 0.00 0.00 9,439.04 86.16 125.03 3,870.28 3,811.88 -5,139.51 5,061.48 3.00 -3.00 0.03 179.51 9,561.93 86.16 125.03 3,878.51 3,820.11 -5,209.89 5,161.88 0.00 0.00 0.00 0.00 9,664.93 89.25 125.00 3,882.64 3,824.24 -5,268.94 5,246.16 3.00 3.00 -0.03 -0.59 10,914.93 89.25 125.00 3,899.00 3,840.60 -5,985.85 6,270.01 0.00 0.00 0.00 0.00 11,027.86 92.64 125.02 3,897.14 3,838.74 -6,050.62 6,362.48 3.00 3.00 0.02 0.34 11,252.38 92.64 125.02 3,886.81 3,828.41 -6,179.33 6,546.16 0.00 0.00 0.00 0.00 11,365.31 89.25 125.00 3,884.95 3,826.55 -6,244.10 6,638.63 3.00 -3.00 -0.02 -179.66 12,515.31 89.25 125.00 3,900.00 3,841.60 -6,903.66 7,580.57 0.00 0.00 0.00 0.00 12,635.51 85.64 125.02 3,905.35 3,846.95 -6,972.54 7,678.90 3.00 -3.00 0.02 179.63 12,794.24 85.64 125.02 3,917.41 3,859.01 -7,063.37 7,808.52 0.00 0.00 0.00 0.00 12,916.10 89.30 125.00 3,922.78 3,864.38 -7,133.21 7,908.21 3.00 3.00 -0.02 -0.37 13,916.10 89.30 125.00 3,935.00 3,876.60 -7,706.75 8,727.31 0.00 0.00 0.00 0.00 13,979.49 91.20 125.01 3,934.72 3,876.32 -7,743.11 8,779.22 3.00 3.00 0.02 0.39 14,315.89 91.20 125.01 3,927.67 3,869.27 -7,936.08 9,054.68 0.00 0.00 0.00 0.00 14,316.32 91.20 125.00 3,927.66 3,869.26 -7,936.33 9,055.03 3.00 -0.35 -2.98 -96.63 15,016.32 91.20 125.00 3,913.00 3,854.60 -8,337.74 9,628.31 0.00 0.00 0.00 0.00 15,035.24 91.77 125.01 3,912.51 3,854.11 -8,348.59 9,643.80 3.00 3.00 0.04 0.78 16,192.54 91.77 125.01 3,876.82 3,818.42 -9,012.20 10,591.27 0.00 0.00 0.00 0.00 16,243.12 90.25 125.00 3,875.93 3,817.53 -9,041.21 10,632.69 3.00 -3.00 -0.02 -179.71 17,143.12 90.25 125.00 3,872.00 3,813.60 -9,557.42 11,369.92 0.00 0.00 0.00 0.00 10/412019 1:47:50PM Page 3 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M-1 5i Design: MPU M -15i wp05 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -15i M -15i D14 RKB @ 58.40usft M -15i D14 RKB @ 58.40usft True Minimum Curvature 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) -24.70 33.70 0.00 0.00 33.70 -24.70 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 100.00 0.00 0.00 100.00 41.60 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 200.00 0.00 0.00 200.00 141.60 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 300.00 0.00 0.00 300.00 241.60 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 400.00 0.00 0.00 400.00 341.60 0.00 0.00 6,027,765.69 533,813.87 0.00 0.00 Start Dir 3°/100' : 400' MD, 400'TVD 500.00 3.00 153.00 499.95 441.55 -2.33 1.19 6,027,763.36 533,815.07 3.00 2.31 600.00 6.00 153.00 599.63 541.23 -9.32 4.75 6,027,756.39 533,818.66 3.00 9.24 700.00 9.00 153.00 698.77 640.37 -20.95 10.67 6,027,744.79 533,824.64 3.00 20.76 800.00 12.00 153.00 797.08 738.68 -37.19 18.95 6,027,728.59 533,832.98 3.00 36.85 900.00 15.00 153.00 894.31 835.91 -57.98 29.54 6,027,707.85 533,843.67 3.00 57.46 1,000.00 18.00 153.00 990.18 931.78 -83.29 42.44 6,027,682.61 533,856.68 3.00 82.53 1,100.00 21.00 153.00 1,084.43 1,026.03 -113.03 57.59 6,027,652.94 533,871.97 3.00 112.00 1,200.00 24.00 153.00 1,176.81 1,118.41 -147.12 74.96 6,027,618.93 533,889.49 3.00 145.79 1,300.00 27.00 153.00 1,267.06 1,208.66 -185.47 94.50 6,027,580.67 533,909.21 3.00 183.80 1,372.94 29.19 153.00 1,331.40 1,273.00 -216.08 110.10 6,027,550.14 533,924.94 3.00 214.12 SV5 1,400.00 30.00 153.00 1,354.93 1,296.53 -227.98 116.16 6,027,538.26 533,931.06 3.00 225.92 1,500.00 33.00 153.00 1,440.18 1,381.78 -274.53 139.88 6,027,491.82 533,954.98 3.00 272.05 1,600.00 36.00 153.00 1,522.59 1,464.19 -325.00 165.59 6,027,441.48 533,980.92 3.00 322.06 Start Dir 40/100' : 1600' MD, 1522.59'TVD 1,700.00 39.98 152.29 1,601.39 1,542.99 -379.64 193.89 6,027,386.97 534,009.46 4.00 376.58 1,800.00 43.96 151.69 1,675.73 1,617.33 -438.66 225.30 6,027,328.10 534,041.14 4.00 436.16 1,900.00 47.94 151.17 1,745.24 1,686.84 -501.76 259.67 6,027,265.17 534,075.80 4.00 500.51 1,941.96 49.61 150.97 1,772.90 1,714.50 -529.37 274.94 6,027,237.62 534,091.19 4.00 528.86 End Dir : 1941.96' MD, 1772.89' TVD 2,000.00 49.61 150.97 1,810.51 1,752.11 -568.03 296.40 6,027,199.07 534,112.82 0.00 568.60 2,095.52 49.61 150.97 1,872.40 1,814.00 -631.63 331.70 6,027,135.63 534,148.41 0.00 634.01 BPRF 2,100.00 49.61 150.97 1,875.30 1,816.90 -634.62 333.36 6,027,132.66 534,150.08 0.00 637.08 2,151.07 49.61 150.97 1,908.40 1,850.00 -668.63 352.24 6,027,098.73 534,169.11 0.00 672.05 SVi 2,200.00 49.61 150.97 1,940.10 1,881.70 -701.21 370.33 6,027,066.24 534,187.34 0.00 705.55 2,300.00 49.61 150.97 2,004.90 1,946.50 -767.81 407.29 6,026,999.82 534,224.61 0.00 774.03 2,400.00 49.61 150.97 2,069.70 2,011.30 -834.40 444.25 6,026,933.40 534,261.87 0.00 842.50 2,500.00 49.61 150.97 2,134.50 2,076.10 -900.99 481.22 6,026,866.98 534,299.13 0.00 910.98 2,600.00 49.61 150.97 2,199.30 2,140.90 -967.59 518.18 6,026,800.57 534,336.40 0.00 979.46 2,700.00 49.61 150.97 2,264.10 2,205.70 -1,034.18 555.15 6,026,734.15 534,373.66 0.00 1,047.93 2,800.00 49.61 150.97 2,328.90 2,270.50 -1,100.77 592.11 6,026,667.73 534,410.92 0.00 1,116.41 2,900.00 49.61 150.97 2,393.70 2,335.30 -1,167.37 629.08 6,026,601.31 534,448.19 0.00 1,184.88 3,000.00 49.61 150.97 2,458.50 2,400.10 -1,233.96 666.04 6,026,534.89 534,485.45 0.00 1,253.36 3,100.00 49.61 150.97 2,523.29 2,464.89 -1,300.55 703.01 6,026,468.47 534,522.71 0.00 1,321.84 3,200.00 49.61 150.97 2,588.09 2,529.69 -1,367.15 739.97 6,026,402.06 534,559.98 0.00 1,390.31 3,300.00 49.61 150.97 2,652.89 2,594.49 -1,433.74 776.94 6,026,335.64 534,597.24 0.00 1,458.79 3,400.00 49.61 150.97 2,717.69 2,659.29 -1,500.33 813.90 6,026,269.22 534,634.50 0.00 1,527.27 10/4/2019 1:47:50PM Page 4 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M -15i Design: MPU M -15i wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -15i TVD Reference: M-1 5i D14 RKB @ 58.40usft MD Reference: M -15i D14 RKB @ 58.40usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (1) (usft) usft (usft) 3,500.00 49.61 150.97 2,782.49 2,724.09 -1,566.93 3,600.00 49.61 150.97 2,847.29 2,788.89 -1,633.52 3,700.00 49.61 150.97 2,912.09 2,853.69 -1,700.11 3,800.00 49.61 150.97 2,976.89 2,918.49 -1,766.71 3,900.00 49.61 150.97 3,041.69 2,983.29 -1,833.30 4,000.00 49.61 150.97 3,106.49 3,048.09 -1,899.89 4,049.25 49.61 150.97 3,138.40 3,080.00 -1,932.69 LA3 6,025,671.46 534,969.88 0.00 2,143.55 1,183.55 4,100.00 49.61 150.97 3,171.29 3,112.89 -1,966.49 4,200.00 49.61 150.97 3,236.08 3,177.68 -2,033.08 4,300.00 49.61 150.97 3,300.88 3,242.48 -2,099.67 4,400.00 49.61 150.97 3,365.68 3,307.28 -2,166.27 4,490.01 49.61 150.97 3,424.01 3,365.61 -2,226.21 Start Dir 4/100' : 4490.01' MD, 3424.01 TVD 2,592.95 4,500.00 49.91 150.62 3,430.46 3,372.06 -2,232.87 4,600.00 52.98 147.35 3,492.79 3,434.39 -2,299.84 4,700.00 56.14 144.33 3,550.77 3,492.37 -2,367.21 4,800.00 59.36 141.53 3,604.13 3,545.73 -2,434.65 4,900.00 62.64 138.91 3,652.61 3,594.21 -2,501.83 4,923.80 63.43 138.31 3,663.40 3,605.00 -2,517.74 SB NA 535,686.82 4.00 3,185.54 1,918.57 6,024,836.22 5,000.00 65.97 136.44 3,695.96 3,637.56 -2,568.42 5,100.00 69.33 134.10 3,733.99 3,675.59 -2,634.10 5,200.00 72.73 131.86 3,766.49 3,708.09 -2,698.54 5,300.00 76.14 129.70 3,793.33 3,734.93 -2,761.44 5,400.00 79.58 127.61 3,814.35 3,755.95 -2,822.49 5,500.00 83.03 125.56 3,829.47 3,771.07 -2,881.38 5,528.09 84.00 124.99 3,832.64 3,774.24 -2,897.50 End Dir : 5528.09' MD, 3832.64' TVD 6,024,495.24 536,237.35 5,600.00 84.00 124.99 3,840.16 3,781.76 -2,938.51 5,700.00 84.00 124.99 3,850.61 3,792.21 -2,995.54 5,800.00 84.00 124.99 3,861.06 3,802.66 -3,052.57 5,812.79 84.00 124.99 3,862.40 3,804.00 -3,059.86 SB OA 5,828.09 84.00 124.99 3,864.00 3,805.60 -3,068.59 Start Dir 4°/100' : 5828.09' MD, 3864'TVD - 9 5/8" x 12 1/4" 5,900.00 86.88 125.00 3,869.72 3,811.32 -3,109.69 5,973.21 89.80 125.00 3,871.84 3,813.44 -3,151.66 End Dir : 5973.21' MD, 3871.84' TVD 6,000.00 89.80 125.00 3,871.93 3,813.53 -3,167.03 6,100.00 89.80 125.00 3,872.27 3,813.87 -3,224.40 6,200.00 89.80 125.00 3,872.61 3,814.21 -3,281.76 6,300.00 89.80 125.00 3,872.95 3,814.55 -3,339.12 6,313.96 89.80 125.00 3,873.00 3,814.60 -3,347.13 Start Dir 3°/100' : 6313.96' MD, 3873'TVD 10/412019 1:47:50PM Page 5 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,724.09 850.87 6,026,202.80 534,671.77 0.00 1,595.74 887.83 6,026,136.38 534,709.03 0.00 1,664.22 924.80 6,026,069.97 534,746.29 0.00 1,732.69 961.76 6,026,003.55 534,783.56 