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Home My WebLink About220-044DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23676-00-00Well Name/No. MILNE PT UNIT M-45Completion Status1-OILCompletion Date6/1/2020Permit to Drill2200440Operator Hilcorp Alaska, LLCMD12192TVD3533Current Status1-OIL9/22/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP DGR AGR ABG ADR EWR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF7/3/20205396 12154 Electronic Data Set, Filename: MPU M-45 ADR Quadrants All Curves.las33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final MD.cgm33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final TVD.cgm33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_Definitive Survey Report.pdf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_Definitive Surveys.xlsx33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_DSR.txt33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_GIS.txt33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_Plan.pdf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45_VSec.pdf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final MD.emf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final TVD.emf33471EDDigital DataDF7/3/2020 Electronic File: MPU_M-45_Geosteering.dlis33471EDDigital DataDF7/3/2020 Electronic File: MPU_M-45_Geosteering.ver33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final MD.pdf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final TVD.pdf33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final MD.tif33471EDDigital DataDF7/3/2020 Electronic File: MPU M-45 LWD Final TVD.tif33471EDDigital Data0 0 2200440 MILNE PT UNIT M-45 LOG HEADERS33471LogLog Header ScansDF112 12192 Electronic Data Set, Filename: MPU M-45 LWD Final.las33471EDDigital DataTuesday, September 22, 2020AOGCCPage 1 of 2MPU M-45 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23676-00-00Well Name/No. MILNE PT UNIT M-45Completion Status1-OILCompletion Date6/1/2020Permit to Drill2200440Operator Hilcorp Alaska, LLCMD12192TVD3533Current Status1-OIL9/22/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:6/1/2020Release Date:5/14/2020Tuesday, September 22, 2020AOGCCPage 2 of 2M. Guhl9/22/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/02/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-45 (220-044) Halliburton LWD FINAL 18 MAY 2020 MPU M-45 Received by the AOGCC 07/20/2020 PTD: 2200440 E-Set: 33571 Abby Bell 07/20/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: 1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB 17. Field / Pool(s): GL: 24.9' BF:25.1' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" X-52 114' 7" L-80 3,772' 4-1/2" L-80 3,533' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, Tieback Assy.Tieback TUBING RECORD Cementless Screen Liner L-80 Surface 5,407' SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD 9-5/8" 40# Surface Stg 2 L - 315 bbls /T - 56 bbls 3,771' Surface 3,777' 12-1/4" 42" 13.5# Stg 1 L - 153 bbls /T - 82 bbls 8-1/2" 18 cubic yards 5,245' 12,192' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 6/1/2020 5,037' FSL, 171' FEL, Sec 14, T13N, R9E, UM, AK 574' FSL, 1320' FWL, Sec 24, T13N, R9E, UM, AK 220-044 Milne Point Field / Schrader Bluff Oil Pool 59' 12,181' MD / 3,534' TVD May 27, 2020 May 18, 2020 ADL388235, ADL025514$'/ AMOUNT PULLED 50-029-23676-00-00 MPU M-45 533994 6027890 993' FNL, 1751' FWL, Sec 13, T13N, R9E, UM, AK CEMENTING RECORD 6027148 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 SETTING DEPTH TVD 6018154 BOTTOM TOP 0 229 bbls Surface114' HOLE SIZECASINGWT. PER FT.GRADE 26# 535919 535536 TOP SETTING DEPTH MD Surface215.5# Per 20 AAC 25.283 (i)(2) attach electronic information 5,253' Surface DEPTH SET (MD) 4,409' MD / 3,620' TVD PACKER SET (MD/TVD) 4,487'4-1/2" Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST 6/8/2020 Date of Test: 1691 6/13/2020 24 Flow Tubing 0 132 Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary 198132 Jet Pump ***Please see attached schematic for Solid/Screen Liner Detail*** Liner run on 5/29/2020 666 ROP DGR AGR ABG ADR EWR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng N/A 12.7 Oil-Bbl: Water-Bbl: 666 0303 LONS 16-004 2,100' MD / 1,891' TVD N/AN/A N/A 12,192' MD / 3,533' TVD Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 7:54 am, Jul 06, 2020 +(: Completion Date 6/1/2020 HEW RBDMS HEW 7/8/2020 G SFD 7/13/2020 DLB 07/08/2020 DSR-7/8/2020MGR17SEP2020 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 2,100' 1,891' Top of Productive Interval SB NB 5,394' 3,777' 1,424' 1,349' 2,156' 1,937' 3,713' 3,213' 4,891' 3,737' 5,258' 3,772' SB NB 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: FORMATION TESTS Permafrost - Top SV5 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report Signature w/Date: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Formation at total depth: SB NA Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME SB NB SV1 Ugnu LA3 The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. 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. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.02 11:43:30 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: DH 6/30/2020 SCHEMATIC Milne Point Unit Well: MPU M-45 Last Completed: 6/1/2020 PTD: 220-044 + TD =14,338’ (MD) / TD =3,509’(TVD) 20” KB Elev.: 58.6’/ GL Elev.: 24.9’ 7” 9-5/8” 1 4 PBTD =14,328’ (MD) / TD = 3,509’(TVD) 9-5/8” ‘ES’ Cementer @ 2,566’ 4-1/2” Shoe @ 14,338’ 7 10 8 9 12 4-1/2” 3 Min ID 3.725” 8-1/2” Hole 2 6 11 5 See Screen/ Solid Liner Detail CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 5,407’ 0.0758 7” Tieback 26/ L-80 / TXP 6.151” Surface 5,253’ 0.0383 4-1/2” Screen Liner 250ђ 13.5 / L-80 / Hydril 625 3.920” 5,245’ 12,192’ 0.0149 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / TXP 3.958” Surface 4,487’ 0.0152 OPEN HOLE / CEMENT DETAIL 42” 18 Yards Pilecrete dumped down backside 12-1/4” 1st stage L –153 bbls / T – 82 bbls 12-1/4” 2nd stage L – 315 bbls / T – 56 bbls 8-1/2” Cementless Screen Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 229 Max Hole Angle = 64° @ Jet Pump Max Hole Angle = 67° @ XN profile Max Hole Angle = 69° @ Tubing tail Max Hole Angle = 94.7° TREE & WELLHEAD Tree Cameron 4 1/16" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 29’ 11” x 4-1/2” Tubing Hanger 3.970” 2 4,364’ 4.5” Discharge Pressure Gauge Mandrel (Discharge Gauge) 3.952” 3 4,373’ 4.5” Sliding Sleeve 3.813” 4 4,381’ 4.5” Gauge Mandrel w/ ¼” Wire (Intake Gauge) 3.951” 5 4,393’ 4.5” X Nipple (3.813” Packing Bore) 3.813” 6 4,410’ 7” x 4.5”Retrievable Packer 3.900” 7 4,435’ 4.5” XN Nipple (MIN ID = 3.725”)3.813” 8 4,486’ 4.5” WLEG 3.958” Lower Completion 9 5,245’ BOT SLZXP Liner Top Packer w/BD Slips 7” x 9-5/8” 6.170” 10 5,257’ 7” Tieback Assy. (8.25” OD No-Go) 6.151” 11 5,267’ 7” Hydril 563 L-80 x 4-1/2” Hydril 625 L-80 XO 5.924” 12 12,191’ Round nose float shoe - GENERAL WELL INFO API: 50-029-23676-00-00 Completed by Doyon 14 on 6/1/2020 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 3 5,271’ 3,773’ 5,395’ 3,777’ 18 8,452’ 3,700’ 9,186’ 3,666’ 3 9,647’ 3,644’ 9,770’ 3,640’ 4-1/2”SCREEN LINER DETAIL Jts Top (MD)Top (TVD) Btm (MD) Btm (TVD) 73 5,394’ 3,777’ 8,452’ 3,700’ 11 9,186’ 3,666’ 9,647’ 3,644’ 57 9,770’ 3,640’ 12,149’ 3,535’ 12,192' Activity Date Present Operations Ops Summary 5/17/2020 Making up 12- 1/4" drilling BHA R/D on M-44. Rig released at 12:00. See M-44 report for details.;Finish cleaning M-44 cellar, PJSM, Skid rig floor into move position. Held PJSM for moving rig off of the well. Install speed head and diverter tee, set rig mats, wellhead equipment and MPD shack behind M-45.;Pull off M-44, move rig matts from M-44 to M-45, align and spot rig over M-45.;Skid rig floor into drilling position. M/U stand DP, shim and level the rig.;Spot rock washer, fuel trailer, 3rd party shacks, 5 star trailer and water pump house. Install all stair landings. Install diverter and diverter line. C/O top drive saver sub. Rig on high line power at 20:30.;Finish diverter & diverter line installation, 348' overall length, 293' from substructure, 106' to closest ignition source M-22 wellhouse. Load pipe shed w/ BHA & HWDP. Load pits w/ 8.8 ppg spud mud. Perform derrick inspection.;Cover all gaps in matting boards w/ plywood. Verify rig level w/ stand of pipe hanging in elevators. Rig accepted at 04:00.;Function test diverter annular on 5" drill pipe - 16 sec. knife valve opening, 24 sec. annular closing. Test accumulator - 3000 PSI system pressure, 1800 PSI after closure, 200 PSI recharge in 41 sec, full recharge in 163 sec, 6 nitrogen bottle avg of 2183 PSI.;AOGCC representative Brian Bixby waived witness of the diverter test at 05:54 on 17 May 2020.;Rack back stand of drill pipe. Mobilize BHA components to the rig floor. M/U one stand of HWDP w/ jars and rack in derrick. 5/18/2020 Drilling 12.25'' surface hole at 1878' M/U 12 1/4'' Kymera bit and mud motor. Rig electrician Calibrate and test rig gas alarms, Totco calibrate PVT system, Hold pre spud meeting, Review rig evacuation plan with all parties.;M/U stand HWDP and TD, flood stack and lines, test lines to 3500 psi from TD IBOP to mud pumps, good, completing last item on acceptance checklist.;Spud well, clean out conductor t/ 114’ and drill to 124’ with water, displace to spud mud on the fly. Drill to 220' pumping 430 gpm, 490 psi, 40 rpm, 2k Tq. Back ream out of hole one stand, pull next stand on elevators. Pull bit to surface and inspect same.;PJSM, M/U DM collar and scribe RFO from motor. Continue M/U MWD tools, scribe to UBHO. Adjust UBHO to motor as per DD. Plug in, Initialize and upload MWD, RIH w/ 3 NMFCs, XO to 177', M/U std HW and TD, wash/ream to 220'.;Drill 12-1/4" surface hole f/ 220' t/ 460', (460’ TVD) 240' drilled, 60'/hr AROP. 500 GPM, 1060 PSI, 60 RPM, 2K TQ, 10- 15K WOB MW 9.0 in / 9..1 out, vis 300 in / 300 out, 9.4 ECD. 67K PU / 71K SO / 69K ROT Kick off @ 269' with 3°/100' build.;Drill 12-1/4" surface hole f/ 460' t/ 831' (825' TVD) 371' drilled, 123.67'/hr AROP. 495 GPM, 1210 PSI, 80 RPM, 3-5K TQ, 8-10K WOB. MW 9.0 in / 9..1+ out, vis 278 in / 300 out, 9.79 ECD. 75K PU / 83K SO / 83K ROT Start 4°/100' build and turn @ 549'.;Safety stand down w/ rig crew after pinched finger injury accident. Floorhand pinched finger while making a connection in the derrick. Discussed accident &review contributing factors. Review procedures for connections & building stands. Discussed risks &methods to eliminate or mitigate those risks.;Drill 12-1/4" surface hole f/ 831' t/ 1117' (1093' TVD) 286' drilled, 114.4'/hr AROP. 495 GPM, 1180 PSI, 80 RPM, 3-6K TQ, 5-15 WOB. MW 9.0+ in / 9..1+ out, vis 230 in / 290 out, 9.84 ECD. 80K PU / 88K SO / 87K ROT Install gas detector at 1030'.;Drill 12-1/4" surface hole f/ 1117' t/ 1878' (1709' TVD) 761' drilled, 126.83'/hr AROP. 480 GPM, 1410 PSI, 80 RPM, 5-7K TQ, 5-10K WOB. MW 9.3 in / 9.45 out, vis 100 in / 270 out, 10.6 ECD. 98K PU / 85K SO / 90K ROT;Ream stand 2x @ 1403' to reduce ECD from 10.8 ppg. End build and turn @ 1367', begin 34° tangent. Last survey @ 1744.77' MD / 1600.93' TVD, 37.11° inc, 47.85° azm, 7.8' from plan, 1.17' low and 7.7' right. 5/19/2020 Drilling 12- 1/4" surface hole at 4543' Drill 12-1/4" surface hole f/ 1878' t/ 2560' (2274' TVD) 682' drilled, 113.67'/hr AROP. 545 GPM, 1640 PSI, 80 RPM, 6K TQ, 8-10K WOB, 10.16 ECD. 115K PU / 96K SO / 102K ROT. MW 9.3 in / 9.4 out, Vis 180 in / 230 out, max gas 85u. Hi vis sweep @ 2355' back on time w/ no increase.;Base of permafrost @ 2111' MD / 1900' TVD. Ugnu MP_UG4 @ 2452' MD / 2182' TVD.;Drill 12-1/4" surface hole f/ 2560' t/ 3306' (2907' TVD) 746' drilled, 124.33'/hr AROP. 545 GPM, 1820 PSI, 80 RPM, 8K TQ, 3-15K WOB, 10.11 ECD. 140 K PU / 105K SO / 118K ROT. MW 9.1 in / 9.15 out, Vis 138 in / 138 out, max gas 61u.;Drill 12-1/4" surface hole f/ 3306' t/ 3900' (3338' TVD) 594' drilled, 99'/hr AROP. 600 GPM, 2150 PSI, 80 RPM, 10K TQ, 7-15K WOB, 10.02 ECD. 149K PU / 105K SO / 124K ROT. MW 9.15 in / 9.2 out, Vis 139 in / 161 out, max gas 52u. Hi vis sweep @ 3401' back on time w/ 10% increase.;Ugnu LA3 3704' MD / 3207' TVD.;Drill 12-1/4" surface hole f/ 3900' t/ 4543' (3670' TVD) 643' drilled, 107.17'/hr AROP. 600 GPM, 2150 PSI, 80 RPM, 16K TQ, 10-16K WOB, 10.11 ECD. 165K PU / 100K SO / 124K ROT. MW 9.4 in / 9.4 out, Vis 150 in / 192 out, max gas 198u. Hi vis sweep @ 4352' back on time w/ 20% increase.;Last survey @ 4408.39' MD / 3619.69' TVD, 65.81° inc, 155.79° azm, 8.35' from plan, 6.8' low, 4.73' right. Ugnu MB 4138' MD / 3488' TVD. 5/20/2020 BROOH at 1309' Drill 12-1/4" surface hole f/ 4543' t/ 5115' (3757' TVD) 572' drilled, 95.33'/hr AROP. 600 GPM, 2230 PSI, 80 RPM, 12-15K TQ, 10-15K WOB, 10.4 ECD. 157K PU / 91K SO / 115K ROT. MW 9.4 in / 9.5 out, Vis 83 in / 190 out, max gas 171u. Entered NA sand at 4901' MD / 3738' TVD.;Drill 12-1/4" surface hole f/ 5115' t/ 5414' (3776' TVD), 299' drilled, 74.75'/hr AROP. Drilled further in sand f/ 5334' t/ 5414' to bring inclination up to 90.92° as per geology. 540 GPM, 1720 PSI, 80 RPM, 10-13K TQ, 7K WOB, 10.26 ECD. 159K PU / 120K SO / 120K ROT.;MW 9.3 in / 9.3 out, Vis 94 in / 137 out, max gas 339u. Entered NB sand at 5250' MD / 3772' TVD.;Last survey @ 5375.02' MD / 3777.58' TVD, 90.92° inc, 168.35° azm, 6.94' from plan, 2.00' high, 6.65' right. Projection to TD 5414' MD / 3776' TVD, 8.4' from plan, 3.94' high, 7.76' right.;BROOH f/ 5414' t/ 5238', 450 GPM, 1300 PSI, 60 RPM, 13K TQ. Pump sweep & circulate hole clean while BROOH f/ 5238' t/ 5115' 600 GPM, 2000 PSI, 60 RPM, 14K TQ. Sweep back 400 strokes late w/ no increase. Final YP = 20. Max gas 80u. 160K PU / 91K SO / 118K ROT.;Rig lost high line power at 17:20, on generators.;Orient mud motor highside. Trip in hole f/ 5115' t/ 5414'. Perform 5 min. flow check - static. PJSM for BROOH.;BROOH f/ 5414' t/ 5234' w/ 450 GPM, 1200 PSI, 60 RPM, 14K TQ, 5 min/stand Increase to 600 GPM, 1750 PSI, 60-80 RPM, 13K TQ f/ 5234' t/ 3403'. Slow pulled speed as hole conditions required. 155K PU / 102K SO / 130K ROT, max gas 59u. Rig back on high line power at 20:20.;BROOH f/ 3403' t/ 1309' at 5 min/stand, slow for pressure or torque increases. 600 GPM, 1580-1650 PSI, 60-80 RPM, 6-17K TQ Pulled slow f/ 2357' t/ 2196' below the permafrost to clean up hole - 2 bottoms up. Slow pump in permafrost to 550 GPM, 1380 PSI, 80 RPM, 6-9K TQ. 105 PU / 80K SO / 90K ROT. Alaska Hilcorp Energy Company Drilling Composite Report 5/18/2020 Doyon 14Contractor Spud Date: Well Name: Field: County/State: MP M-45 Milne Point Unit 5/21/2020 Begin 1st stage surface cement job BROOH f/ 1309' t/ 833', 500 GPM, 1380 PSI, 60-80 RPM, 3-6K TQ, 5 min/stand. Pump out w/ no rotation f/ 833' t/ 738' & circulate 2x bottoms up. Monitor well for 10 min - static.;POOH on elevators f/ 738'. Lay down excess HWDP, rack back on stand w/ jars & L/D drill collars to 83'. Read MWD tools - retrieved all data. L/D BHA #1 f/ 83'. Bit graded: 1-1-WT-A-E-I-NO-TD. 86.5 bbls lost on trip out of the hole.;Clear rig floor and mobilize casing equipment to the rig floor. R/U 9-5/8" Volant CRT, spiders, bail extensions and elevators. PJSM for running casing. 2.5 BPH static losses.;M/U 9-5/8" casing shoe track: round nose float shoe, jt#1, Baker-Loc jt#2, float collar, jt#3 w/ bypass baffle installed to 121'. Pump thru shoe track to check floats - good. M/U baffle adapter & jt#4 to 163'. Torqued all connections to 21,000 ft/lbs w/ Volant tool & Baker-Loc first 4 connections.;Two 9-5/8" x 12-1/4" centralizer & 4 stop rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints.;Run 9-5/8" 40# L-80 TXP-BTC casing f/ 163' t/ 2499'. Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bowspring centralizers on jts #5-25 then every other joint to #53. Fill casing on the fly & top off every 10 joints.;Circulate a bottoms up at 2499'. Stage up pumps from 3.5 BPM, 103 PSI to 6 BPM, 180 PSI. 130K PU / 100K SO.;Run 9-5/8" 40# L-80 TXP-BTC casing f/ 2499' t/ 5412'. Torque to 21,000 ft/lbs with the Volant tool. Install Halliburton ES cementer between jts #78 & 79, with 1 centralizer & stop ring on each pup joint. Centralizers installed on jts #74-83 then every other joint to #131.;Total of 135 joints of casing, 76 Expand-O-Lizer centralizers and 10 stop rings ran. 34 bbls total lost while running casing.;Condition & circulate for cement job. Stage pumps up to 6 BPM, 210 PSI. 250K PU / 112K SO. Start rotary w/ torque limit set at 20K, 5 RPM when reciprocating. Reciprocate 30' f/ 5412' t/ 5382', continue to stage up to 7 BPM, 130 PSI. 215K PU / 145K SO. Circulated a total of 3 bottoms up.;Cementers finished rigging up and filled cement water tank w/ 93° water then blend w/ cold water to 76°. PJSM. Blow down top drive & R/U cement lines. Pre-treat mud in pit #4. Pump 50 bbls of pre-treated mud, 5 BPM, 130 PSI. 12 bbls losses while circulating.;Daily losses = 106.5 bbls, Cumulative losses = 106.5 bbls. H2O from L-Pad Lake: 565 bbls Daily/ 5,150 bbls total Cuttings/mud/cement to MPU G&I: 808 bbls Daily / 4,729 bbls total 5/22/2020 Finish N/U BOPs Pump 5 bbls water, 3.5 BPM, 170 PSI. Pressure test lines to 1000 PSI low / 4200 PSI high. Bleed down and line up to well. Mix and pump 60 bbl tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 3.5 BPM, 185 PSI. Mix & Pump 153 bbl 12 ppg Lead cmt ( 365 sx ), 3.5 BPM, 210 PSI.;Mix & Pump 82 bbl 15.8 ppg tail cmt. ( 400 sx ) 4.5 BPM, 725 PSI. Chase with 20 bbl fresh water. Rig displace with 194 bbl 9.4 ppg spud mud at 6 BPM, 190 PSI. HES pump 80 bbl 9.4 ppg tuned spacer, 3.5 BPM, 215 PSI. Rig displace at 6 BPM, 500 PSI, 101.3 bbl 1013 stks to bump.;2953 total strokes. 600 psi final lift. Hold 500 over at 1100 for 5 min. Bleed down and check Floats. Good. Pressure up and open ES cmt tool at 2900 psi. Cement in place at 09:20 15 bbls lost during cement job. *** Notified AOGCC of upcoming BOP test at 07:16 on 22 May 2020 ***;Saw Pol-E-Flake at shakers at opening. Circulate hole clean through ES cementer at 2292'. Displace out 60 bbl spacer, 40 bbl cmt and 70 bbl chase spacer. Send all to rockwasher.;Take mud returns back to pits. Dumped total of 200 bbl to rock. Circ two btm up back to pits. Clean. Shut down and flush all surface equipment in black water. Cycle annular three times in black water and flush same.;Circ at 5 bpm, 160 psi while waiting on cmt and preparing for second stage. Work pipe f/ 100K t/ 200K every 30 min.;PJSM for second stage cmt jpb. Continue to circ at 5 bpm, 160 psi.;Perform 2nd stage cement job through ES cementer at 2292'. Pump 5 bbls of water Mix & pump 60 bbls of 10.0 ppg Tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 5 BPM, 250 PSI. Mix & pump 315 bbls 10.7 ppg Perm L lead cement (400 sks), 6 BPM, 430 PSI ICP, 605 PSI FCP.;Observed spacer and good cement back @ 314 bbls of lead pumped. Mix & pump 56 bbls of 15.8 ppg tail cement (270 sks), 5.25 BPM, 605 PSI. Drop closing plug. Pump 20 bbls of water.;Displace w/ #2 rig pump with 9.5 ppg spud mud. 5 BPM, 190 PSI ICP, 540 PSI FCP. 350 PSI final lift. Slow to 3 BPM, 390 PSI for last 5 bbls pumped. Plug bumped 1.92 bbls early at 1505 stks . 229 bbls of cement to surface. CIP at 19:05.;Pressure up & shifted ES cementer closed at 1350 PSI. Pressure held good, bleed off to verify cementer closed. No flow back - good. 34 bbls lost during cement job.;Drain stack to the cellar. L/D Volant CRT. Disconnect knife valve accumulator lines. Function annular and flush w/ black water. Rig vacuum fluid out of casing to cellar level. Disconnect & begin N/D diverter line.;Back out speed head lockdown screws on diverter adapter & hoist stack. Install 9-5/8" casing slips and set with 112K on slips. Cut 9-5/8" casing (Joint #135 = 40.43' - 21.26' = 19.17' left in hole). Set stack back down. N/D annular & diverter tee, then remove from cellar. Sim-ops: clean pits.;N/U FMC slip lock head and test Cahn seal to 500 PSI for 5 min. & 2470 PSI for 10 min. N/U casing and tubing spools.;Remove 13-3/8" spacer spool. Install 11" x 13-3/8" adapter spool and N/U BOP stack & R/U turnbuckles. N/U choke line. Install trip nipple. Sim-ops: clean pits, clear casing equipment from rig floor, mobilize test equipment & safety valves to the rig floor. Load & strap 5" drill pipe.;Daily losses = 61 bbls, Cumulative losses = 167.5 bbls H2O from L-Pad Lake: 560 bbls Daily/ 5,710 bbls Total Source Water from G&I: 400 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 2,057 bbls Daily / 6,786 bbls Total 5/23/2020 Drilling cement in 9- 5/8" casing at 5370' Install test plug, 4-1/2" test joint and R/U test equipment. Fill stack w/ water and purge lines. R/U test manifold w/ floor valves and dart valve. Perform shell test of BOP to 3000 PSI - good.;Test BOP equipment w/ AOGCC inspector Adam Earl witnessing. All tests performed with fresh water to 250 PSI low / 3000 PSI high. Tests held for 5 min. each and charted. 