0.00 1,801.17 998.73 6,025,937.13 534,820.82 0.00 1,869.65 1,035.69 6,025,870.71 534,858.09 0.00 1,938.12 1,053.90 6,025,838.00 534,876.44 0.00 1,971.85 1,072.66 6,025,804.29 534,895.35 0.00 2,006.60 1,109.62 6,025,737.88 534,932.61 0.00 2,075.08 1,146.59 6,025,671.46 534,969.88 0.00 2,143.55 1,183.55 6,025,605.04 535,007.14 0.00 2,212.03 1,216.82 6,025,545.26 535,040.68 0.00 2,273.66 1,220.54 6,025,538.62 535,044.43 4.00 2,280.53 1,260.87 6,025,471.83 535,085.05 4.00 2,351.97 1,306.64 6,025,404.68 535,131.13 4.00 2,428.11 1,357.63 6,025,337.48 535,182.42 4.00 2,508.57 1,413.61 6,025,270.56 535,238.70 4.00 2,592.95 1,427.64 6,025,254.71 535,252.80 4.00 2,613.57 1,474.29 6,025,204.26 535,299.67 4.00 2,680.85 1,539.38 6,025,138.88 535,365.05 4.00 2,771.84 1,608.56 6,025,074.76 535,434.52 4.00 2,865.47 1,681.49 6,025,012.19 535,507.73 4.00 2,961.30 1,757.83 6,024,951.50 535,584.34 4.00 3,058.84 1,837.19 6,024,892.97 535,663.96 4.00 3,157.63 1,859.98 6,024,876.96 535,686.82 4.00 3,185.54 1,918.57 6,024,836.22 535,745.59 0.00 3,257.06 2,000.04 6,024,779.57 535,827.31 0.00 3,356.51 2,081.52 6,024,722.92 535,909.04 0.00 3,455.96 2,091.94 6,024,715.67 535,919.49 0.00 3,468.68 2,104.41 6,024,707.00 535,932.00 0.00 3,483.90 2,163.12 6,024,666.17 535,990.89 4.00 3,555.57 2,223.06 6,024,624.48 536,051.02 4.00 3,628.75 2,245.00 6,024,609.21 536,073.03 0.00 3,655.54 2,326.91 6,024,552.22 536,155.19 0.00 3,755.53 2,408.82 6,024,495.24 536,237.35 0.00 3,855.53 2,490.73 6,024,438.25 536,319.51 0.00 3,955.53 2,502.17 6,024,430.30 536,330.98 0.00 3,969.49 10/412019 1:47:50PM Page 5 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -15i Company: Hilcorp Alaska, LLC TVD Reference: M -15i D14 RKB @ 58.40usft Project: Milne Point MD Reference: M -15i D14 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -15i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -15i Design: MPU M -15i 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) 3,815.10 6,351.83 88.67 125.03 3,873.50 3,815.10 -3,368.86 2,533.18 6,024,408.71 536,362.09 3.00 4,007.36 End Dir : 6351.83' MD, 3873.5' ND 6,400.00 88.67 125.03 3,874.62 3,816.22 -3,396.50 2,572.61 6,024,381.25 536,401.64 0.00 4,055.52 6,500.00 88.67 125.03 3,876.95 3,818.55 -3,453.89 2,654.48 6,024,324.24 536,483.76 0.00 4,155.49 6,522.94 88.67 125.03 3,877.48 3,819.08 -3,467.05 2,673.26 6,024,311.17 536,502.60 0.00 4,178.42 Start Dir 30/100': 6522.94' MD, 3877.48'TVD 6,564.00 89.90 125.00 3,877.99 3,819.59 -3,490.61 2,706.88 6,024,287.76 536,536.32 3.00 4,219.48 End Dir : 6564' MD, 3877.99' TVD 6,600.00 89.90 125.00 3,878.06 3,819.66 -3,511.26 2,736.37 6,024,267.25 536,565.90 0.00 4,255.48 6,700.00 89.90 125.00 3,878.23 3,819.83 -3,568.62 2,818.28 6,024,210.27 536,648.07 0.00 4,355.48 6,800.00 89.90 125.00 3,878.40 3,820.00 -3,625.98 2,900.20 6,024,153.29 536,730.24 0.00 4,455.48 6,900.00 89.90 125.00 3,878.58 3,820.18 -3,683.33 2,982.11 6,024,096.32 536,812.40 0.00 4,555.48 7,000.00 89.90 125.00 3,878.75 3,820.35 -3,740.69 3,064.03 6,024,039.34 536,894.57 0.00 4,655.48 7,100.00 89.90 125.00 3,878.93 3,820.53 -3,798.05 3,145.95 6,023,982.36 536,976.74 0.00 4,755.48 7,200.00 89.90 125.00 3,879.10 3,820.70 -3,855.41 3,227.86 6,023,925.38 537,058.91 0.00 4,855.48 7,300.00 89.90 125.00 3,879.28 3,820.88 -3,912.76 3,309.78 6,023,868.40 537,141.07 0.00 4,955.48 7,400.00 89.90 125.00 3,879.45 3,821.05 -3,970.12 3,391.69 6,023,811.42 537,223.24 0.00 5,055.48 7,500.00 89.90 125.00 3,879.63 3,821.23 -4,027.48 3,473.61 6,023,754.44 537,305.41 0.00 5,155.48 7,600.00 89.90 125.00 3,879.80 3,821.40 -4,084.84 3,555.52 6,023,697.46 537,387.57 0.00 5,255.48 7,700.00 89.90 125.00 3,879.98 3,821.58 -4,142.19 3,637.44 6,023,640.48 537,469.74 0.00 5,355.48 7,714.00 89.90 125.00 3,880.00 3,821.60 -4,150.22 3,648.90 6,023,632.51 537,481.24 0.00 5,369.48 Start Dir 31/100': 7714' MD, 3880'TVD 7,800.00 92.48 125.02 3,878.21 3,819.81 -4,199.55 3,719.32 6,023,583.51 537,551.88 3.00 5,455.45 7,824.80 93.22 125.02 3,876.98 3,818.58 -4,213.76 3,739.61 6,023,569.39 537,572.23 3.00 5,480.22 End Dir : 7824.8' MD, 3876.98' ND 7,900.00 93.22 125.02 3,872.75 3,814.35 -4,256.85 3,801.09 6,023,526.58 537,633.90 0.00 5,555.30 8,003.57 93.22 125.02 3,866.93 3,808.53 -4,316.20 3,885.77 6,023,467.63 537,718.84 0.00 5,658.71 Start Dir 31/100': 8003.57' MD, 3866.93'TVD 8,100.00 90.33 125.00 3,863.93 3,805.53 -4,371.49 3,964.70 6,023,412.70 537,798.02 3.00 5,755.08 8,114.38 89.90 125.00 3,863.91 3,805.51 -4,379.74 3,976.48 6,023,404.50 537,809.83 3.00 5,769.46 End Dir : 8114.38' MD, 3863.91' TVD 83200.00 89.90 125.00 3,864.06 3,805.66 -4,428.85 4,046.62 6,023,355.72 537,880.18 0.00 5,855.08 8,300.00 89.90 125.00 3,864.23 3,805.83 -4,486.21 4,128.53 6,023,298.74 537,962.35 0.00 5,955.08 8,400.00 89.90 125.00 3,864.40 3,806.00 -4,543.57 4,210.45 6,023,241.76 538,044.52 0.00 6,055.08 8,500.00 89.90 125.00 3,864.58 3,806.18 -4,600.92 4,292.36 6,023,184.78 538,126.68 0.00 6,155.08 8,600.00 89.90 125.00 3,864.75 3,806.35 -4,658.28 4,374.28 6,023,127.80 538,208.85 0.00 6,255.08 8,700.00 89.90 125.00 3,864.93 3,806.53 -4,715.64 4,456.19 6,023,070.82 538,291.02 0.00 6,355.08 83800.00 89.90 125.00 3,865.10 3,806.70 -4,773.00 4,538.11 6,023,013.85 538,373.18 0.00 6,455.08 8,900.00 89.90 125.00 3,865.28 3,806.88 -4,830.35 4,620.02 6,022,956.87 538,455.35 0.00 6,555.08 9,000.00 89.90 125.00 3,865.45 3,807.05 -4,887.71 4,701.94 6,022,899.89 538,537.52 0.00 6,655.08 9,100.00 89.90 125.00 3,865.63 3,807.23 -4,945.07 4,783.85 6,022,842.91 538,619.68 0.00 6,755.08 9,200.00 89.90 125.00 3,865.80 3,807.40 -5,002.43 4,865.77 6,022,785.93 538,701.85 0.00 6,855.08 9,300.00 89.90 125.00 3,865.97 3,807.57 -5,059.78 4,947.68 6,022,728.95 538,784.02 0.00 6,955.08 9,314.38 89.90 125.00 3,866.00 3,807.60 -5,068.03 4,959.46 6,022,720.76 538,795.83 0.00 6,969.46 Start Dir 3°/100' : 9314.38' MD, 3866'TVD 10/4/2019 1:47.50PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M -15i Design: MPU M -15i wp05 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 9,400.00 87.33 125.02 3,868.07 3,809.67 9,439.04 86.16 125.03 3,870.28 3,811.88 End Dir : 9439.04' MD, 3870.28' TVD 6,022,649.75 9,500.00 86.16 125.03 3,874.37 3,815.97 9,561.93 86.16 125.03 3,878.51 3,820.11 Start Dir 3°/100' : 9561.93' MD, 3878.517VD 9,600.00 87.30 125.02 3,880.68 3,822.28 9,664.93 89.25 125.00 3,882.64 3,824.24 End Dir : 9664.93' MD, 3882.64' TVD 6,022,521.18 9,700.00 89.25 125.00 3,883.10 3,824.70 9,800.00 89.25 125.00 3,884.41 3,826.01 9,900.00 89.25 125.00 3,885.72 3,827.32 10,000.00 89.25 125.00 3,887.02 3,828.62 10,100.00 89.25 125.00 3,888.33 3,829.93 10,200.00 89.25 125.00 3,889.64 3,831.24 10,300.00 89.25 125.00 3,890.95 3,832.55 10,400.00 89.25 125.00 3,892.26 3,833.86 10,500.00 89.25 125.00 3,893.57 3,835.17 10,600.00 89.25 125.00 3,894.88 3,836.48 10,700.00 89.25 125.00 3,896.19 3,837.79 10,800.00 89.25 125.00 3,897.50 3,839.10 10,900.00 89.25 125.00 3,898.80 3,840.40 10,914.93 89.25 125.00 3,899.00 3,840.60 Start Dir 3°/100' : 10914.93' MD, 38997VD 540,015.99 11,000.00 91.80 125.02 3,898.22 3,839.82 11,027.86 92.64 125.02 3,897.14 3,838.74 End Dir : 11027.86' MD, 3897.14'TVDO° RT TF 11,100.00 92.64 125.02 3,893.82 3,835.42 11,200.00 92.64 125.02 3,889.22 3,830.82 11,252.38 92.64 125.02 3,886.81 3,828.41 Start Dir 31/100': 11252.38' MD, 3886.81'TVD 11,300.00 91.21 125.01 3,885.21 3,826.81 11,365.31 89.25 125.00 3,884.95 3,826.55 End Dir : 11365.31' MD, 3884.95' TVD 6,021,589.67 11,400.00 89.25 125.00 3,885.40 3,827.00 11,500.00 89.25 125.00 3,886.71 3,828.31 11,600.00 89.25 125.00 3,888.02 3,829.62 11,700.00 89.25 125.00 3,889.33 3,830.93 11,800.00 89.25 125.00 3,890.64 3,832.24 11,900.00 89.25 125.00 3,891.95 3,833.55 12,000.00 89.25 125.00 3,893.25 3,834.85 12,100.00 89.25 125.00 3,894.56 3,836.16 12,200.00 89.25 125.00 3,895.87 3,837.47 12,300.00 89.25 125.00 3,897.18 3,838.78 12,400.00 89.25 125.00 3,898.49 3,840.09 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-1 5i M -15i D14 RKB @ 58.40usft M -15i D14 RKB @ 58.40usft True Minimum Curvature 10/42019 1:47:50PM Page 7 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,809.67 -5,117.14 5,029.56 6,022,671.98 538,866.15 3.00 7,055.05 -5,139.51 5,061.48 6,022,649.75 538,898.16 3.00 7,094.02 -5,174.42 5,111.29 6,022,615.07 538,948.12 0.00 7,154.85 -5,209.89 5,161.88 6,022,579.83 538,998.87 0.00 7,216.64 -5,231.71 5,193.01 6,022,558.16 539,030.09 3.00 7,254.64 -5,268.94 5,246.16 6,022,521.18 539,083.41 3.00 7,319.54 -5,289.05 5,274.89 6,022,501.19 539,112.23 0.00 7,354.61 -5,346.41 5,356.79 6,022,444.22 539,194.39 0.00 7,454.60 -5,403.76 5,438.70 6,022,387.25 539,276.55 0.00 7,554.59 -5,461.11 5,520.61 6,022,330.27 539,358.71 0.00 7,654.58 -5,518.46 5,602.52 6,022,273.30 539,440.87 0.00 7,754.57 -5,575.82 5,684.43 6,022,216.32 539,523.03 0.00 7,854.57 -5,633.17 5,766.33 6,022,159.35 539,605.19 0.00 7,954.56 -5,690.52 5,848.24 6,022,102.38 539,687.35 0.00 8,054.55 -5,747.87 5,930.15 6,022,045.40 539,769.51 0.00 8,154.54 -5,805.23 6,012.06 6,021,988.43 539,851.67 0.00 8,254.53 -5,862.58 6,093.97 6,021,931.45 539,933.83 0.00 8,354.52 -5,919.93 6,175.88 6,021,874.48 540,015.99 0.00 8,454.51 -5,977.29 6,257.78 6,021,817.51 540,098.15 0.00 8,554.51 -5,985.85 6,270.01 6,021,809.00 540,110.41 0.00 8,569.44 -6,034.65 6,339.68 6,021,760.52 540,180.30 3.00 8,654.49 -6,050.62 6,362.48 6,021,744.65 540,203.17 3.00 8,682.33 -6,091.97 6,421.50 6,021,703.57 540,262.36 0.00 8,754.40 -6,149.30 6,503.31 6,021,646.63 540,344.42 0.00 8,854.29 -6,179.33 6,546.16 6,021,616.80 540,387.41 0.00 8,906.62 -6,206.64 6,585.14 6,021,589.67 540,426.50 3.00 8,954.21 -6,244.10 6,638.63 6,021,552.45 540,480.16 3.00 9,019.51 -6,263.99 6,667.04 6,021,532.69 540,508.66 0.00 9,054.20 -6,321.35 6,748.95 6,021,475.71 540,590.82 0.00 9,154.19 -6,378.70 6,830.86 6,021,418.74 540,672.98 0.00 9,254.18 -6,436.05 6,912.77 6,021,361.77 540,755.14 0.00 9,354.17 -6,493.41 6,994.67 6,021,304.79 540,837.30 0.00 9,454.17 -6,550.76 7,076.58 6,021,247.82 540,919.46 0.00 9,554.16 -6,608.11 7,158.49 6,021,190.84 541,001.62 0.00 9,654.15 -6,665.46 7,240.40 6,021,133.87 541,083.78 0.00 9,754.14 -6,722.82 7,322.31 6,021,076.89 541,165.94 0.00 9,854.13 -6,780.17 7,404.22 6,021,019.92 541,248.10 0.00 9,954.12 -6,837.52 7,486.12 6,020,962.95 541,330.26 0.00 10,054.11 10/42019 1:47:50PM Page 7 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -15i Wellbore: MPU M -15i Design: MPU M -15i wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -15i TVD Reference: M -15i D14 RKB @ 58.40usft MD Reference: M -15i D14 RKB @ 58.40usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (°) (°) (usft) usft (usft) 12,500.00 89.25 125.00 3,899.80 3,841.40 -6,894.87 12,515.31 89.25 125.00 3,900.00 3,841.60 -6,903.66 Start Dir 30/100' : 12515.31' MD, 3900'TVD 6,020,828.82 541,523.64 12,600.00 86.71 125.02 3,902.99 3,844.59 -6,952.21 12,635.51 85.64 125.02 3,905.35 3,846.95 -6,972.54 End Dir : 12635.51' MD, 3905.35' ND 6,020,735.31 541,658.37 12,700.00 85.64 125.02 3,910.25 3,851.85 -7,009.44 12,794.24 85.64 125.02 3,917.41 3,859.01 -7,063.37 Start Dir 3°/100' : 12794.24' MD, 3917.4l'TVD 541,822.58 12,800.00 85.82 125.02 3,917.84 3,859.44 -7,066.67 12,900.00 88.82 125.00 3,922.52 3,864.12 -7,123.98 12,916.10 89.30 125.00 3,922.78 3,864.38 -7,133.21 End Dir : 12916.1' MD, 3922.78' TVD 542,151.22 0.00 13,000.00 89.30 125.00 3,923.81 3,865.41 -7,181.33 13,100.00 89.30 125.00 3,925.03 3,866.63 -7,238.68 13,200.00 89.30 125.00 3,926.25 3,867.85 -7,296.04 13,300.00 89.30 125.00 3,927.47 3,869.07 -7,353.39 13,400.00 89.30 125.00 3,928.69 3,870.29 -7,410.74 13,500.00 89.30 125.00 3,929.92 3,871.52 -7,468.10 13,600.00 89.30 125.00 3,931.14 3,872.74 -7,525.45 13,700.00 89.30 125.00 3,932.36 3,873.96 -7,582.80 13,800.00 89.30 125.00 3,933.58 3,875.18 -7,640.16 13,900.00 89.30 125.00 3,934.80 3,876.40 -7,697.51 13,916.10 89.30 125.00 3,935.00 3,876.60 -7,706.74 Start Dir 31/100': 13916.1' MD, 3935'TVD 0.00 12,053.20 13,979.49 91.20 125.01 3,934.72 3,876.32 -7,743.11 End Dir : 13979.49' MD, 3934.72' TVD 0.00 12,253.15 14,000.00 91.20 125.01 3,934.29 3,875.89 -7,754.87 14,100.00 91.20 125.01 3,932.20 3,873.80 -7,812.24 14,200.00 91.20 125.01 3,930.10 3,871.70 -7,869.60 14,300.00 91.20 125.01 3,928.00 3,869.60 -7,926.96 14,315.89 91.20 125.01 3,927.67 3,869.27 -7,936.08 Start Dir 3°/100' : 14315.89' MD, 3927.67'TVD 14,316.32 91.20 125.00 3,927.66 3,869.26 -7,936.32 End Dir : 14316.32' MD, 3927.66' TVD 14,400.00 91.20 125.00 3,925.91 3,867.51 -7,984.31 14,500.00 91.20 125.00 3,923.81 3,865.41 -8,041.66 14,600.00 91.20 125.00 3,921.72 3,863.32 -8,099.00 14,700.00 91.20 125.00 3,919.62 3,861.22 -8,156.35 14,800.00 91.20 125.00 3,917.53 3,859.13 -8,213.69 14,900.00 91.20 125.00 3,915.44 3,857.04 -8,271.04 15,000.00 91.20 125.00 3,913.34 3,854.94 -8,328.38 15,016.32 91.20 125.00 3,913.00 3,854.60 -8,337.74 Start Dir 3°/100' : 15016.32' MD, 3913'TVD 10/4/2019 1:47:50PM Page 8 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,841.40 7,568.03 6,020,905.97 541,412.42 0.00 10,154.11 7,580.57 6,020,897.25 541,425.00 0.00 10,169.41 7,649.89 6,020,849.02 541,494.53 3.00 10,254.05 7,678.91 6,020,828.82 541,523.64 3.00 10,289.48 7,731.57 6,020,792.16 541,576.46 0.00 10,353.78 7,808.52 6,020,738.59 541,653.65 0.00 10,447.75 7,813.22 6,020,735.31 541,658.37 3.00 10,453.49 7,895.02 6,020,678.38 541,740.42 3.00 10,553.37 7,908.21 6,020,669.21 541,753.65 3.00 10,569.47 7,976.93 6,020,621.41 541,822.58 0.00 10,653.36 8,058.84 6,020,564.43 541,904.74 0.00 10,753.35 8,140.75 6,020,507.46 541,986.90 0.00 10,853.35 8,222.66 6,020,450.48 542,069.06 0.00 10,953.34 8,304.57 6,020,393.51 542,151.22 0.00 11,053.33 8,386.48 6,020,336.53 542,233.38 0.00 11,153.32 8,468.39 6,020,279.56 542,315.55 0.00 11,253.32 8,550.30 6,020,222.59 542,397.71 0.00 11,353.31 8,632.21 6,020,165.61 542,479.87 0.00 11,453.30 8,714.11 6,020,108.64 542,562.03 0.00 11,553.29 8,727.30 6,020,099.46 542,575.26 0.00 11,569.39 8,779.22 6,020,063.34 542,627.33 3.00 11,632.78 8,796.02 6,020,051.65 542,644.18 0.00 11,653.29 8,877.90 6,019,994.67 542,726.32 0.00 11,753.26 8,959.78 6,019,937.68 542,808.45 0.00 11,853.24 9,041.67 6,019,880.70 542,890.59 0.00 11,953.22 9,054.68 6,019,871.64 542,903.64 0.00 11,969.11 9,055.03 6,019,871.40 542,903.99 3.00 11,969.54 9,123.56 6,019,823.73 542,972.74 0.00 12,053.20 9,205.46 6,019,766.76 543,054.89 0.00 12,153.18 9,287.36 6,019,709.79 543,137.03 0.00 12,253.15 9,369.25 6,019,652.83 543,219.18 0.00 12,353.13 9,451.15 6,019,595.86 543,301.33 0.00 12,453.11 9,533.05 6,019,538.90 543,383.48 0.00 12,553.09 9,614.95 6,019,481.93 543,465.63 0.00 12,653.07 9,628.31 6,019,472.63 543,479.04 0.00 12,669.38 10/4/2019 1:47:50PM Page 8 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -15i Company: Hilcorp Alaska, LLC TVD Reference: M -15i D14 RKB @ 58.40usft Project: Milne Point MD Reference: M -15i D14 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -15i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -15i Design: MPU M-1 5i 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) 3,854.11 15,035.24 91.77 125.01 3,912.51 3,854.11 -8,348.59 9,643.80 6,019,461.85 543,494.58 3.00 12,688.30 End Dir : 15035.24' MD, 3912.51' TVD 15,050.00 91.77 125.01 3,912.05 3,853.65 -8,357.05 9,655.89 6,019,453.45 543,506.70 0.00 12,703.05 Fault 15,100.00 91.77 125.01 3,910.51 3,852.11 -8,385.72 9,696.82 6,019,424.96 543,547.76 0.00 12,753.03 15,200.00 91.77 125.01 3,907.43 3,849.03 -8,443.06 9,778.69 6,019,368.00 543,629.88 0.00 12,852.98 15,300.00 91.77 125.01 3,904.34 3,845.94 -8,500.41 9,860.56 6,019,311.04 543,712.00 0.00 12,952.93 15,400.00 91.77 125.01 3,901.26 3,842.86 -8,557.75 9,942.43 6,019,254.08 543,794.12 0.00 13,052.88 15,500.00 91.77 125.01 3,898.18 3,839.78 -8,615.09 10,024.30 6,019,197.11 543,876.24 0.00 13,152.83 15,600.00 91.77 125.01 3,895.09 3,836.69 -8,672.43 10,106.17 6,019,140.15 543,958.36 0.00 13,252.79 15,700.00 91.77 125.01 3,892.01 3,833.61 -8,729.77 10,188.03 6,019,083.19 544,040.48 0.00 13,352.74 15,800.00 91.77 125.01 3,888.92 3,830.52 -8,787.11 10,269.90 6,019,026.22 544,122.60 0.00 13,452.69 15,900.00 91.77 125.01 3,885.84 3,827.44 -8,844.45 10,351.77 6,018,969.26 544,204.72 0.00 13,552.64 16,000.00 91.77 125.01 3,882.76 3,824.36 -8,901.80 10,433.64 6,018,912.30 544,286.84 0.00 13,652.60 16,100.00 91.77 125.01 3,879.67 3,821.27 -8,959.14 10,515.51 6,018,855.34 544,368.96 0.00 13,752.55 16,192.54 91.77 125.01 3,876.82 3,818.42 -9,012.20 10,591.27 6,018,802.62 544,444.96 0.00 13,845.05 Start Dir 3°/100' : 16192.54' MD, 3876.82'TVD 16,200.00 91.54 125.01 3,876.60 3,818.20 -9,016.48 10,597.38 6,018,798.37 544,451.08 3.00 13,852.50 16,243.12 90.25 125.00 3,875.93 