1) Annular on 4.5" test joint, choke valves 1, 12, 13, 14, kill Demco & 5" FOSV #1;2) Upper 4.5"x7" VBR on 4.5" test joint, choke valves 9, 11, HCR kill & 5" FOSV #2 3) Choke valves 5, 8, 10, manual kill & 5" dart valve 4)Choke valves 4, 6, 7 & 3.5" dart valve 5) Lower 3.5"x6" VBR on 4.5" test joint, 3.5" FOSV (tighten test connection - retest good);6) Upper 4.5"x7" VBR on 7" test joint, choke valve 2 & upper IBOP 7) HCR choke & lower IBOP 8) Manual choke 9) Lower 3.5"x6" VBR on 5" test joint 10) Blind rams & choke valve 3 11) Manual choke A 12) Manual choke B.;Accumulator test: 3000 PSI system pressure, 1700 PSI after closure, 200 PSI recovery in 48 sec, full recovery in 188 sec, 6 nitrogen bottle average = 2125 PSI.;Blow down choke & kill lines. Pull test plug and L/D test joint. Install 9-1/16" I.D. wear bushing. Install split master bushing & 30' mousehole.;PJSM. M/U 8-1/2" NOV SK616M-J1D bit, near bit stabilizer, 7600 Geo-Pilot, MWD w/ ADR, DGR, PWD & directional to 83'. Test & initialize MWD tools. M/U 8-1/2" roller reamer, float sub, 3 NM flex drill collars & second float sub t/ 187'. RIH w/ HWDP & jar stand to 281'. TIH w/ 5" drill pipe to 2186'.;Fill drill pipe, break in Geo-Pilot seals & pressure test Geo-Span to 3000 PSI.;Ream down f/ 2186' t/ 2286', drill cement f/ 2286' to ES cementer at 2289'. Drill shut-off plug & ES cementer f/ 2289 t/ 2293', 500 GPM, 1130 PSI, 30 RPM, 3K TQ, 5-7K WOB. Ream f/ 2305' t/ 2275' three times then slide through with no rotation once - drag observed. RIH t/ 2373' & blow down top drive.;TIH f/ 2373' t/ 4946' on elevators. Pick up singles f/ 4946' t/ 5200'. Wash down with singles f/ 5200' t/ 5263', 485 GPM, 1400 PSI, 40 RPM, 11K TQ. 180 PU / 83K SO / 110 ROT.;R/U to test 9-5/8" casing and purge lines. Close 4-1/2" x 7" upper VBR on 5" drill pipe. Test casing to 2500 PSI for 30 min. - good test. R/D test equipment & blow down lines.;Ream down f/ 5263' t/ 5281'. Drilled cement f/ 5281' t/ 5285', 500 GPM, 1440 PSI, 40 RPM, 13K TQ 2-4K WOB. Drill baffle adapter on depth f/ 5285' t/5286', 5-7K WOB. Drill cement to 5325'. Drill float collar on depth f/ 5325' t/ 5326', 5-7K WOB. Drill cement to 5370' 5/24/2020 Drilling 8.5'' production lateral at 7210' Drill 9-5/8" casing shoe track f/ 5370' t/ 5207', drilled shoe on depth f/ 5405' t/ 5407', 500 GPM, 1430 PSI, 40 RPM, 14K TQ, 3-6K WOB. Clean out rat hole f/ 5407' t/ 5414'. 180K PU / 83K SO / 113K ROT.;Drill 8-1/2" production lateral f/ 5414' t/ 5434', 500 GPM, 1430 PSI, 40 RPM, 14K TQ, 10K WOB. Ream shoe 3x times. 180K PU / 80K SO / 115K ROT. MW 9.3 in / 9.35 out, vis 36 in / 36 out, max gas 336u.;Circulate hole clean while reciprocating f/ 5407' t/ 5358', 550 GPM, 1530 PSI, 40 RPM, 12K TQ.;Perform FIT to 12.0 ppg at 5407' MD / 3776' TVD w/ 9.35 ppg mud to 560 PSI - good test. Pumped 1.1 bbl and bled back 1.0 bbl.;Remove trip nipple and install MPD RCD.;Pump 30 bbl hi vis spacer then displace to 8.8 ppg Flo-Pro, 295 GPM, 730 PSI, 40 RPM, 12K TQ. Blow down top drive, choke and kill lines. 148K PU / 80K SO / 112K ROT.;Slip and cut 66' of drilling line. Calibrate block height, service and inspect top drive. Sim-op: clean pit #4.;Obtain new slow pump rates then wash to bottom, 400 GPM, 890 PSI. 130K PU / 97K SO / 116K ROT w/ 4K TQ.;Drill 8-1/2" production hole f/ 5434' t/ 5895' (3758' TVD), 461' drilled, 115.25'/hr AROP. 450 GPM, 1060 PSI, 120 RPM, 11K TQ, 5K WOB, 9.95 ECD. 136K PU / 90K SO / 111K ROT, MW 8.8 ppg, vis 46, max gas 361u.;Drill 8-1/2" production hole f/ 5895' t/ 6700' (3774' TVD), 805' drilled, 134.17'/hr AROP. 450 GPM, 1190 PSI, slowed pump @ 6563' to 380 GPM, 890 PSI, 80 RPM, 12K TQ, 12K WOB, 9.85 ECD. 153K PU / 77K SO / 110K ROT, MW 8.8, vis 44, max gas 363u. Not achieving 3°/100' right turn, slow flow and rotary.;Grizzly bear on moose pad attempting to get in the covered dumpster. Notify rig personnel, pad operator and Milne security. Milne safety dispatched to Moose pad. Bear circled the pad and left heading north.;Drill 8-1/2" production hole f/ 6700' t/ 6979' (3762' TVD) 279' drilled, 79.71'/hr AROP. 380 GPM, 920 PSI, 60 RPM, 10K TQ, 15K WOB, 9.86 ECD. 145K PU / 85K SO / 110K ROT, MW 8.8, vis 45, max gas 410u.;Plan right turn to 183.84° azimuth ended at 6427'. Survey at 6871' was 185.99° azimuth beginning to return to the plan, maximum of 84.57' left of plan.;Observed 15.2° dogleg f/ 6948' t/ 6959' after drilling a concretion f/ 6932' t/ 6944', inclination built from 91.99° to 93.66°.= Ream w/ 100% deflection lowside f/ 6745' t/ 6979'. Dropped dogleg to 6.1°, dropped inclination f/ 91.99° to 91.90° and 93.66° to 92.51°;Drill 8-1/2" production hole f/ 6979' t/ 7210' (3755' TVD), 231' drilled, 115.5'/hr AROP. 400 GPM, 1250 PSI, 85 RPM, 10K TQ, 8K WOB, 9.77 ECD. 143K PU / 83K SO / 112K ROT, MW 8.8, vis 43, max gas 335u.;Pumped high vis sweep at 7037', back 200 stks late w/ 150% increase. Drilled 4 concretions for a total thickness of 22' (1.3% of the lateral). Survey @ 7062.86' MD / 3758.13' TVD, 91.42° inc, 191.25° azi, 78.65' from plan, 39.22' low, 68.17' low.;Daily losses = 0 bbls, Cumulative losses for interval = 0 bbls H2O from L-Pad Lake: 360 bbls Daily/ 6,530 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 919 bbls Daily / 8,717 bbls Total 5/25/2020 Drilling 8.5'' production lateral at 9466' Drill 8-1/2" production lateral f/ 7210' t/ 7824' (3725' TVD), 614' drilled, 102.33'/hr AROP. 400-450 GPM, 1080-1310 PSI, 80-85 RPM, 11K TQ, 7-15K WOB. 145K PU / 78K SO / 110K WOB. 8.8 ppg MW, 45 vis, 9.96 ECD. 394u max gas. Drilled out the top of the NB sand f/ 7800' t/ 7835' (35');Drill 8-1/2" production lateral f/ 7824' t/ 8466' (3707' TVD), 642' drilled, 107'/hr AROP. 415 GPM, 1290 PSI, 80 RPM, 13K TQ, 16-20K WOB. 151K PU / 68K SO / 105K ROT. 8.8 ppg MW, 46 vis, 10.17 ECD, 391u max gas. High vis sweep @ 7990', on time w/ 100% increase.;Drill 8-1/2" production lateral f/ 8466' t/ 8944' (3725' TVD) 478' drilled, 79.67'/hr AROP. 505 GPM, 1800 PSI, 80 RPM, 13K TQ, 16-20K WOB. 146K PU / 66K SO / 101K ROT. 8.85 ppg MW, 46 vis, 10.74 ECD, 385u max gas.;Drill 8-1/2" production lateral f/ 8944' t/ 9466' (3654' TVD) 700' drilled, 116.67'/hr AROP. 505 GPM, 1870 PSI, 80 RPM, 13-15K TQ, 10-15K WOB. 145K PU / 65K SO / 103K ROT. 9.05 ppg MW, 46 vis, 11.04 ECD, 273u max gas. High vis sweep @ 8944', 400 stks late w/ 60% increase.;Drilled 15 concretions for a total thickness of 65' (1.7% of the lateral). MPD closing chokes on connections max build to 41 PSI. Chokes open drilling w/ 53 PSI line restriction. Last survey @ 9348.01' MD / 3658.41' TVD, 92.47° inc, 183.75° azi, 24.11' from plan, 23.69' low, 4.49' right.;Daily losses 22 bbls, cumulative interval losses 22 bbls. H2O from L-Pad Lake: 720 bbls Daily/ 7,250 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 627 bbls Daily / 9,344 bbls Total 5/26/2020 Drilling 8-1/2'' production lateral at 10835' Drill 8-1/2" production lateral f/ 9466’ t/ 9610' (3645' TVD) 144' drilled, 24’/hr AROP. 500 GPM, 1650 PSI, 80 RPM, 13-15K TQ, 10-20K WOB. 155K PU / 63K SO / 102K ROT. 8.9 ppg MW, 41 vis, 10.6 ECD, 240u max gas. 290 bbl full mud dilution @ 9537’.;Drill 8-1/2" production lateral f/ 9610’ t/ 9906 (3640' TVD) 296’ drilled, 49.3’/hr AROP. 520 GPM, 1790 PSI, 120 RPM, 14K TQ, 10-18K WOB. 165K PU / 0K SO / 101K ROT. 8.85 ppg MW, 44 vis, 10.61 ECD, 312u max gas. Drilled out the top of the NB sand f/ 9669' t/ 9777' (108') Lost slackoff wt @ 9893’.;Drill 8-1/2" production lateral f/ 9906’ t/ 10415’ (3615' TVD) 509’ drilled, 84.8’/hr AROP. 500 GPM, 1830 PSI, 120 RPM, 14K TQ, 12-18K WOB. 160K PU / 0K SO / 99K ROT. 8.9 ppg MW, 45 vis, 10.86 ECD, 314u max gas. High tandem sweeps @ 8944', 500 stks late w/ 75% increase.;Drill 8-1/2" production lateral f/ 10415' t/ 10835' (3586' TVD) 420' drilled, 70'/hr AROP. 515 GPM, 1870 PSI, 100-130 RPM, 14-18K TQ, 7-15K WOB. 155K PU / 0K SO / 99K ROT. 9.05 ppg MW, 46 vis, 11.04 ECD, 314u max gas.;We have drilled 33 concretions for a total thickness of 333' (6% of the lateral). MPD closing chokes on connections max build to 68 PSI. Chokes open drilling w/ 57 PSI line restriction. Last survey @ 10680.52' MD / 3596.75' TVD, 94.02° inc, 186.04° azi, 26.17' from plan, 24.74' low, 8.52' right.;Daily losses 54 bbls, cumulative interval losses 76 bbls. H²O from L-Pad Lake: 0 bbls Daily/ 7,250 bbls Total H²0 From 6 Mile Lake: 605 bbls Daily / 605 bbls Total Source H²O from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 1,316 bbls Daily / 10,660 bbls Total 5/27/2020 Displacing to 8.45 ppg 2% KCL/NaCl lubricated/visc osified brine. Drill 8-1/2" production lateral f/ 10835' t/ 11321' (3573' TVD) 486' drilled, 81'/hr AROP. 500 GPM, 1950 PSI, 100 RPM, 15-18K TQ, 10-15K WOB. 155K PU / 0K SO / 97K ROT. 9.05 ppg MW, 42 vis, 11.2 ECD, 313u max gas. High vis sweep @ 11035', 300 stks late w/ 25% increase.;Drill 8-1/2" production lateral f/ 11321’ t/ 11893' (3542' TVD) 572’ drilled, 95.3'/hr AROP. 500 GPM, 1900 PSI, 100 RPM, 18K TQ, 10K WOB. 170K PU / 0K SO / 95K ROT. 9.0 ppg MW, 45 vis, 11.23 ECD, 335u max gas. Drilled out the top of the NB sand f/ 11536' t/ 11609' (73').;Drill 8-1/2" production lateral f/ 11893' t/ TD @ 12192' (3533' TVD) 299’ drilled, 74.75/hr AROP. 500 GPM, 2040 PSI, 100 RPM, 23K TQ, 10-16K WOB. 172K PU / 0K SO / 92K ROT. 9.0 ppg MW, 46 vis, 11.51 ECD, 285u max gas.;Fault #1 crossed @ 12151’. TD in the Schrader Bluff Clays above NB sands. 61 concretions were drilled in the lateral, for a total thickness of 487' (7.2%).;Last survey at 12123.92' MD / 3535.06' TVD, 92.17° inc, 185.37° azm, 17.83’ from plan, 3.48' high and 17.48' left. Extrapolated to TD at 12192' MD / 3532.48' TVD, 92.17° inc,, 185.37° azm, 16.38' from plan, 2.99' high and 16.11' left.;Pumped tandem sweeps, 30 bbl brine / 25 bbl hi-vis flo-pro. 500 GPM, 2020 PSI, 100 RPM, 17k Tq. Sweeps back 600 stks late w/ 10% increase in cuttings returns Circulated a total of 4 bottoms up. Rack back a stand each bottoms up to 11831'. 10.92 ECD, 8.95 ppg MW, 42 vis. PJSM for displacement.;Ream to bottom (no slack off weight) f/ 11831' t/ 12192'. 415 GPM, 1530 PSI, 40 RPM, 15k Tq.;Pump SAPP pill treatment: Pump 30 bbl hi vis spacer, 3- 20 bbl SAPP pills with 50 bbl seawater spacers, chase with 300 bbls seawater. Pump 30 bbl hi vis spacer 7.3 bpm, 950 psi, 130 rpm, 21k tq.;Displace w/ 8.5 ppg 4% lube viscosified brine 7.3 BPM, 1003 PSI ICP 100 RPM, 21k Tq . Divert mud & SAPP trains/seawater to rock washer.;Daily losses 25 bbls, cumulative interval losses 101 bbls. H²O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H²0 From 6 Mile Lake: 660 bbls Daily / 1,175 bbls Total Source H²O from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 1,316 bbls Daily / 10,660 bbls Total 5/28/2020 Removing MPD RCD bearing Continue displacement with 937 bbls of 8.45 ppg viscosified lubricated 2% KCL/NaCL brine. 300 GPM, 900 PSI ICP / 710 PSI FCP, 80 RPM, 19K TQ initial, 13K TQ final. Spacer & brine strung out and 162 bbls of lubed brine interface dumped to RW.;MPD initially started with full open choke w/ 8.95 ppg mud, increased to 125 PSI w/ 8.45 ppg brine. Reciprocate pipe 75'. PST passed w/ 3.7, 3.9 & 4.0 sec. No losses recorded during displacement. Max gas of 1965u during displacement, peaked with seawater to surface.;Perform pressure monitoring w/ MPD. Trap 11 psi and built to 59 psi in 5 min. Bleed off to 9 PSI and built to 50 PSI in 5 min. Bleed off to 9 psi and built to 48 psi, with 8.5 ppg brine out = 8.9 ppg EMW. Obtain new slow pump rates. 165K PU / 40K SO / 110K ROT with lubricated brine.;BROOH f/ 12192' t/ 10657' at 5-10 min/stand, 450 GPM, 1190 PSI, 100 RPM, 12K Tq. MPD full open choke while pumping = 9.6-10.5 ppg ECD & 100 PSI static = 9.2 ppg EMW. L/D stands 5'' DP utilizing the mouse hole, sort DP due f/ inspection. 84 bbls losses while BROOH.;BROOH f/ 10657' t/ 8591' at 5-10 min/stand slowing as needed for hole cleaning or packing off, 450 GPM, 945 psi, 100 RPM, 11K Tq. L/D stands 5'' DP utilizing the mouse hole, sort DP due f/ inspection. MPD full open choke while BR and 100 psi during connections.;BROOH f/ 8591' t/ 5390' at 5-10 min/stand slowing down as needed for hole cleaning and sight packing off , 450 GPM, 1000 psi, Reduce RPM t/ 40 while pulling BHA into shoe. Losses at 1 bbl hr, 99 total bbls loss during BROOH.;Pump 30 bbl high vis sweep, back on time w/ minimal increase. Pumped additional 1950 strokes for sand to clean up on shakers. SimOps:Make up Safety joint for upcoming 4-1/2" liner run.;Hold kick drill w/ crew. Install FOSV, Blow down TopDrive & Geo-Span. Slip & cut 46' of drilling line. Monitor pressure build with MPD chokes closed. Initial build t/ 58 psi in 5 min. Bleed down and build to 48 psi in 10 min. Bleed down and build to 38 psi in 10 min.;Final bleed and build to 38 psi in 20 min. 8.8 ppg fluid + 40 PSI @ 3777’ TVD = 9.0 ppg EMW. Weight up mud pits to 9.2 ppg with oilfield salt while continuing slip and cut Service TopDrive, Drawworks and roughneck.;Spot 9.2 ppg viscosified/lubricated brine from shoe to surface. 550 GPM, 1300 PSI, 30 RPM, 5K TQ. MPD full open choke while circulating, 9.9 ECD.;Shut pumps down and monitor for flow at possum belly. Initial flow of 1.64 bph slowing to 0.61 bph after 5 min, Close 4" MPD line, open 2" bleeder & monitor for flow, slowed to 0.25 bph in 10 min. then static after 20 min. Hold PJSM on removing RCD bearing while monitoring.;Remove MPD RCD and install trip nipple.;Daily losses (Midnight)- 97 bbls, Cumulative interval losses 198 bbls. H²O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H²O From 6 Mile Lake: 525 bbls Daily / 2,360 bbls Total Source H²O from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 2,212 bbls Daily / 14,540 bbls Total 5/29/2020 RIH with 4.5'' production screen liner on 5'' HWDP @ 8832' Finish installing trip nipple. Fill stack & check for leaks - none. Start hole fill pump.;TOOH on elevators f/ 5295' L/D 5" drill pipe to 1233'. Pumped dry job at 4946’ With 10 stands remaining, drop 2.45'' drift on wire, Rack drifted DP in the derrick to HWDP @ 281'. Mark and segregate drill pipe for inspection and hard band. 6 bbl losses TOOH f/ shoe.;Flow check before pulling BHA, static, L/D jar stand, float subs and NMFCs to 83', Recover drift on wire. Plug in and upload MWD. L/D remaining BHA. Bit grade= 1-3-BT-A-X-I-CT-TD Found a 1- 3/4”x5” piece of ES Cmtr aluminum wedged in a junk slot of the Bit NRP Sleeve.;The ILS was 1” under gauge, visible wear on the bit sleeve and wear bands of the MWD.;Clear and clean rig floor, M/U stack washer and flush stack. Remove split bushings, install master bushing. Load tools to rig floor, R/U 4 1/2'' handling equipment and power tongs. Ready FOSV w/ 4 1/2'' H625 XO.;Hold PJSM on picking up/running liner. P/U round nose shoe w/ XO jt, and run 4-1/2'', 13.5#, L-80 H625 lower screen completion as per tally to 6921'. 103K PU / 88K SO inside the 9-5/8" shoe 5704'.;Torque to optimum @ 9600 ft/lbs, On blank jts- install 1- 4 1/2'' x 7 1/4'' straight vane centralizer w/ 1- stop ring free floating on each joint 1-21. 24 blank joints, 141 Halliburton 250 micron screens .0.4 bph loss rate 3.5 bbls lost running liner.;M/U Baker 7"x9-5/8" SLZXP liner top packer to 6959’ then run one stand of 5" drill pipe to 7054'. Pump 10 bbls to ensure clear flow path through Baker tools, 3 BPM, 100 PSI. Obtain parameters: 114K PU / 82K SO / 98K ROT, 15 & 20 RPM both at 6.5K TQ.;Run 4-1/2" lower production completion on 5" drill pipe from the derrick f/ 7054' t/ 7816'. Single in the hole w/ 5" HWDP f/ 7816' t/ 8832'. 165K PU / 110K SO. 3 bph losses.;Daily losses = 18 bbls, cumulative interval losses = 216 bbls. H²O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H²O from B-Pad Creek: 525 bbls Daily / 525 bbls Total;H²O From 6 Mile Lake: 600 bbls Daily / 2,960 bbls Total Source H²O from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 114 bbls Daily / 14,654 bbls Total 5/30/2020 Perform 7" Dummy Run_Swap to Completions Run 4-1/2" lower production completion. Single in the hole w/ 5" HWDP f/ 8832' t/ 12126' RIH with stand from derrick & Tag btm at 12195'. Set liner in tension. Drop 0.906" ball. 260K PU / 135K SO.;Pump ball down with 30 bbl high vis sweep and land ball on seat at 43.9 bbl. Pressure up and saw packer set at 2650 psi. Hold 3K for 5 min. Pressure up to 4150 with mud pumps and line up test pump. Pressure up to 4350 psi & shear neutralizer tool. Pressure bled to 0.;P/U & verify free, Good. Test back side to 1500 psi for 10 min, Good. Pump at 2 bpm & pull out of liner top. Hold 300-500 psi while pulling out. Bring pumps to 10 bpm when pressure dumped. Circ out sweep and two btm up total staging pumps up to 12.6 bpm 1800 psi. Got sand back at btm up.;Work pipe 20' staying 15' above liner top.;PJSM, Line up and pump sweep and displace the well to clean 9.2ppg brine at 7 bpm. Dump 100 bbl interface plus sweep.;Monitor well. Static. Blow down choke and surface equipment.;PJSM, POOH & L/D HWDP F/ 5230' T/ 900'. Lay down 9 stds 5" DP and liner running tool. Rupture disk was blown, Circ sub still intact. Total of 14 bbls loss during TOH.;Drain BOP stack and pull wear bushing. Perform dummy run w/ 7" hanger.;Swap to completion. See completion report #1 for details.;Daily losses 29 bbls, cumulative interval losses 245 bbls. H2O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H2O from B-Pad Creek: 50 bbls Daily / 575 bbls Total;H2O From 6 Mile Lake: 600 bbls Daily / 2,960 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 907 bbls Daily / 15,561 bbls Total Activity Date Present Operations Ops Summary 5/30/2020 Running 7'' Tie Back Liner at 4200' Refer to final drilling report for details.,Mobilize 7" handling equipment to rig floor and R/U to run liner. Load shed w/ 7" 26# L-80 TXP- BTC liner.,PJSM. P/U Baker bullet seal assy w/ 8.25" O.D. locator to 15'. Run 7" 26# L-80 TXP-BTC liner f/ 15' t/ 4200' Torque to 14,750 ft/lbs with Doyon double stack tongs. 6 bbls lost while running liner.,Daily losses 29 bbls, cumulative interval losses 245 bbls. H2O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H2O from B-Pad Creek: 50 bbls Daily / 575 bbls Total H2O From 6 Mile Lake: 600 bbls Daily / 2,960 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 907 bbls Daily / 15,561 bbls Total 5/31/2020 Pressure test Tree Run 7" 26# L-80 TXP-BTC liner F/ 4200' T/ 5254.6. Torque to 14,750 ft/lbs with Doyon double stack tongs. Tag out on no go on depth. Space out with full joints. 129 joints total. M/U hanger and landing joint. Land hanger. R/U to reverse circulate.,Test lines to 250/2500 psi. PJSM, Pump Corrosion inhibitor & Diesel freeze protect. Reverse circ & Pump 86 bbl 9.2 PPG clean brine with 1 % concor 303. Chase with 65 bbl diesel. Strip in and land hanger. Check for isolation. Bleed down back side. No flow. Good. R/D circ lines & landing joint. Blow down stack to cuttings box.,Change handling equipment to 5'' DP. M/U joint of 5'' & pack off running tool. RIH & land pack off as per well head supervisor. RILD. Test to 250/5000 psi. Good. Back out running tool. L/D Same.,Test 9 5/8 X 7'' with injection line & rig pumps with diesel to 1000 psi for 30 min. Good. Blow down surface equipment.,R/U to run 4.5 TXP jet pump completion with Baker tec wire.,PJSM. M/U WLEG, Halliburton XN nipple with RHC installed / Baker Premier Production Packer assembly, X nipple, Zenith ported pressure sub, Durasleeve SSD & gauge carrier to 132'. Install ¼” SS TEC wire and gauge, test good. Torque to 6170 ft/lbs with Doyon double stack tongs.,Run 4-1/2" 12.6# L-80 TXP-BTC tubing f/ 132' t/ 4455'. Torque to 6170 ft/lbs with Doyon double stack tongs. Test TEC wire every 1000’. Installed 60 cross coupler Cannon clamps (4 on pup joints above gauges, 1 ea first 5 joints then every other joint). 