3,817.53 -9,041.21 10,632.69 6,018,773.80 544,486.51 3.00 13,895.62 End Dir : 16243.12' MD, 3875.93' TVD 16,300.00 90.25 125.00 3,875.68 3,817.28 -9,073.83 10,679.28 6,018,741.40 544,533.24 0.00 13,952.50 16,400.00 90.25 125.00 3,875.24 3,816.84 -9,131.19 10,761.20 6,018,684.42 544,615.41 0.00 14,052.49 16,500.00 90.25 125.00 3,874.81 3,816.41 -9,188.55 10,843.11 6,018,627.44 544,697.57 0.00 14,152.49 16,600.00 90.25 125.00 3,874.37 3,815.97 -9,245.91 10,925.03 6,018,570.46 544,779.74 0.00 14,252.49 16,700.00 90.25 125.00 3,873.93 3,815.53 -9,303.26 11,006.94 6,018,513.48 544,861.91 0.00 14,352.49 16,800.00 90.25 125.00 3,873.50 3,815.10 -9,360.62 11,088.86 6,018,456.50 544,944.07 0.00 14,452.49 16,900.00 90.25 125.00 3,873.06 3,814.66 -9,417.98 11,170.77 6,018,399.52 545,026.24 0.00 14,552.49 17,000.00 90.25 125.00 3,872.62 3,814.22 -9,475.33 11,252.69 6,018,342.55 545,108.41 0.00 14,652.49 17,100.00 90.25 125.00 3,872.19 3,813.79 -9,532.69 11,334.60 6,018,285.57 545,190.57 0.00 14,752.49 17,143.12 90.25 125.00 3,872.00 3,813.60 -9,557.42 11,369.92 6,018,261.00 545,226.00 0.00 14,795.61 Total Depth : 17143.12' MD, 3872' TVD 10/412019 1:47:50PM Page 9 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -15i Company: Hilcorp Alaska, LLC TVD Reference: M-1 5i D14 RKB @ 58.40usft Project: Milne Point Name MD Reference: x 12 1/4" M -15i D14 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Depth Depth Depth SS Well: Plan: MPU M -15i (usft) (usft) Survey Calculation Method: Minimum Curvature Wellbore: MPU M -15i 5,812.79 3,862.40 SB_OA 2,151.07 1,908.40 SV 1 2,095.52 1,872.40 Design: MPU M -15i wp05 4,049.25 3,138.40 LA3 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Shape (°) (I (usft) (usft) (usft) (usft) MPU M-15 wp05 CP3 0.00 0.00 3,866.00 -5,068.03 4,959.46 6,022,720.76 plan hits target center - Point MPU M-15 wp05 CP1 0.00 0.00 3,873.00 -3,347.13 2,502.17 6,024,430.30 plan hits tarqet center Point MPU M-15 wp05 Toe 0.00 0.00 3,872.00 -9,557.42 11,369.92 6,018,261.00 - plan hits tarqet center - Point MPU M-15 wp05 CP2 0.00 0.00 3,880.00 -4,150.22 3,648.90 6,023,632.51 plan hits tarqet center Point MPU M-15 wp05 CP6 0.00 0.00 3,935.00 -7,706.75 8,727.31 6,020,099.46 plan hits tarqet center Point MPU M-15 wp05 CP4 0.00 0.00 3,899.00 -5,985.85 6,270.01 6,021,809.00 - plan hits tarqet center - Point MPU M-15 wp05 CP5 0.00 0.00 3,900.00 -6,903.66 7,580.57 6,020,897.25 plan hits target center Point MPU M-15 wp05 Heel 0.00 0.00 3,864.00 -3,068.59 2,104.41 6,024,707.00 - plan hits target center - Circle (radius 30.00) MPU M-15 wp05 CP7 0.00 0.00 3,913.00 -8,337.74 9,628.31 6,019,472.63 plan hits target center Point Casing Points Measured Vertical Depth Depth (usft) (usft) Name 5,828.09 3,864.00 9 5/8" x 12 1/4" 17,143.12 3,872.00 6 5/8" x 8 1/2" Formations Measured Vertical Vertical Depth Depth Depth SS (usft) (usft) Name 1,372.94 1,331.40 SV5 4,923.80 3,663.40 SB—NA 5,812.79 3,862.40 SB_OA 2,151.07 1,908.40 SV 1 2,095.52 1,872.40 BPRF 4,049.25 3,138.40 LA3 Easting (usft) 538,795.83 536,330.98 545,226.00 537,481.24 542,575.26 540,110.41 541,425.00 535,932.00 543,479.04 Casing Hole Diameter Diameter 9-5/8 12-1/4 6-5/8 8-1/2 Dip Dip Direction Lithology (°) (°) 10/4/2019 1:47:50PM Page 10 COMPASS 5000.15 Build 91 Plan Annotations Measured Vertical Halliburton HALLIBURTON Depth Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -15i Company: Hilcorp Alaska, LLC TVD Reference: M-1 5i D14 RKB @ 58.40usft Project: Milne Point MD Reference: M -15i D14 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -15i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -15i 165.59 Start Dir 41/100': 1600' MD, 1522.59'TVD Design: MPU M -15i wp05 1,772.90 -529.37 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 400.00 400.00 0.00 0.00 Start Dir 3°/100' : 400' MD, 400 -TVD 1,600.00 1,522.59 -325.00 165.59 Start Dir 41/100': 1600' MD, 1522.59'TVD 1,941.96 1,772.90 -529.37 274.94 End Dir : 1941.96' MD, 1772.89' TVD 4,490.01 3,424.01 -2,226.21 1,216.82 Start Dir 4°/100' : 4490.01' MD, 3424.01'TVD 5,528.09 3,832.64 -2,897.50 1,859.98 End Dir : 5528.09' MD, 3832.64' TVD 5,828.09 3,864.00 -3,068.59 2,104.41 Start Dir 41/100': 5828.09' MD, 3864'TVD 5,973.21 3,871.84 -3,151.66 2,223.06 End Dir : 5973.21' MD, 3871.84' TVD 6,313.96 3,873.00 -3,347.13 2,502.17 Start Dir 31/100': 6313.96' MD, 3873'TVD 6,351.83 3,873.50 -3,368.86 2,533.18 End Dir : 6351.83' MD, 3873.5' TVD 6,522.94 3,877.48 -3,467.05 2,673.26 Start Dir 3°/100' : 6522.94' MD, 3877.48'TVD 6,564.00 3,877.99 -3,490.61 2,706.88 End Dir : 6564' MD, 3877.99' TVD 7,714.00 3,880.00 -4,150.22 3,648.90 Start Dir 31/100': 7714' MD, 3880'TVD 7,824.80 3,876.98 -4,213.76 3,739.61 End Dir : 7824.8' MD, 3876.98' TVD 8,003.57 3,866.93 -4,316.20 3,885.77 Start Dir 3'/100': 8003.57' MD, 3866.93'TVD 8,114.38 3,863.91 -4,379.74 3,976.48 End Dir : 8114.38' MD, 3863.91' TVD 9,314.38 3,866.00 -5,068.03 4,959.46 Start Dir 31/100': 9314.38' MD, 3866'TVD 9,439.04 3,870.28 -5,139.51 5,061.48 End Dir : 9439.04' MD, 3870.28' TVD 9,561.93 3,878.51 -5,209.89 5,161.88 Start Dir Y/100' : 9561.93' MD, 3878.51'TVD 9,664.93 3,882.64 -5,268.94 5,246.16 End Dir : 9664.93' MD, 3882.64' TVD 10,914.93 3,899.00 -5,985.85 6,270.01 Start Dir 31/100' : 10914.93' MD, 3899'TVD 11,027.86 3,897.14 -6,050.62 6,362.48 End Dir : 11027.86' MD, 3897.14'TVDO° RT TF 11,252.38 3,886.81 -6,179.33 6,546.16 Start Dir 31/100' : 11252.38' MD, 3886.81'TVD 11,365.31 3,884.95 -6,244.10 6,638.63 End Dir : 11365.31' MD, 3884.95' TVD 12,515.31 3,900.00 -6,903.66 7,580.57 Start Dir 31/100': 12515.31' MD, 3900'TVD 12,635.51 3,905.35 -6,972.54 7,678.91 End Dir : 12635.51' MD, 3905.35' TVD 12,794.24 3,917.41 -7,063.37 7,808.52 Start Dir 31/100': 12794.24' MD, 3917.417VD 12,916.10 3,922.78 -7,133.21 7,908.21 End Dir : 12916.1' MD, 3922.78' TVD 13,916.10 3,935.00 -7,706.74 8,727.30 Start Dir 3°/100' : 13916.1' MD, 3935'TVD 13,979.49 3,934.72 -7,743.11 8,779.22 End Dir : 13979.49' MD, 3934.72' TVD 14,315.89 3,927.67 -7,936.08 9,054.68 Start Dir 31/100' : 14315.89' MD, 3927.67'TVD 14,316.32 3,927.66 -7,936.32 9,055.03 End Dir : 14316.32' MD, 3927.66' TVD 15,016.32 3,913.00 -8,337.74 9,628.31 Start Dir 3°/100' : 15016.32' MD, 3913'TVD 15,035.24 3,912.51 -8,348.59 9,643.80 End Dir : 15035.24' MD, 3912.51' TVD 15,050.00 3,912.05 -8,357.05 9,655.89 Fault 16,192.54 3,876.82 -9,012.20 10,591.27 Start Dir 31/100': 16192.54' MD, 3876.82'TVD 16,243.12 3,875.93 -9,041.21 10,632.69 End Dir : 16243.12' MD, 3875.93' TVD 17,143.12 3,872.00 -9,557.42 11,369.92 Total Depth : 17143.12' MD, 3872' TVD 10/4/2019 1:47:50PM Page 11 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -15i MPU M -15i MPU M -15i wp05 Sperry Drilling Services Clearance Summary Anticollision Report 04 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M -15i - MPU M -15i -MPU M -15i wp05 Well Coordinates: 6,027,765.69 N, 533,813.87E (70" 29' 12.78" N, 149° 43' 25.06" W) Datum Height: M -15i D14 RKB @ 58.40usft Scan Range: 33.70 to 5,828.09 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: 91 Scan Type: - - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -15i - MPU M -15i 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 -15i - MPU M-151 - MPU M -15i wp05 Scan Range: 33.70 to 5,828.09 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-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-361-1 - MPL-36L1 MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 MPL-36 - MPL-36PB1 - MPL-36PB1 M Pt Moose Pad MPU M-11 - MPU M-11 - MPU M-11 MPU M-11 - MPU M-11 - MPU M-11 MPU M-11 - MPU M-11 - MPU M-11 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12PB1 - MPU M -12P81 MPU M-12- MPU M-12PB1 - MPU M-12PB1 MPU M-12- MPU M-12PB1 - MPU M-12PB1 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-13 - MPU M -13i - MPU M-13 MPU M-13 - MPU M -13i - MPU M-13 MPU M-13 - MPU M -13i - MPU M-13 MPU M-14 - MPU M-14 - MPU M-14 MPU M -14 -MPU M-14 - MPU M-14 5,709.75 725.44 5,709.75 639.80 13,082.32 8.471 Centre Distance Pass - 5,758.70 726.99 5,758.70 638.33 13,070.56 8.200 Ellipse Separation Pass - 5,828.09 734.45 5,628.09 640.47 13,053.48 7.815 Clearance Factor Pass - 5,828.09 1,068.22 5,828.09 923.47 13,313.42 7.380 Clearance Factor Pass - 5,828.09 1,068.22 5,828.09 916.43 13,313.42 7.037 Clearance Factor Pass - 5,828.09 1,068.22 5,828.09 911.22 13,313.42 