9 bbls total losses running tubing.,M/U FMC 11"x4.5" tubing hanger & 5” jt of DP w/ TCII XO for landing joint. Perform hanger penetration with TEC wire. Obtain final readings: 1743.56 & 1746.02 PSI / 73.3° tbg & 72.7° ann. Drain stack, blow down choke & kill lines. Land tubing on hanger – 86k PU / 74k SO, 34k on hanger. RILD & L/D landing joint and install BPV.,Clear rig floor of casing equipment and TEC wire spool.,L/D trip nipple and 90' mousehole extension. Remove kill line & N/D BOP stack.,Perform Centrilift penetrations & terminate - final readings tubing: 1715.68 PSI, 73.7°, annulus 1718.88 PSI, 72.9°. Install test dart in BPV. N/U tubing head adapter flange & 5M FMC production tree. Test tubing hanger void to 500 PSI for 5 min / 5000 PSI for 10 min - good tests. R/U equipment to test Tree.,Rig ULSD in gallons: 0 rec'd, 627 used, 8122 on hand. Daily (midnight) losses = 17 bbls, Cumulative losses for production lateral = 262 bbls H2O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H2O from B-Pad Creek: 140 bbls Daily / 715 bbls Total H2O From 6 Mile Lake: 165 bbls Daily / 3,125 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 227 bbls Daily / 15,788 bbls Total 6/1/2020 RDMO to L- 60 R/U Testing and u Tube lines. Had to wait on bolts from well head Reps to N/U flange. Test lines to 350/4000 psi. Good.,Reverse circ 81 bbl diesel freeze protect at 3 bpm down IA taking returns up the tubing to cuttings box. FCP 800. Static pressure at 310 psi. R/U lubricator extension & drop ball & rod.,Pressure up on tubing and set packer. Saw tool set at 1950 psi and held 3500 for 30 min. Good. Bleed down tubing to 2000 psi. Pressure up on IA to 3500 for 30 min. Good test. Bleed down IA and tubing to 400 psi.,Blow down all surface lines and R/D same. Secure tree in cellar. Rig released @ 17:30.,Move rig off M-45 to L-60. See L-60 report for details.,H2O from L-Pad Lake: 0 bbls Daily/ 6,930 bbls Total H2O from B-Pad Creek: 140 bbls Daily / 715 bbls Total H2O From 6 Mile Lake: 165 bbls Daily / 3,125 bbls Total Source Water from G&I: 0 bbls Daily / 400 bbls Total Cuttings/mud/cement to MPU G&I: 344 bbls Daily / 16,132 bbls Total Recycle to ORT: 140 bbls daily / 140 bbls total Contractor Spud Date: Well Name: Field: County/State: MP M-45 Milne Point Unit Alaska Hilcorp Energy Company Completion Composite Report 5/18/2020 Doyon 14 28 May, 2020 Milne Point M Pt Moose Pad MPU M-45 500292367600 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 Actual RKB @ 58.69usft Design:MPU M-45 Database:NORTH US + CANADA MD Reference:MPU M-45 Actual RKB @ 58.69usft North Reference: Well MPU M-45 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU M-45, Slot 48 usft usft 0.00 0.00 6,027,889.76 533,993.77 24.90Wellhead Elevation:25.10 usft0.50 70° 29' 13.996 N 149° 43' 19.751 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-45 Model NameMagnetics IFR 5/30/2020 15.95 80.91 57,387.00000000 Phase:Version: Audit Notes: Design MPU M-45 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.59 184.000.000.0033.59 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 5/28/2020 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa229.02 5,375.02 MPU M-45 MWD+IFR2+MS+Sag (1) (MP 05/14/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa5,444.99 12,123.32 MPU M-45 MWD+IFR2+MS+sag (2) (MP 05/26/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 33.59 0.00 0.00 33.59 0.00 0.00-25.10 6,027,889.76 533,993.77 0.00 0.00 UNDEFINED 229.02 0.37 349.86 229.02 0.62 -0.11170.33 6,027,890.38 533,993.66 0.19 -0.61 3_MWD+IFR2+MS+Sag (1) 322.87 2.08 13.95 322.84 2.57 0.25264.15 6,027,892.33 533,994.00 1.86 -2.58 3_MWD+IFR2+MS+Sag (1) 413.58 4.02 18.93 413.42 7.18 1.67354.73 6,027,896.95 533,995.41 2.16 -7.28 3_MWD+IFR2+MS+Sag (1) 509.42 5.72 18.96 508.91 14.87 4.32450.22 6,027,904.65 533,998.02 1.77 -15.14 3_MWD+IFR2+MS+Sag (1) 603.39 7.82 28.78 602.22 24.91 8.92543.53 6,027,914.70 534,002.57 2.54 -25.47 3_MWD+IFR2+MS+Sag (1) 696.60 10.44 30.98 694.25 37.71 16.32635.56 6,027,927.54 534,009.91 2.84 -38.75 3_MWD+IFR2+MS+Sag (1) 792.13 13.07 35.33 787.77 53.94 27.02729.08 6,027,943.82 534,020.54 2.90 -55.70 3_MWD+IFR2+MS+Sag (1) 887.52 17.04 38.17 879.86 73.74 41.90821.17 6,027,963.68 534,035.33 4.23 -76.48 3_MWD+IFR2+MS+Sag (1) 982.97 20.35 41.18 970.27 97.23 61.48911.58 6,027,987.26 534,054.80 3.61 -101.28 3_MWD+IFR2+MS+Sag (1) 1,077.80 23.88 45.87 1,058.11 123.02 86.12999.42 6,028,013.16 534,079.32 4.16 -128.73 3_MWD+IFR2+MS+Sag (1) 1,173.29 28.20 48.90 1,143.89 151.32 117.011,085.20 6,028,041.60 534,110.08 4.73 -159.12 3_MWD+IFR2+MS+Sag (1) 1,268.56 34.06 50.41 1,225.41 183.15 154.571,166.72 6,028,073.60 534,147.48 6.20 -193.49 3_MWD+IFR2+MS+Sag (1) 5/28/2020 11:49:15AM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 Actual RKB @ 58.69usft Design:MPU M-45 Database:NORTH US + CANADA MD Reference:MPU M-45 Actual RKB @ 58.69usft North Reference: Well MPU M-45 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,364.15 39.23 49.60 1,302.08 219.82 198.251,243.39 6,028,110.47 534,190.99 5.43 -233.12 3_MWD+IFR2+MS+Sag (1) 1,458.79 37.95 50.28 1,376.05 257.82 243.421,317.36 6,028,148.66 534,235.99 1.42 -274.17 3_MWD+IFR2+MS+Sag (1) 1,553.96 38.75 49.20 1,450.69 295.98 288.481,392.00 6,028,187.03 534,280.86 1.10 -315.38 3_MWD+IFR2+MS+Sag (1) 1,649.47 38.17 50.13 1,525.48 334.43 333.761,466.79 6,028,225.68 534,325.96 0.86 -356.90 3_MWD+IFR2+MS+Sag (1) 1,744.77 37.11 47.85 1,600.95 372.61 377.681,542.26 6,028,264.05 534,369.70 1.84 -398.04 3_MWD+IFR2+MS+Sag (1) 1,839.57 36.40 45.10 1,676.90 411.66 418.811,618.21 6,028,303.29 534,410.65 1.89 -439.87 3_MWD+IFR2+MS+Sag (1) 1,934.63 35.34 44.56 1,753.94 451.16 458.081,695.25 6,028,342.96 534,449.74 1.16 -482.01 3_MWD+IFR2+MS+Sag (1) 2,030.58 33.58 44.89 1,833.05 489.73 496.281,774.36 6,028,381.71 534,487.76 1.84 -523.16 3_MWD+IFR2+MS+Sag (1) 2,126.18 33.79 47.28 1,912.60 526.50 534.471,853.91 6,028,418.64 534,525.77 1.40 -562.50 3_MWD+IFR2+MS+Sag (1) 2,221.08 34.21 48.85 1,991.27 561.96 573.951,932.58 6,028,454.28 534,565.08 1.03 -600.62 3_MWD+IFR2+MS+Sag (1) 2,316.63 34.93 49.40 2,069.95 597.43 614.942,011.26 6,028,489.94 534,605.91 0.82 -638.87 3_MWD+IFR2+MS+Sag (1) 2,409.46 34.11 50.90 2,146.44 631.15 655.322,087.75 6,028,523.83 534,646.14 1.27 -675.32 3_MWD+IFR2+MS+Sag (1) 2,506.16 33.06 55.13 2,227.01 663.33 698.012,168.32 6,028,556.21 534,688.67 2.65 -710.41 3_MWD+IFR2+MS+Sag (1) 2,600.31 32.36 58.89 2,306.23 691.03 740.662,247.54 6,028,584.10 534,731.19 2.28 -741.02 3_MWD+IFR2+MS+Sag (1) 2,697.39 30.94 64.06 2,388.89 715.38 785.352,330.20 6,028,608.65 534,775.77 3.15 -768.42 3_MWD+IFR2+MS+Sag (1) 2,792.69 28.85 70.37 2,471.52 733.83 829.062,412.83 6,028,627.30 534,819.38 3.96 -789.87 3_MWD+IFR2+MS+Sag (1) 2,888.19 29.90 78.98 2,554.78 746.12 874.142,496.09 6,028,639.80 534,864.41 4.55 -805.28 3_MWD+IFR2+MS+Sag (1) 2,982.01 31.12 86.81 2,635.64 751.94 921.322,576.95 6,028,645.83 534,911.56 4.43 -814.38 3_MWD+IFR2+MS+Sag (1) 3,077.49 32.32 95.02 2,716.90 751.08 971.412,658.21 6,028,645.20 534,961.64 4.69 -817.02 3_MWD+IFR2+MS+Sag (1) 3,172.60 33.28 101.82 2,796.87 743.51 1,022.302,738.18 6,028,637.86 535,012.56 4.00 -813.01 3_MWD+IFR2+MS+Sag (1) 3,267.87 34.87 107.86 2,875.80 729.80 1,073.822,817.11 6,028,624.39 535,064.14 3.92 -802.93 3_MWD+IFR2+MS+Sag (1) 3,363.10 36.57 117.66 2,953.18 708.26 1,124.912,894.49 6,028,603.09 535,115.32 6.26 -785.01 3_MWD+IFR2+MS+Sag (1) 3,457.69 40.23 122.18 3,027.31 678.90 1,175.742,968.62 6,028,573.96 535,166.28 4.87 -759.26 3_MWD+IFR2+MS+Sag (1) 3,552.78 42.82 126.83 3,098.51 643.16 1,227.623,039.82 6,028,538.46 535,218.32 4.23 -727.22 3_MWD+IFR2+MS+Sag (1) 3,648.46 44.32 132.38 3,167.86 601.12 1,278.363,109.17 6,028,496.65 535,269.24 4.29 -688.83 3_MWD+IFR2+MS+Sag (1) 3,743.06 47.01 135.06 3,233.97 554.34 1,327.233,175.28 6,028,450.10 535,318.32 3.49 -645.57 3_MWD+IFR2+MS+Sag (1) 3,838.77 48.42 136.51 3,298.37 503.59 1,376.593,239.68 6,028,399.58 535,367.91 1.85 -598.39 3_MWD+IFR2+MS+Sag (1) 3,933.60 48.51 139.94 3,361.26 450.66 1,423.873,302.57 6,028,346.88 535,415.42 2.71 -548.89 3_MWD+IFR2+MS+Sag (1) 4,025.31 51.11 143.90 3,420.45 395.51 1,467.023,361.76 6,028,291.93 535,458.82 4.35 -496.88 3_MWD+IFR2+MS+Sag (1) 4,123.38 54.77 145.70 3,479.54 331.56 1,512.103,420.85 6,028,228.19 535,504.19 4.01 -436.23 3_MWD+IFR2+MS+Sag (1) 4,218.49 58.60 148.63 3,531.78 264.78 1,555.143,473.09 6,028,161.62 535,547.53 4.78 -372.61 3_MWD+IFR2+MS+Sag (1) 4,313.71 62.75 153.24 3,578.43 192.23 1,595.393,519.74 6,028,089.26 535,588.10 6.07 -303.05 3_MWD+IFR2+MS+Sag (1) 4,408.89 65.84 155.83 3,619.71 114.80 1,632.233,561.02 6,028,012.01 535,625.30 4.07 -228.38 3_MWD+IFR2+MS+Sag (1) 4,504.31 70.23 156.84 3,655.39 33.77 1,667.733,596.70 6,027,931.15 535,661.16 4.70 -150.02 3_MWD+IFR2+MS+Sag (1) 4,599.62 74.32 158.81 3,684.41 -50.29 1,701.973,625.72 6,027,847.26 535,695.78 4.72 -68.56 3_MWD+IFR2+MS+Sag (1) 4,695.11 78.91 159.87 3,706.51 -137.19 1,734.733,647.82 6,027,760.52 535,728.94 4.93 15.84 3_MWD+IFR2+MS+Sag (1) 4,790.52 80.63 159.50 3,723.45 -225.24 1,767.333,664.76 6,027,672.63 535,761.93 1.84 101.40 3_MWD+IFR2+MS+Sag (1) 4,885.31 83.75 159.81 3,736.33 -313.28 1,799.973,677.64 6,027,584.74 535,794.98 3.31 186.95 3_MWD+IFR2+MS+Sag (1) 4,980.52 84.60 162.66 3,745.99 -402.95 1,830.443,687.30 6,027,495.22 535,825.85 3.11 274.28 3_MWD+IFR2+MS+Sag (1) 5,076.05 84.38 166.23 3,755.17 -494.54 1,855.933,696.48 6,027,403.75 535,851.76 3.73 363.87 3_MWD+IFR2+MS+Sag (1) 5/28/2020 11:49:15AM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 Actual RKB @ 58.69usft Design:MPU M-45 Database:NORTH US + CANADA MD Reference:MPU M-45 Actual RKB @ 58.69usft North Reference: Well MPU M-45 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 5,171.83 84.09 166.24 3,764.79 -587.10 1,878.613,706.10 6,027,311.31 535,874.85 0.30 454.62 3_MWD+IFR2+MS+Sag (1) 5,267.33 86.06 166.68 3,772.99 -679.60 1,900.883,714.30 6,027,218.92 535,897.55 2.11 545.34 3_MWD+IFR2+MS+Sag (1) 5,296.85 85.52 167.48 3,775.16 -708.29 1,907.463,716.47 6,027,190.26 535,904.26 3.26 573.51 3_MWD+IFR2+MS+Sag (1) 5,375.02 90.92 168.35 3,777.58 -784.66 1,923.813,718.89 6,027,113.97 535,920.96 7.00 648.55 3_MWD+IFR2+MS+Sag (1) 5,444.99 91.99 167.75 3,775.81 -853.10 1,938.303,717.12 6,027,045.62 535,935.75 1.75 715.81 3_MWD+IFR2+MS+Sag (2) 5,539.66 91.86 166.72 3,772.63 -945.37 1,959.203,713.94 6,026,953.45 535,957.08 1.10 806.40 3_MWD+IFR2+MS+Sag (2) 5,634.51 92.10 166.71 3,769.35 -1,037.63 1,980.983,710.66 6,026,861.30 535,979.28 0.25 896.91 3_MWD+IFR2+MS+Sag (2) 5,730.90 92.29 167.04 3,765.66 -1,131.43 2,002.863,706.97 6,026,767.61 536,001.58 0.39 988.96 3_MWD+IFR2+MS+Sag (2) 5,826.02 90.87 167.17 3,763.03 -1,224.11 2,024.083,704.34 6,026,675.03 536,023.22 1.50 1,079.94 3_MWD+IFR2+MS+Sag (2) 5,920.91 90.50 166.76 3,761.90 -1,316.55 2,045.483,703.21 6,026,582.70 536,045.04 0.58 1,170.66 3_MWD+IFR2+MS+Sag (2) 6,016.43 90.56 168.81 3,761.02 -1,409.90 2,065.683,702.33 6,026,489.45 536,065.67 2.15 1,262.37 3_MWD+IFR2+MS+Sag (2) 6,111.51 90.19 168.11 3,760.39 -1,503.06 2,084.703,701.70 6,026,396.40 536,085.12 0.83 