6.804 Clearance Factor Pass - 5,828.09 1,068.22 5,828.09 923.47 13,313.42 7.380 Clearance Factor Pass - 439.95 238.45 439.95 234.98 441.21 68.621 Centre Distance Pass - 458.70 238.49 458.70 234.89 459.12 66.236 Ellipse Separation Pass - 883.70 292.80 883.70 286.46 815.09 46.231 Clearance Factor Pass - 339.90 171.88 339.90 168.42 340.76 49.707 Centre Distance Pass - 383.70 172.04 383.70 168.21 383.25 44.833 Ellipse Separation Pass - 783.70 229.62 783.70 222.45 743.33 31.986 Clearance Factor Pass - 339.90 171.88 339.90 168.42 340.76 49.707 Centre Distance Pass - 383.70 172.04 383.70 168.21 383.25 44.833 Ellipse Separation Pass - 783.70 229.62 783.70 222.45 743.33 31.986 Clearance Factor Pass - 339.90 171.88 339.90 168.42 340.76 49.707 Centre Distance Pass - 383.70 172.04 383.70 168.21 383.25 44.833 Ellipse Separation Pass - 783.70 229.62 783.70 222.45 743.33 31.986 Clearance Factor Pass - 805.78 176.83 805.78 170.79 790.84 29.250 Centre Distance Pass - 833.70 176.98 833.70 170.73 815.96 28.310 Ellipse Separation Pass - 4,483.70 1,498.92 4,483.70 1,421.09 4,581.22 19.260 Clearance Factor Pass - 33.70 89.94 33.70 89.03 34.07 98.633 Centre Distance Pass - 183.70 90.43 183.70 88.63 183.44 50.102 Ellipse Separation Pass - 04 October, 2019 - 13:49 Page 2 of 8 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-151 - MPU M-1 5i wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 Scan Range: 33.70 to 5,828.09 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 MPU M-14 - MPU M-14 - MPU M-14 5,828.09 806.69 5,828.09 686.80 5,883.93 6.729 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 33.70 89.78 33.70 88.87 34.18 98.458 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 1,533.70 98.89 1,533.70 83.78 1,553.34 6.545 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 1,908.70 114.70 1,908.70 92.68 1,922.20 5.208 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 33.70 210.02 33.70 209.11 34.42 230.322 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 108.70 210.21 108.70 208.89 108.37 160.037 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 2,133.70 382.42 2,133.70 354.76 2,118.64 13.830 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 33.70 210.02 33.70 209.11 34.42 230.322 Centre Distance Pass - MPU M-18 - MPU M -18P81 - MPU M-18PB1 108.70 210.21 108.70 208.89 108.37 160.037 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 2,133.70 382.42 2,133.70 354.76 2,118.64 13.829 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 33.70 210.02 33.70 209.11 34.42 230.322 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 108.70 210.21 108.70 208.89 108.37 160.037 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 2,133.70 382.42 2,133.70 354.76 2,118.64 13.830 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 321.22 127.12 321.22 124.49 321.95 48.378 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 358.70 127.25 358.70 124.36 358.58 44.055 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 4,933.70 430.12 4,933.70 340.94 7,734.90 4.823 Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 321.22 127.12 321.22 124.49 321.95 48.378 Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 358.70 127.25 358.70 124.36 358.58 44.055 Ellipse Separation Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 4,933.70 430.12 4,933.70 340.94 7,734.90 4.823 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 321.22 127.12 321.22 124.49 321.95 48.378 Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 358.70 127.25 358.70 124.36 358.58 44.055 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 4,933.70 430.12 4,933.70 340.94 7,734.90 4.823 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 33.70 194.66 33.70 193.75 33.95 213.482 Centre Distance Pass - MPU M-22 - MPU M-22 - MPU M-22 308.70 195.29 308.70 192.72 307.55 76.127 Ellipse Separation Pass - MPU M-22 - MPU M-22 - MPU M-22 683.70 245.23 683.70 240.13 642.21 48.087 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 33.70 194.66 33.70 193.75 33.95 213.482 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 308.70 195.29 308.70 192.72 307.55 76.127 Ellipse Separation Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 683.70 245.23 683.70 240.13 642.21 48.087 Clearance Factor Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,649.73 117.19 1,649.73 101.81 1,853.30 7.621 Centre Distance Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,658.70 117.32 1,658.70 101.45 1,860.86 7.393 Ellipse Separation Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,758.70 134.35 1,758.70 113.17 1,945.50 6.343 Clearance Factor Pass - 04 October, 2019 - 13:49 Page 3 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-1 5i - MPU M -1 5i wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 Scan Range: 33.70 to 5,828.09 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-12 P2 - M107 Phase 2 - M-12 p2 wp02 333.70 194.93 333.70 191.44 334.00 55.765 Centre Distance Pass - Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 358.70 195.02 358.70 191.35 357.34 53.153 Ellipse Separation Pass - Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 783.70 249.96 783.70 243.44 737.81 38.357 Clearance Factor Pass - Plan: MPU M -13i P2 - M-13 Phase 2 - M -13i P2 wp03 309.77 150.15 309.77 146.82 310.07 45.169 Centre Distance Pass - Plan: MPU M -13i P2 - M-13 Phase 2 - M -13i P2 wp03 358.70 150.34 358.70 146.67 357.51 41.033 Ellipse Separation Pass - Plan: MPU M -13i P2 - M-13 Phase 2 - MAN P2 wp03 4,583.70 1,498.75 4,583.70 1,416.23 4,436.25 18.160 Clearance Factor Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 261.28 120.14 261.28 117.17 261.58 40.364 Centre Distance Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 608.70 121.58 608.70 116.22 600.00 22.679 Ellipse Separation Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 5,828.09 809.42 5,828.09 672.91 5,647.74 5.929 Clearance Factor Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 722.57 28.82 722.57 22.65 720.34 4.667 Centre Distance Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M-1 5i P2 wp02 758.70 29.01 758.70 22.58 755.86 4.508 Ellipse Separation Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M-1 5i P2 wp02 5,258.70 114.62 5,258.70 70.54 5,134.37 2.600 Clearance Factor Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 960.27 58.16 960.27 49.92 967.91 7.054 Centre Distance Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 1,033.70 58.48 1,033.70 49.48 1,041.38 6.498 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 1,258.70 65.70 1,258.70 54.22 1,263.65 5.726 Clearance Factor Pass - Plan: MPU M -17i P2 - M112 Phase 2 - M -17i P2 wp02 684.12 145.71 684.12 139.69 693.55 24.231 Centre Distance Pass - Plan: MPU M -17i P2 - M112 Phase 2 - MAT P2 wp02 783.70 146.18 783.70 139.34 794.42 21.385 Ellipse Separation Pass - Plan: MPU M -17i P2 - M112 Phase 2 - MAT P2 wp02 5,828.09 1,315.67 5,828.09 1,196.06 5,471.74 10.999 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 462.89 238.95 462.89 235.01 462.85 60.599 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 508.70 239.12 508.70 234.86 509.38 56.091 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 4,858.70 1,493.91 4,858.70 1,423.40 4,545.07 21.186 Clearance Factor Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl 645.48 116.33 645.48 111.07 648.06 22.108 Centre Distance Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl 733.70 116.72 733.70 110.76 737.01 19.604 Ellipse Separation Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl 1,133.70 143.14 1,133.70 133.35 1,123.49 14.621 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 383.70 138.10 383.70 134.25 384.00 35.832 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 433.70 138.28 433.70 134.07 434.00 32.863 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 4,808.70 383.35 4,808.70 288.08 6,995.48 4.024 Clearance Factor Pass - Plan: MPU M-21 i - MPU M -21i - MPU M-21 i wp03 383.70 137.86 383.70 134.44 384.00 40.289 Centre Distance Pass - Plan: MPU M-21 i - MPU M -21i - MPU M-21 i wp03 408.70 137.88 408.70 134.28 409.00 38.302 Ellipse Separation Pass - Plan: MPU M -21i - MPU M -21i - MPU M-21 i wp03 4,683.70 1,040.89 4,683.70 957.45 6,913.60 12.474 Clearance Factor Pass - 04 October. 2019 - 13:49 Page 4 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -15i - MPU M -15i wp05 383.70 243.89 383.70 240.68 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 76.002 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M-231 - M-231 wp03 408.70 243.91 Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M-151 - MPU M -15i wp05 240.52 409.00 72.016 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 Scan Range: 33.70 to 5,828.09 usft. Measured Depth. 290.18 783.70 284.27 746.23 49.156 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Plan: MPU M-27 - M-27 - M-27 wp02 618.46 237.90 618.46 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 633.70 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 3,558.70 1,437.93 Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 383.70 153.41 383.70 149.55 384.00 39.804 Centre Distance Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-211 P2 wp02 408.70 153.43 408.70 149.40 409.00 38.052 Ellipse Separation Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M -21i P2 wp02 4,683.70 1,274.15 4,683.70 1,189.11 6,528.00 14.983 Clearance Factor Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 335.68 218.67 335.68 215.16 335.98 62.301 Centre Distance Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 358.70 218.68 358.70 215.01 358.23 59.553 Ellipse Separation Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 683.70 259.79 683.70 253.94 650.00 44.384 Clearance Factor Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 383.70 243.89 383.70 240.68 384.00 76.002 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M-231 - M-231 wp03 408.70 243.91 408.70 240.52 409.00 72.016 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 783.70 290.18 783.70 284.27 746.23 49.156 Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02 618.46 237.90 618.46 232.96 586.91 48.144 Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02 633.70 237.94 633.70 232.90 600.00 47.227 Ellipse Separation Pass - Plan: MPU M-27 - M-27 - M-27 wp02 3,558.70 1,492.89 3,558.70 1,437.93 2,921.82 27.164 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 383.70 124.02 383.70 120.60 376.90 36.241 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 408.70 124.04 408.70 120.44 401.90 34.453 Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 783.70 159.15 783.70 152.90 774.32 25.476 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! 383.70 172.58 383.70 169.16 384.00 50.413 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! 408.70 172.60 408.70 169.00 409.00 47.928 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 858.70 225.60 858.70 218.83 854.60 33.309 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 5,733.70 158.50 5,733.70 9.76 5,807.25 1.066 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 5,759.61 156.70 5,759.61 12.50 5,817.30 1.087 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 261.28 127.86 261.28 125.32 261.58 50.257 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 283.70 127.86 283.70 125.16 283.75 47.287 Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 558.70 153.16 558.70 148.56 538.94 33.253 Clearance Factor Pass - Rig: MPU MAT - MPU M -17i - MPU M -17i 33.70 180.02 33.70 179.11 34.00 197.419 Centre Distance Pass - Rig: MPU M -1 7i - MPU M -1 7i - MPU M-1 7i 733.70 182.00 733.70 176.27 747.09 31.789 Ellipse Separation Pass - Rig: MPU M -17i - MPU MAT - MPU MAT 2,158.70 292.63 2,158.70 264.37 2,151.00 10.357 Clearance Factor Pass - Rig: MPU M -17i - MPU M-1 7i - MPU M-17 wp07 408.70 180.02 408.70 176.19 409.27 47.032 Centre Distance Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 958.70 182.39 958.70 174.12 980.90 22.051 Ellipse Separation Pass - Rig: MPU M -17i - MPU M-171 - MPU M-17 wp07 5,828.09 1,299.34 5,828.09 1,178.43 5,545.88 10.746 Clearance Factor Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 383.70 29.87 383.70 26.45 346.30 8.731 Centre Distance Pass - 04 October, 2019 - 13.49 Page 5 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -15i - MPU M -15i wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 Scan Range: 33.70 to 5,828.09 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 Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 433.70 30.01 433.70 26.24 396.30 7.952 Ellipse Separation Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 558.70 33.46 558.70 28.82 521.12 7.201 Clearance Factor Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 723.12 53.60 723.12 47.78 684.18 9.219 Centre Distance Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 733.70 53.63 733.70 47.74 694.60 9.102 Ellipse Separation Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 808.70 56.02 808.70 49.58 768.19 8.695 Clearance Factor Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 383.70 152.48 383.70 149.06 346.30 44.565 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 433.70 152.61 433.70 148.84 396.30 40.427 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 933.70 197.04 933.70 189.69 889.38 26.816 Clearance Factor Pass - Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 383.70 218.88 383.70 215.46 346.30 63.973 Centre Distance Pass - Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 483.70 219.12 483.70 215.00 446.27 53.121 Ellipse Separation Pass - Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 1,058.70 258.70 1,058.70 250.39 1,000.00 31.139 Clearance Factor Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 1,008.06 186.95 1,008.06 178.96 960.44 23.387 Centre Distance Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 1,033.70 187.13 1,033.70 178.92 984.74 22.803 Ellipse Separation Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 1,058.70 187.86 1,058.70 179.48 1,000.00 22.418 Clearance Factor Pass - Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 33.70 5,828.09 MPU M -15i wp05 2 MWD+IFR2+MS+Sag 5,828.09 17,143.12 MPU M -15i wp05 2_MWD+IFR2+MS+Sag 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. 04 October, 2019 - 13:49 Page 6 of 8 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DECAILSTIan:MPUM-15i NAD1927(NADCONCONUS) Alaska Zone04 Coordinate (WE) Reference: Well Plan: MPU M -15i, True NOr" Veruwl (ND) Reference: A415i D14 RKB (j 58.40ustt Grund Level: 24.70 ----------------- Site: M Pt Moose Pad Sperry Orillinc� Well: Plan: MPU M -15i Measured Dap"Rafe, c W15i D14 RU@Sa, 0usft +N/ -S +E/ -W Northing E�ting L fithwe Longitude Wellbore MPU M -15i Calwla on MC"od: Minimum Curvature 0.00 6.0025k,51 6027765.69 533813.87 70° 29' 12.784 N 149° 43' Plan: MPU M-151 wp05 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria Date: 2016-06-22Too:00:00 Validated: Yes Version: ' 33.70 To 17143.12 Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETATLS 33.70 5828.09 MPU M -15i wp05 (MPU M -15i) 2_MWD+IFR2+MS+Sag TVD TVDSS MD Size Name SH (1 of 2) 5828.09 17143.12 MPU M -15i wp05(MPU M -15i) 2_MWD+IFR2+MS+Sag 3864.00 3805.60 5828.09 9-5/8 9 5/8" x 1'_ t/4" 3872.00 3813.60 17143.12 6-5/8 6 5/8" x 8 l/2" Slot 42 - l cehotd — _ M -/3i M p03 I X150.00 l ---t-- I + i 7 VA0 p MPU AT 5720.00 S M -14-P2 wp02 I MP M-14 CMPU -16 60.00 (j Slot 3 - Placeho17.111, I M-1 'P2 wp02 .0�.. 30.00 � v i l � I 11 -01 0.00 I 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 Measured Depth (600 usft/in) 4.00 o 3.00 LL T ° Collision Risk Procedures Req. @ 2.00 a Collision Avoidance Req - Cl) No -Go Zone - Stop Drilling) l: NOERRORS 0.00 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 Measured Depth (600 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -15i MPU M -15i MPU M -15i wp05 Sperry Drilling Services Clearance Summary Anticollision Report 04 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 Well Coordinates: 6,027,765.69 N, 533,813.87 E (70° 29' 12.78" N, 149° 43' 25.06" W) Datum Height: M -15i D14 RKB @ 58.40usft Scan Range: 5,828.09 to 17,143.12 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: 5000.1-5 Build: 91 Scan Type: fined selection & filtering criteria - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-1 5i - MPU M-1 5i wp05 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M-151 - MPU M-151 wp05 Scan Range: 5,828.09 to 17,143.12 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 -24 - MPJ -24A- MPJ -24A MPJ -24 - MPJ -241-1 - MPJ -24L1 MPJ -24 - MPJ -241-1 PB1 - MP,L24LI PBI MPJ -24 - MPJ-24L1PB2 - MPJ -241-1 PB2 MPJ -24 - MPU J-24 - MPJ -24 M Pt L Pad MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35A - MPL-35A MPL-35 - MPL-35A - MPL-35A MPL-35 - MPL-35APB1 - MPL-35APB1 MPL-35 - MPL-35APB1 - MPL-35APB1 MPL-35 - MPL-35APB2 - MPL-35APB2 MPL-35 - MPL-35APB2 - MPL-35APB2 MPL-35 - MPL-35APB3 - MPL-35APB3 MPL-35 - MPL-35APB3 - MPL-35APB3 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-361-1 - MPL-36L1 MPL-36 - MPL-36L1 - MPL-361-1 MPL-36 - MPL-361-1 - MPL-361-1 MPL-36 - MPL-36L1 PB1 - MPL-361-1 PB1 MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 MPL-36 - MPL-361-1 PB1 - MPL-36L1 PBI 17,143.12 714.34 17,143.12 136.32 8,967.30 1.236 Clearance Factor Pass - 17,143.12 674.83 17,143.12 108.45 8,849.34 1.191 Clearance Factor Pass - 17,143.12 674.83 17,143.12 107.71 8,849.34 1.190 Clearance Factor Pass - 17,143.12 674.83 17,143.12 108.35 8,849.34 1.191 Clearance Factor Pass - 17,143.12 663.45 17,143.12 52.23 8,902.19 1.085 Clearance Factor Pass - 5,828.09 734.45 5,828.09 640.47 13,053.48 7.815 Ellipse Separation Pass - 6,078.09 823.37 6,078.09 710.34 12,984.88 7.284 Clearance Factor Pass - 9,303.66 799.40 9,303.66 703.33 12,555.03 8.321 Ellipse Separation Pass - 9,678.09 868.35 9,678.09 758.69 12,557.35 7.919 Clearance Factor Pass - 9,303.66 799.40 9,303.66 703.33 12,555.83 8.321 Ellipse Separation Pass - 9,678.09 868.35 9,678.09 758.64 12,558.15 7.915 Clearance Factor Pass - 9,303.66 799.40 9,303.66 703.22 12,555.83 8.312 Ellipse Separation Pass - 9,678.09 868.35 9,678.09 758.53 12,558.15 7.907 Clearance Factor Pass - 9,303.66 799.40 9,303.66 703.22 12,555.83 8.312 Ellipse Separation Pass - 9,678.09 868.35 9,678.09 758.53 12,558.15 7.907 Clearance Factor Pass - 9,303.66 799.40 9,303.66 703.22 12,555.83 8.312 Ellipse Separation Pass - 9,678.09 868.35 9,678.09 758.53 12,558.15 7.907 Clearance Factor Pass - 6,748.07 576.39 6,748.07 500.25 13,090.94 7.570 Centre Distance Pass - 6,803.09 578.80 6,803.09 499.44 13,075.25 7.293 Ellipse Separation Pass - 7,178.09 710.64 7,178.09 586.95 12,983.68 5.745 Clearance Factor Pass - 6,748.07 576.39 6,748.07 500.23 13,090.94 7.568 Centre Distance Pass - 6,803.09 578.80 6,803.09 499.12 13,075.25 7.264 Ellipse Separation Pass - 7,178.09 710.64 7,178.09 582.61 12,983.68 5.550 Clearance Factor Pass - 6,748.07 576.39 6,748.07 500.21 13,090.94 7.567 Centre Distance Pass - 6,803.09 578.80 6,803.09 498.88 13,075.25 7.242 Ellipse Separation Pass - 7,203.09 725.12 7,203.09 591.13 12,977.70 5.412 Clearance Factor Pass - 04 October, 2019 - 13:50 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-1 5i - MPU M-1 5i wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 225.37 10,603.09 Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 198.32 10,653.09 Scan Range: 5,828.09 to 17,143.12 usft. Measured Depth. 10,759.25 171.67 10,759.25 103.94 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 75.50 Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) MPL-36 - MPL-36PB1 - MPL-36PB1 6,748.07 576.39 6,748.07 500.25 MPL-36 - MPL-36PB1 - MPL-36PB1 6,803.09 578.80 6,803.09 499.44 MPL-36 - MPL-36PB1 - MPL-36PB1 7,178.09 710.64 7,178.09 586.95 MPU L-51 - MPU L-51 - MPU L-51 12,278.09 214.81 12,278.09 59.27 MPU L-51 - MPU L-51 - MPU L-51 12,303.09 201.18 12,303.09 57.13 MPU L-51 - MPU L-51 - MPU L-51 12,425.87 166.84 12,425.87 92.89 MPU L-52 - MPU L-52 - MPU L-52 MPU L-52 - MPU L-52 - MPU L-52 MPU L-52 - MPU L-52 - MPU L-52 MPU L-53 - MPU L-53 - MPU L-53 MPU L-53 - MPU L-53 - MPU L-53 MPU L-53 - MPU L-53 - MPU L-53 MPU L-54 - MPU L-54 - MPU L-54 MPU L-54 - MPU L-54 - MPU L-54 MPU L-54 - MPU L-54 - MPU L-54 MPU L-56 - MPU L-56 - MPU L-56 MPU L-56 - MPU L-56 - MPU L-56 MPU L-56 - MPU L-56 - MPU L-56 MPU L-57 - MPU L-57 - MPU L-57 MPU L-57 - MPU L-57 - MPU L-57 MPU L-57 - MPU L-57 - MPU L-57 MPU L-57 - MPU L-57PB1 - MPU L-57PB1 MPU L-57 - MPU L-57PB1 - MPU L-57PB1 MPU L-57 - MPU L-57PB1 - MPU L-57PB1 M Pt Moose Pad MPU M-14 - MPU M-14 - MPU M-14 MPU M-14 - MPU M-14 - MPU M-14 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-20 - MPU M-20 - MPU M-20 10,603.09 225.37 10,603.09 82.74 10,653.09 198.32 10,653.09 77.44 10,759.25 171.67 10,759.25 103.94 9,210.01 151.84 9,210.01 75.50 9,278.09 164.81 9,278.09 70.40 9,328.09 188.21 9,328.09 74.78 13,153.09 356.71 13,153.09 106.52 13,178.09 350.93 13,178.09 105.07 13,247.49 344.00 13,247.49 116.15 9,903.09 217.52 9,903.09 83.78 9,928.09 203.55 9,928.09 80.26 10,051.16 168.13 10,051.16 104.08 11,478.09 210.80 11,478.09 66.89 11,503.09 196.74 11,503.09 63.90 11, 623.71 161.93 11, 623.71 94.15 11,403.09 371.97 11,403.09 166.22 11,428.09 366.27 11,428.09 165.25 11,499.87 359.16 11,499.87 175.14 @Measured Clearance Summary Based on Depth Factor Minimum usft 13,090.94 13,075.25 12,983.68 13,367.02 13,376.91 13,424.71 13,541.29 13,559.03 13,594.80 13,945.71 13,968.22 13,984.94 13,500.00 13,500.00 13,500.00 13,660.70 13,670.08 13,715.18 13,470.45 13,479.46 13,524.32 13,186.00 13,186.00 13,186.00 7.570 Centre Distance 7.293 Ellipse Separation 5.745 Clearance Factor 1.381 Clearance Factor 1.397 Ellipse Separation 2.256 Centre Distance 1.580 Clearance Factor 1.641 Ellipse Separation 2.535 Centre Distance 1.989 Centre Distance 1.746 Ellipse Separation 1.659 Clearance Factor 1.426 Clearance Factor 1.427 Ellipse Separation 1.510 Centre Distance 1.626 Clearance Factor 1.651 Ellipse Separation 2.625 Centre Distance 1.465 Clearance Factor 1.481 Ellipse Separation 2.389 Centre Distance 1.808 Clearance Factor 1.822 Ellipse Separation 1.952 Centre Distance Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass- Pass- Pass - Pass - Pass - Pass - Pass- Pass- Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 8,418.03 800.25 8,418.03 599.22 8,499.89 3.981 Centre Distance Pass - 17,053.09 821.80 17,053.09 224.65 17,135.85 1.376 Clearance Factor Pass - 5,828.09 777.70 5,828.09 645.10 5,687.60 5.865 Centre Distance Pass - 16,253.09 811.73 16,253.09 277.94 16,306.00 1.521 Clearance Factor Pass - 5,828.09 1,061.19 5,828.09 949.59 8,256.16 9.509 Clearance Factor Pass - 04 October, 2019 - 13:50 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-1 5i - MPU M-1 5i wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -15i - MPU M -15i - MPU M -15i wp05 Scan Range: 5,828.09 to 17,143.12 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) MPU M-20 - MPU M-20PB1 - MPU M-20PB1 5,828.09 1,061.19 5,828.09 949.60 MPU M-20 - MPU M-20PB2 - MPU M-20PB2 5,828.09 1,061.19 5,828.09 949.59 Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 5,828.09 809.42 5,828.09 672.91 Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 14,653.09 840.66 14,653.09 327.94 Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 5,828.09 806.61 5,828.09 676.85 Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 13,178.09 831.15 13,178.09 391.93 Plan: MPU M -17i P2 - M112 Phase 2 - M -17i P2 wp02 5,828.09 1,315.67 5,828.09 1,196.06 Plan: MPU M -17i P2 - M112 Phase 2 - M -17i P2 wp02 6,453.09 1,495.30 6,453.09 1,347.73 Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 5,828.09 1,128.69 5,828.09 1,008.38 Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 5,828.09 169.00 5,828.09 49.73 Rig: MPU M -17i - MPU M -17i - MPU M -17i 5,828.09 1,307.96 5,828.09 1,185.94 Rig: MPU M -17i - MPU M -17i - MPU M -17i 6,228.09 1,451.72 6,228.09 1,314.31 Rig: MPU M-171 - MPU M -17i - MPU M-17 wp07 5,828.09 1,299.34 5,828.09 1,178.43 Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 6,178.09 1,420.03 6,178.09 1,286.01 Milne Point Exploration @Measured Clearance Summary Based on Depth Factor Minimum usft 8,256.16 8,256.16 5,647.74 14,470.04 5,661.21 13,109.59 5,471.74 5,942.90 7,581.25 5,842.74 5,534.41 5,855.96 5,545.88 5,809.32 9.510 Clearance Factor 9.509 Clearance Factor 5.929 Centre Distance 1.640 Clearance Factor 6.216 Centre Distance 1.892 Clearance Factor 10.999 Ellipse Separation 10.133 Clearance Factor 9.382 Clearance Factor 1.417 Clearance Factor 10.719 Ellipse Separation 10.565 Clearance Factor Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - Pass- Pass- Pass - Pass - Pass - Pass - Pass - Pass - 10.746 Ellipse Separation Pass - 10.596 Clearance Factor Pass - MPU-Liviano-Ol-Liviano-01A-Liviano-01A 9,518.49 1,101.64 9,518.49 968.84 3,863.00 8.296 Centre Distance Pass - MPU-Liviano-Ol-Liviano-01A-Liviano-01A 9,553.09 1,102.17 9,553.09 968.42 3,858.46 8.241 Ellipse Separation Pass - MPU-Liviano-0l-Liviano-01A-Liviano-01A 9,653.09 1,109.51 9,653.09 973.68 3,843.08 8.168 Clearance Factor Pass - From TO (usft) (usft) 33.70 5,828.09 MPU M -15i wp05 5,828.09 17,143.12 MPU M -15i wp05 Survey/Plan Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 04 October, 2019 - 13:50 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-1 5i - MPU M-1 5i 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 04 October, 2019 - 13:50 Page 5 of 7 COMPASS HALLIBLIRTON Project: Milne Point REFERENCE INFORMATION WELL DETAOSTIao: MPUM-15i NAD 1927(NADCONCONUS) Aloka Zone 04 Ca Me (N/E) Reference: Wall Plan: MPU M-15i, TNo h V.I Var6caReference: M-15i D14 RKB 0540usft G.ouad L-1: 24.70 Site: M Pt Moose Pad Sperry 0,1111.9 Well: Plan: MPU M-15i Measured D,pth DapM Reference: M15 D14 RK13058.40usft +N/-$ +E/-W Nurthiug F.nting Irtittude Iuny�'aulc Wellbore: MPU M-15i Cake alion Melho :Minimum Curvature 0.00 0.00 6027765.69 533813.87 70° 29' 12.784N 149° 43' 25.061 Plan: MPU M-15i wp05 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering cntena Date: 2016-06-22T00:00:00 Validated: Yes Version: m 33-70 To 17143.12 Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS PH (2 of 2) 33.70 5828.09 MPUM-15i wp05(MPUM-i Si) 2_MWD+IFR2+MS+Sag 5828.09 17143.12 MPU M-15i wp05 (MPU M- 5i 2_MWD+IFR2+MS+Sag TVD TVDSS MD Size Name 3864.00 3805.60 5828.09 9-5/8 95/8"x 121/4" 3872.00 3813.60 17143.12 6-5/8 6 5/8" z 8 1/2" 150.00 — 4 i PU L-53 o 6120.00— I , i � c o .2 I I i 0.00 90.00— U) (n 4) 60.00- 0.00 0 0 2 30.00 _ i I N ' U 0.00 6000 6600 7200 76100 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 Measured Depth (1200 usft/in) 4.00 — � I O I 0 3.00 00 LL — - c o 2.00 Collision Risk Procedures Req. rn Collision Avoidance Req. t I 1.00— No-Go Zone -Stop Drilling NOERRORS 0.00 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 Measured Depth (1200 usft/in) Transform Points {' X Source coordinate system State plane 1927 -Alaska Zone 4 LmfaDatum: NAD 1927 - North America Datum of 19:27 (Mean) Target coordinate system "",,� Albers Equal Area (-154) A ! be(e5 C- ISO Datum: NAD 1927 - North America Datum of 1927 (Mean) `Type +slues into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctr+C to !copy and Ctd+V'to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. <Back :i Finish 1 Cancel I Help TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 2, Development ervice Exploratory Stratigraphic Test _ Non -Conventional FIELD: M t 11/1 Po POOL: Ir'Gl P.i cV /Gt 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 LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number 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 both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company 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 (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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 �'X)Per within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 PTD#: 2191410 Company Hilcorp Alaska LLC Initial Class/Type Well Name: MILNE PT UNIT M-15 Program SER Well bore seg ❑ SER/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit_ fee attached - - - - - - - - - ---- - - - - ---- - -- -- - - - - - - - - _ _ _ _ - - - _ _ NA - 2 Lease number appropriate- - - - - - - - - - - - - - - - - - - - Yes 3 Unique well-nameandnumber ---------------- Yes----------------------- ------------------------------------ ----- 4 Well located in_ a_definedpool-------- Yes - - - - 5 Well located proper distance from drilling unit -boundary - - - - - - - - - Yes 6 Well located proper distance from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ - - - - - - - - - - - - - - - - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - 7 Sufficient acreage available in -drilling unit - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - - - - 8 If deviated, is -wellbore plat -included - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - 9 Operator only affected party - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - 10 Operator has_appropriate_bondinforce ----------------- -- ---- - - - - - -- Yes ------------------- ----------------- - ------ 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 DLB 10/21/2019 - - - - - - - - - - - - - - - - _ _ - _ _ _ - - - - - - - - - - - - - - - - - - - - - 14 Well located within area and -strata authorized by Injection Order # (put_10# in -comments) -(For- Yes - _ _ _ _ _ - AIO.10-B - - - - - - - - - - - - - - - - - 15 All wells- within 1/4_mile area of review identified (:For service well only)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - - - - - - - _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ - - - - - - - - - - 16 Pre -produced injector. duration of pre production less than 3 months -(For service well only) - _ No_ - - - - - - M-15 will not be_pre-produced- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 Nonconven. gas_conforms to AS31.05.030(;j.1_.A),(j.2.A-D) - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ - _ _ - - - - - - - - - - - - - - - - - _ - 18 Conductor string -provided - - - - - - - --_ _ _ - Yes _ - - - - - - 20 inch_conductor set at_113ft - - - - - - - - Engineering 19 Surface_casing_ protects allknown_USDWs-------------- ------------ NA------------------------------------------------------ 20 CMT_vol- adequate _to circulate on conductor & surf_csg - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 9 5/8" surface/prod-casing will be fully -cemented in 2 -stages. _ES_ at 2500_ft. - - - - - 21 CMT-vol-adequate_to tie-in long string to surf_ csg----------------------------- es _ _ _ - _ _ _ - - - - - _ - - - - - - - - - - - - - - - - - - - - - - _ _ _ - _ _ _ _ _ - _ - _ - _ - - - - - - - - - - 22 CMT_will cover all known -productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 9 5/8" landed in the SB... lateral will have swell packers and ICD- - - - - - . 23 Casing designs adequate for CJ, B &_ permafrost - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - BTC provided. - - - - - - - - - - - - - - - . - 24 Adequatetankage_orreservepit-------------------- ---- -- ----------- Yes --___-_ Doyon 14has-steel _tanks .__________-_-__--__-_-_ ---------------- 25 If -a - re -drill, has_a 107-403 for abandonment been approved - _ - _ _ _ _ _ _ _ _ NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 26 Adequate wellbore separation proposed - - - - - - - - - - - - - - - - - - Yes - - - - - - - No issues - - - - - - - - - - - - - - - 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 formation_ press= 1599_psi_(8.5 ppg EMW) will drill with 8.8-9.5 ppg-mud_ GLS 11/1/2019 29 BOPEs,_do they meet regulation - - - - - - - - - - - - - - Yes _ _ _ _ - _ _ 13 5/8"5000 psi WP_BOPE_ - - - - - - - - - - 30 BOPE_press rating appropriate; test to_(put prig in comments)- - - - - - - - Yes - - - - - - - MASP= 1314psi will test BOPE to 3000 psi - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 31 Choke -manifold complies MAPI-RP-53 (May 84)- - - - - - - - - - - - - - - - - - - - - - Yes- - - - - - - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - _ _ 33 Js presence of H2S gas probable_ - - - _ N No _ _ _ _ --------------------- - - - - - - - - - - - - - - - - - - - - - - - - - - 34 Mechanical -condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - - Yes - - - - - - - AOR is -completed . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - _ - - - - - 35 Permit_can be issued w/o hydrogen_ sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms._ Geology 36 Data -presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ - - - _ - - - ------------------------------------------------------- Appr Date 37 Seismicanalysisofshallow gas -zones ----------------------------------- A- ----------------------------------------------- DLB 10/21/2019 38 Seabed condition survey (if off -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - _ _ - _ - - - - - - - - - - - - - - - - - - - - - _ - _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - 39 Contact name/phone for weekly -progress reports [exploratory only] - - - - - - - - - - - - - - - - - NA- - - - - - - - _ - -- - - - - - - - - - - _ - - - _ _ - _ _ _ _ _ _ _ - - Geologic Engineering Public Schrader Bluff OA sand injector. Will use ICD to regulate injetion profile along the lateral. GIs Date: Date Date Commissioner: Commissioner: Co fission j � I� 111'q