1,353.97 3_MWD+IFR2+MS+Sag (2) 6,205.96 90.99 169.67 3,759.42 -1,595.73 2,102.903,700.73 6,026,303.82 536,103.74 1.86 1,445.15 3_MWD+IFR2+MS+Sag (2) 6,301.52 90.00 170.57 3,758.60 -1,689.87 2,119.303,699.91 6,026,209.77 536,120.56 1.40 1,537.91 3_MWD+IFR2+MS+Sag (2) 6,396.71 90.87 174.02 3,757.87 -1,784.18 2,132.063,699.18 6,026,115.52 536,133.75 3.74 1,631.11 3_MWD+IFR2+MS+Sag (2) 6,492.39 90.25 176.37 3,756.94 -1,879.51 2,140.073,698.25 6,026,020.24 536,142.20 2.54 1,725.65 3_MWD+IFR2+MS+Sag (2) 6,587.21 88.46 176.05 3,758.01 -1,974.11 2,146.343,699.32 6,025,925.67 536,148.90 1.92 1,819.58 3_MWD+IFR2+MS+Sag (2) 6,681.82 88.58 178.21 3,760.45 -2,068.57 2,151.073,701.76 6,025,831.25 536,154.06 2.29 1,913.48 3_MWD+IFR2+MS+Sag (2) 6,776.81 89.64 182.53 3,761.93 -2,163.52 2,150.463,703.24 6,025,736.31 536,153.88 4.68 2,008.24 3_MWD+IFR2+MS+Sag (2) 6,871.95 89.76 185.99 3,762.42 -2,258.38 2,143.393,703.73 6,025,641.42 536,147.25 3.64 2,103.36 3_MWD+IFR2+MS+Sag (2) 6,967.49 91.99 189.32 3,760.96 -2,353.04 2,130.673,702.27 6,025,546.72 536,134.96 4.19 2,198.68 3_MWD+IFR2+MS+Sag (2) 7,062.86 91.42 191.25 3,758.13 -2,446.83 2,113.653,699.44 6,025,452.86 536,118.38 2.11 2,293.43 3_MWD+IFR2+MS+Sag (2) 7,157.40 92.29 192.11 3,755.07 -2,539.36 2,094.523,696.38 6,025,360.25 536,099.67 1.29 2,387.07 3_MWD+IFR2+MS+Sag (2) 7,253.41 93.34 193.20 3,750.35 -2,632.92 2,073.523,691.66 6,025,266.60 536,079.09 1.58 2,481.87 3_MWD+IFR2+MS+Sag (2) 7,348.63 92.54 191.91 3,745.47 -2,725.74 2,052.853,686.78 6,025,173.70 536,058.85 1.59 2,575.90 3_MWD+IFR2+MS+Sag (2) 7,444.30 93.83 189.87 3,740.15 -2,819.54 2,034.803,681.46 6,025,079.83 536,041.23 2.52 2,670.73 3_MWD+IFR2+MS+Sag (2) 7,538.99 93.53 186.57 3,734.07 -2,913.05 2,021.293,675.38 6,024,986.27 536,028.16 3.49 2,764.95 3_MWD+IFR2+MS+Sag (2) 7,634.44 92.66 184.01 3,728.92 -3,007.94 2,012.513,670.23 6,024,891.34 536,019.80 2.83 2,860.23 3_MWD+IFR2+MS+Sag (2) 7,729.69 90.99 183.50 3,725.88 -3,102.94 2,006.273,667.19 6,024,796.33 536,014.01 1.83 2,955.43 3_MWD+IFR2+MS+Sag (2) 7,825.69 91.37 183.19 3,723.91 -3,198.75 2,000.673,665.22 6,024,700.50 536,008.84 0.51 3,051.40 3_MWD+IFR2+MS+Sag (2) 7,921.11 90.00 182.14 3,722.77 -3,294.06 1,996.243,664.08 6,024,605.18 536,004.84 1.81 3,146.79 3_MWD+IFR2+MS+Sag (2) 8,016.07 91.98 182.91 3,721.13 -3,388.91 1,992.053,662.44 6,024,510.33 536,001.10 2.24 3,241.69 3_MWD+IFR2+MS+Sag (2) 8,111.34 91.98 183.20 3,717.83 -3,483.99 1,986.983,659.14 6,024,415.24 535,996.46 0.30 3,336.89 3_MWD+IFR2+MS+Sag (2) 8,206.64 93.71 186.52 3,713.10 -3,578.81 1,978.923,654.41 6,024,320.39 535,988.83 3.92 3,432.05 3_MWD+IFR2+MS+Sag (2) 8,301.39 91.86 187.31 3,708.50 -3,672.75 1,967.523,649.81 6,024,226.40 535,977.87 2.12 3,526.56 3_MWD+IFR2+MS+Sag (2) 8,396.43 93.41 188.10 3,704.13 -3,766.83 1,954.803,645.44 6,024,132.27 535,965.57 1.83 3,621.30 3_MWD+IFR2+MS+Sag (2) 8,490.91 94.65 187.59 3,697.49 -3,860.20 1,941.933,638.80 6,024,038.86 535,953.13 1.42 3,715.33 3_MWD+IFR2+MS+Sag (2) 8,587.56 92.97 186.24 3,691.07 -3,955.92 1,930.323,632.38 6,023,943.09 535,941.96 2.23 3,811.64 3_MWD+IFR2+MS+Sag (2) 8,682.87 92.66 185.34 3,686.39 -4,050.63 1,920.723,627.70 6,023,848.35 535,932.79 1.00 3,906.78 3_MWD+IFR2+MS+Sag (2) 8,777.80 91.79 182.05 3,682.70 -4,145.28 1,914.613,624.01 6,023,753.68 535,927.12 3.58 4,001.63 3_MWD+IFR2+MS+Sag (2) 5/28/2020 11:49:15AM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 Actual RKB @ 58.69usft Design:MPU M-45 Database:NORTH US + CANADA MD Reference:MPU M-45 Actual RKB @ 58.69usft North Reference: Well MPU M-45 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,872.30 92.04 180.17 3,679.54 -4,239.71 1,912.783,620.85 6,023,659.26 535,925.72 2.01 4,095.95 3_MWD+IFR2+MS+Sag (2) 8,966.89 91.92 181.73 3,676.27 -4,334.22 1,911.213,617.58 6,023,564.74 535,924.58 1.65 4,190.35 3_MWD+IFR2+MS+Sag (2) 9,061.81 92.85 183.57 3,672.32 -4,428.95 1,906.833,613.63 6,023,470.00 535,920.63 2.17 4,285.15 3_MWD+IFR2+MS+Sag (2) 9,157.47 92.66 184.89 3,667.73 -4,524.24 1,899.783,609.04 6,023,374.70 535,914.02 1.39 4,380.70 3_MWD+IFR2+MS+Sag (2) 9,252.46 93.03 184.89 3,663.01 -4,618.77 1,891.693,604.32 6,023,280.14 535,906.37 0.39 4,475.56 3_MWD+IFR2+MS+Sag (2) 9,348.01 92.47 183.75 3,658.43 -4,713.94 1,884.503,599.74 6,023,184.95 535,899.61 1.33 4,571.00 3_MWD+IFR2+MS+Sag (2) 9,442.67 93.96 183.95 3,653.12 -4,808.23 1,878.163,594.43 6,023,090.64 535,893.70 1.59 4,665.50 3_MWD+IFR2+MS+Sag (2) 9,538.29 92.10 181.94 3,648.06 -4,903.58 1,873.253,589.37 6,022,995.27 535,889.23 2.86 4,760.97 3_MWD+IFR2+MS+Sag (2) 9,631.49 92.72 183.99 3,644.14 -4,996.57 1,868.443,585.45 6,022,902.28 535,884.84 2.30 4,854.06 3_MWD+IFR2+MS+Sag (2) 9,727.02 91.36 185.59 3,640.74 -5,091.70 1,860.473,582.05 6,022,807.12 535,877.31 2.20 4,949.52 3_MWD+IFR2+MS+Sag (2) 9,822.83 90.07 186.49 3,639.55 -5,186.97 1,850.393,580.86 6,022,711.82 535,867.66 1.64 5,045.26 3_MWD+IFR2+MS+Sag (2) 9,917.94 91.74 185.84 3,638.05 -5,281.51 1,840.173,579.36 6,022,617.23 535,857.88 1.88 5,140.28 3_MWD+IFR2+MS+Sag (2) 10,014.61 91.73 182.60 3,635.12 -5,377.86 1,833.063,576.43 6,022,520.86 535,851.21 3.35 5,236.89 3_MWD+IFR2+MS+Sag (2) 10,109.84 92.11 181.80 3,631.93 -5,472.97 1,829.413,573.24 6,022,425.75 535,848.00 0.93 5,332.02 3_MWD+IFR2+MS+Sag (2) 10,205.25 92.54 182.33 3,628.06 -5,568.24 1,825.983,569.37 6,022,330.48 535,845.00 0.71 5,427.30 3_MWD+IFR2+MS+Sag (2) 10,300.27 93.22 183.62 3,623.28 -5,663.01 1,821.053,564.59 6,022,235.69 535,840.50 1.53 5,522.18 3_MWD+IFR2+MS+Sag (2) 10,395.10 94.27 185.80 3,617.09 -5,757.31 1,813.283,558.40 6,022,141.37 535,833.17 2.55 5,616.80 3_MWD+IFR2+MS+Sag (2) 10,490.13 93.83 186.68 3,610.38 -5,851.54 1,802.983,551.69 6,022,047.10 535,823.30 1.03 5,711.51 3_MWD+IFR2+MS+Sag (2) 10,585.62 94.27 185.76 3,603.63 -5,946.23 1,792.663,544.94 6,021,952.37 535,813.41 1.07 5,806.69 3_MWD+IFR2+MS+Sag (2) 10,680.52 94.02 186.04 3,596.77 -6,040.38 1,782.933,538.08 6,021,858.19 535,804.11 0.39 5,901.29 3_MWD+IFR2+MS+Sag (2) 10,775.27 91.61 183.79 3,592.12 -6,134.65 1,774.823,533.43 6,021,763.89 535,796.44 3.48 5,995.90 3_MWD+IFR2+MS+Sag (2) 10,869.98 93.16 184.73 3,588.18 -6,229.01 1,767.803,529.49 6,021,669.50 535,789.84 1.91 6,090.53 3_MWD+IFR2+MS+Sag (2) 10,965.80 92.04 185.20 3,583.83 -6,324.38 1,759.513,525.14 6,021,574.12 535,781.99 1.27 6,186.23 3_MWD+IFR2+MS+Sag (2) 11,061.47 91.73 185.50 3,580.68 -6,419.58 1,750.603,521.99 6,021,478.88 535,773.52 0.45 6,281.82 3_MWD+IFR2+MS+Sag (2) 11,158.65 91.67 185.45 3,577.80 -6,516.27 1,741.333,519.11 6,021,382.16 535,764.69 0.08 6,378.93 3_MWD+IFR2+MS+Sag (2) 11,251.57 92.54 184.42 3,574.39 -6,608.78 1,733.343,515.70 6,021,289.62 535,757.13 1.45 6,471.77 3_MWD+IFR2+MS+Sag (2) 11,347.09 93.46 182.80 3,569.39 -6,703.98 1,727.333,510.70 6,021,194.41 535,751.55 1.95 6,567.15 3_MWD+IFR2+MS+Sag (2) 11,441.89 94.77 182.97 3,562.59 -6,798.41 1,722.573,503.90 6,021,099.96 535,747.23 1.39 6,661.69 3_MWD+IFR2+MS+Sag (2) 11,537.34 93.65 181.75 3,555.58 -6,893.52 1,718.663,496.89 6,021,004.85 535,743.74 1.73 6,756.84 3_MWD+IFR2+MS+Sag (2) 11,632.24 91.24 179.96 3,551.53 -6,988.31 1,717.243,492.84 6,020,910.06 535,742.76 3.16 6,851.50 3_MWD+IFR2+MS+Sag (2) 11,727.81 91.73 177.70 3,549.05 -7,083.82 1,719.193,490.36 6,020,814.57 535,745.15 2.42 6,946.64 3_MWD+IFR2+MS+Sag (2) 11,823.48 92.35 178.81 3,545.65 -7,179.39 1,722.103,486.96 6,020,719.03 535,748.50 1.33 7,041.77 3_MWD+IFR2+MS+Sag (2) 11,918.88 91.86 183.12 3,542.14 -7,274.69 1,720.503,483.45 6,020,623.73 535,747.33 4.54 7,136.95 3_MWD+IFR2+MS+Sag (2) 12,013.66 91.49 185.51 3,539.37 -7,369.15 1,713.373,480.68 6,020,529.25 535,740.63 2.55 7,231.68 3_MWD+IFR2+MS+Sag (2) 12,109.87 91.92 185.72 3,536.51 -7,464.86 1,703.963,477.82 6,020,433.51 535,731.66 0.50 7,327.81 3_MWD+IFR2+MS+Sag (2) 12,123.32 92.17 185.37 3,536.03 -7,478.23 1,702.663,477.34 6,020,420.12 535,730.43 3.20 7,341.25 3_MWD+IFR2+MS+Sag (2) 12,192.00 92.17 185.37 3,533.43 -7,546.56 1,696.243,474.74 6,020,351.77 535,724.32 0.00 7,409.86 PROJECTED to TD Approved By:Checked By:Date: 5/28/2020 11:49:15AM COMPASS 5000.15 Build 91E Page 5 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.02 11:42:58 -08'00' Monty M Myers Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.07.02 11:43:04 -08'00' Monty M Myers TD Shoe Depth: PBTD Jts. 1 2 1 1 1 75 1 1 1 56 1 X Yes No X Yes No 45 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint of Casing 10 3/4 50.0 327.67 0.5326.13SECOND STAGERig 19:05 Returns to surface Rotate Csg Recip Csg Ft. Min. PPG9.4 Shoe @ 5407 FC @ Top of Liner5,325.41 Floats Held 335.46 606 269 337 Spud Mud CASING RECORD County State Alaska Supv.S. Sunderland / C. Demoski Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP M-45 Date Run 21-May-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top TXP BTC-SR Innovex 1.62 5,407.00 5,405.38 19.17 50.74 30.749 5/8 40.0 L-80 TXP BTC-SR Tenaris Csg Wt. On Hook:152,000 Type Float Collar:Innovex No. Hrs to Run:13.5 9.4 6 1350 10 10.7 315 6 78 600 Bump Plug?FIRST STAGE10Tuned Spacer 60 15.8 540 5.25 9.5 5 172/174.19 398.25/400.98 1100 40 Rig 15.8 82 Bump press Circulate to surface Bump Plug? Y 9:20 5/22/2020 2,290 2290.37 5,407.005,414.00 CEMENTING REPORT Csg Wt. On Slips:112,000 Spud Mud Tuned Spacer 400 4.41 Stage Collar @ 60 Bump press 94 314 ES Cementer Closure OK 56 12 153 Type of Shoe:Innovex Casing Crew:Doyon www.wellez.net WellEz Information Management LLC ver_04818br 4.5 Permafrost Lead Type Two 9-5/8" x 12-1/4" centralizer & 4 stop rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints. Install 9-5/8" x 12-1/4" bowspring centralizers on joints #5-25 then every other joint to #53. Centralizers installed on joints #74-83 then every other joint to #131. Total of 135 joints of casing, 76 9-5/8" x 12-1/4" Expand-O-Lizer centralizers and 10 stop rings ran. Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 78.67 5,405.38 5,326.71 Float Collar 10 3/4 50.0 TXP BTC-SR Innovex 1.30 5,326.71 5,325.41 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 39.98 5,325.41 5,285.43 Baffle Adapter 10 3/4 50.0 TXP BTC-SR HES 1.48 5,285.43 5,283.95 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 2,972.91 5,283.95 2,311.04 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 16.94 2,311.04 2,294.10 ES Cementer 10 3/4 TXP BTC-SR HES 3.73 2,294.10 2,290.37 Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 17.17 2,290.37 2,273.20 Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 2,222.46 2,273.20 50.74 Lead Cement 365 2.35 Tail Cement 400 1.16 3.5 Tail Cement 270 1.17 5/22/2020 38 Spud Mud Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/02/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-45 (220-044) Halliburton LWD FINAL 18 MAY 2020 MPU M-45 Received by the AOGCC 07/03/2020 PTD: 2200440 E-Set: 33471 Abby Bell 07/06/2020 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-45 Hilcorp Alaska, LLC Permit to Drill Number: 220-044 Surface Location: 5037’ FSL, 171’ FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 574’ FSL, 1320’ FWL, SEC. 24, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of May, 2020. y JMPi 14 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 14,338' TVD: 3,509' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 58.6' 15. Distance to Nearest Well Open Surface: x-533993 y- 6027889 Zone-4 24.9' to Same Pool: 875' to MPU M-44 16. Deviated wells:Kickoff depth: 280 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92.7 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 20" - X52 Weld 113' Surface Surface 113' 113' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 9,276' 5,062' 3,730' 14,338' 3,509' Tieback 7" 26# L-80 TXP 5,062' Surface Surface 5,062' 3,730' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 5/16/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Joe Engel jengel@hilcorp.com 777-8395 18. Casing Program:Top - Setting Depth - BottomSpecifications MPU M-45 Milne Point Unit Schrader Bluff Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 5037' FSL, 171' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL355023, ADL388235 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1311 993' FNL, 1751' FWL, Sec 13, T13N, R9E, UM, AK 574' FSL, 1320' FWL, Sec 24, T13N, R9E, UM, AK LONS 16-004 7735 574' to nearest unit boundary 1662 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): Conductor/Structural LengthCasing Intermediate Effect. Depth MD (ft): Authorized Signature: Production Liner Commission Use Only Surface Surface 5,212' See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ~270 ft3 Stg 1 - L - 698 ft3 / T - 458 ft3 3,744'12-1/4"9-5/8"40#Stg 2 - L - 1937 ft3 / T - 314 ft3L-80 TXP 5,212' Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 5/5/2020 Cementless Screen Liner Tieback es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Cody Dinger DN: cn=Cody Dinger, ou=Users Date: 2020.05.05 14:05:50 - 08'00' Cody Dinger By Samantha Carlisle at 3:27 pm, May 05, 2020 X 029-23676-00-00 X X X 220-044 DSR-5/6/2020 X X DLB 05/06/2020 X+ 3000 psi BOPE test + 2500 psi Annular test gls 5/14/200 5/14/2020 05/14/2020 Milne Point Unit (MPU) M-45 Drilling Program Version 1 5/4/2020 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 RU and Preparatory Work ...................................................................................................... 10 10.0 NU 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 ND Diverter, NU BOPE, & Test .............................................................................................. 26 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 27 16.0 Run 4-1/2” Screen Liner .......................................................................................................... 32 17.0 Run 7” Tieback ........................................................................................................................ 36 18.0 Run Upper Completion............................................................................................................ 39 19.0 Doyon 14 Diverter Schematic .................................................................................................. 41 20.0 Doyon 14 BOP Schematic ........................................................................................................ 42 21.0 Wellhead Schematic ................................................................................................................. 43 22.0 Days Vs Depth .......................................................................................................................... 44 23.0 Formation Tops & Information............................................................................................... 45 24.0 Anticipated Drilling Hazards .................................................................................................. 46 25.0 Doyon 14 Layout ...................................................................................................................... 49 26.0 FIT Procedure .......................................................................................................................... 50 27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 51 28.0 Casing Design ........................................................................................................................... 52 29.0 8-1/2” Hole Section MASP ....................................................................................................... 53 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 54 31.0 Surface Plat (As Staked) (NAD 27) ......................................................................................... 55 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart ............................................................... 56 Doyon 14 Page 2 Milne Point Unit M-45 SB Producer Drilling Procedure 1.0 Well Summary Well MPU M-45 Pad Milne Point “M” Pad Planned Completion Type Jet Pump on 4-1/2 tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 14,337’ MD / 3,508’ TVD PBTD, MD / TVD 14,327’ MD / 3,508’ TVD Surface Location (Governmental) 5037' FSL, 171' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533993, Y= 6027889 Top of Productive Horizon (Governmental) 993' FNL, 1751' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 535919 Y= 6027147 BHL (Governmental) 574' FSL, 1320' FWL, Sec 24, T13N, R9E, UM, AK BHL (NAD 27) X= 535535, Y= 6018154 AFE Number 2011202 AFE Drilling Days 20 AFE Completion Days 4 AFE Drilling Amount $3,440,187 AFE Completion Amount $2,340,699 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1,311 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,662 psig Work String 5” 19.5# S-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 24.9 ft = 58.6 ft GL Elevation above MSL: 24.9 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams 1,311 psig 1,662 psig Page 3 Milne Point Unit M-45 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit M-45 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40.0 L-80 TXP 5,750 3,090 916 Tieback 7” 6.276” 6.151” 7.656 26.0 L-80 TXP 7,240 5,410 604 8-1/2” 4-1/2” Screens 3.920 3.795 4.714 13.5 L-80 Hydril 625 9,020 8,540 279 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5” 4.276” 3.250” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5” 4.276” 3.250” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit M-45 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 6 Milne Point Unit M-45 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic MIT 3500 psi MIT 1000 psi Reverse Jet pump Page 7 Milne Point Unit M-45 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU M-45 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff NB/NC sand. M-45 is part of a multi well program targeting the Schrader Bluff sand on M-Pad. The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff NB sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” screen liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore Drilling operations are expected to commence approximately May 16, 2020, pending rig schedule. Surface casing will be run to 5,212’ MD / 3,743’ 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. NU & 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. ND diverter, NU wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD. 6. Run 6-5/8” production liner 7. Run 7” tieback 8. Run Upper Completion 9. ND BOP, NU Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit M-45 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-45. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. Page 9 Milne Point Unit M-45 SB Producer Drilling Procedure Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only For Reference x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc N/A N/A Primary closing unit: NL Shaffer, 6 station, 3,000 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: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit M-45 SB Producer Drilling Procedure 9.0 RU and Preparatory Work 9.1 M-45 will utiliz e 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 RU. 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 (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4,665 psi, 462 GPM @ 110 SPM @ 95% volumetric efficiency. Page 11 Milne Point Unit M-45 SB Producer Drilling Procedure 10.0 NU 21-1/4” 2M Diverter System 10.1 NU 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x NU 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x NU 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 feet from nearest ignition source x 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit M-45 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit M-45 SB Producer Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD, in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6°/ 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 ppg minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates have not been seen on M-Pad. However, be prepared for them. In MPU they have been encountered typically around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates: Page 14 Milne Point Unit M-45 SB Producer Drilling Procedure x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit M-45 SB Producer Drilling Procedure System Type: 8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 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 to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 ft/minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. 8.8 – 9.8– y Page 16 Milne Point Unit M-45 SB Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit M-45 SB Producer Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: 2500 ' Page 18 Milne Point Unit M-45 SB Producer Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: x 1 centralizer every joint to ~1,000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to 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). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3,300 psi. x ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at ~ 2,080 psi, and the tool to open at ~ 3,000 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 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD belowyp the permafrost (~ 2,500’ MD). Page 19 Milne Point Unit M-45 SB Producer Drilling Procedure Page 20 Milne Point Unit M-45 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: x 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 PU landing joint and MU to casing string. Position the casing shoe ±10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 21 Milne Point Unit M-45 SB Producer Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 RU 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: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (4,212' - 2,500') x .0558 bpf x 1.3 = 124.2 697.3 Total Lead 124.2 697.3 12-1/4" OH x 9-5/8" Casing (5,212' - 4,212') x .0558 bpf x 1.3 = 72.5 407 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458LeadTail Estimated 1st Stage Total Cement Volume: 394 296 sx sx Page 22 Milne Point Unit M-45 SB Producer Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 BPS (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,092’ x .0758 BPF = 386 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk Page 23 Milne Point Unit M-45 SB Producer Drilling Procedure 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2 nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Increase pressure to 3,300 psi to open circulating ports in stage collar. Page 24 Milne Point Unit M-45 SB Producer Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls of 10.5 ppg tuned spacer. 13.22 Mix and pump cement per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 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 314LeadTail Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Estimated 2nd Stage Total Cement Volume: Section 439 sx 270 sx Page 25 Milne Point Unit M-45 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2,500’ 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 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. LD cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration 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 jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Make final cut on 9-5/8”. Dress To ES tool p 2,500’ x .0758 BPF = 190 bbls mud drop ES Cementer closing plug Page 26 Milne Point Unit M-45 SB Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity, blind ram in bottom cavity. x Single ram can be dressed with 4-1/2” x 7” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment. 14.4 Run 5” BOP test plug. 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg FloPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6” liners in mud pumps. Initial BOPE test Page 27 Milne Point Unit M-45 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM). x Decision may be made to drill out with RSS. If so MU RSS BHA 15.2 TIH with 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 RU and PT casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD Cleanout BHA. 15.9 PU 8-1/2” directional BHA. x 8-1/2” Bit Jetting: 6each 14/32nds x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. PT casing Conduct FIT to 12.0 ppg EMW. FIT 12 PPG RU and PT casing to 2,500 psi for 30 minutes charted. Page 28 Milne Point Unit M-45 SB Producer Drilling Procedure x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8-1/2” (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (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 8.9-9.5 Page 29 Milne Point Unit M-45 SB Producer Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom. 15.12 Install MPD RCD. 15.13 Displace wellbore to 8.9 ppg Flo Pro drilling fluid 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to stay in NB/NC sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff Concretions: 5-10% of lateral x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x M-08DSW wp02 has a CF of .8, this is a planned future water source well and does not exist. Its well path will be adjusted when it is drilled to avoid existing wells. 15.15 Reference: Open hole sidetracking practice: x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 30 Milne Point Unit M-45 SB Producer Drilling Procedure x Orient TF to low side and dig a trough with high flowrates for the first 10 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum x Decision may be made to leave mud in the lateral and BROOH. This is TBD based upon hole conditions and M-44 results. 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 Monitor the returned fluids carefully while displacing to brine. After 4 (or more) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). x Rotate at maximum rpm that can be sustained. Page 31 Milne Point Unit M-45 SB Producer Drilling Procedure x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions. x If back reaming operations are commenced, continue back reaming to the shoe 15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.23 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid weight if necessary x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.24 POOH and LD BHA. 15.25 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. 15.26 Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 32 Milne Point Unit M-45 SB Producer Drilling Procedure 16.0 Run 4-1/2” Screen Liner 16.1 Confirm VBR’s have been tested on 4-1/2” and 5” test joints to 250/3,000 psi. 16.2 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” production screens, the following well control response procedure will be followed: x PU & MU the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4-1/2” screen. x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW valve. x Proceed with well kill operations. 16.3 If an inner string is ran, 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” production screens: x PU & MU 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). MU 2-3/8” and then 4-1/2” to triple connect. x This joint shall be fully MU with crossovers prior to running the first joint of wash pipe. x 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 RU 4-1/2” screen running equipment. x Ensure 4-1/2” x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components w/ vendor & model info. 16.5 Run 4-1/2” screen production liner – Reference screen handling and running procedure. x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound will plug the screens. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run packoff and float shoe on bottom. x 4-1/2” Screens should auto –fill, top off with completion brine if needed x Swell packers will not be required on this completion unless the well is drilled out of zone x If needed, install swell packers as per the lower completion tally. x Remove protective packaging on swell packers just prior to picking up x Do not place tongs or slips on the packer element 4-1/2”, 13.5 #, L-80, Hydril 625 Torque OD Minimum Optimum Operating Torque Confirm VBR’s have been tested on 4-1/2” and 5” test joints to 250/3,000 psi. p ” triple connect crossover Page 33 Milne Point Unit M-45 SB Producer Drilling Procedure 4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 34 Milne Point Unit M-45 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/packer will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. MU Baker SLZXP liner top packer to 4-1/2” liner. 16.9. Inner string may or not be ran, depending on out of zone excursion and condition of lateral. Have 2-3/8” inner string available if needed. 16.10. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH with liner on ALL 5” HWDP no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 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. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. Page 35 Milne Point Unit M-45 SB Producer Drilling Procedure 16.18. 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. 16.19. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.20. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.21. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.23. 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. 16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.25. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. 16.26. MU 3-1/2” wash tool and RIH with remaining DP out of derrick to liner top. 16.27. Wash through liner top at max rate and circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.28. POOH and LD remaining 5” HWDP Page 36 Milne Point Unit M-45 SB Producer Drilling Procedure 17.0 Run 7” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. 17.2 Confirm 4-1/2” x 7” VBRs have been tested with 7” test joint to 250/3,000 psi. 17.3 RU 7” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.4 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7” annulus. 17.5 M/U first joint of 7” to seal assembly. 17.6 Run 7”, 26#, L-80, TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7” 26# TXP MU Torque OD Minimum Optimum Maximum Yield Torque 7” 13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 23,400 ft-lbs Confirm 4-1/2” x 7” VBRs have been tested with 7” test joint to 250/3,000 psi. Page 37 Milne Point Unit M-45 SB Producer Drilling Procedure Page 38 Milne Point Unit M-45 SB Producer Drilling Procedure 17.7 MU 7” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7” joints. 17.13 Space out with pups as needed to leave the no-go 1ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.14 PU and MU the the 7” casing hanger with landing joint. 17.15 Ensure circulation is possible through 7” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.17 With seals stabbed into the tieback sleeve, spot diesel freeze protection from ~2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of the 7” tieback assembly). 17.18 SO and land hanger. Confirm the hanger has seated properly in the wellhead. Make note of actual weight on the hanger in the morning report. 17.19 Back out landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set tubing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 R/D casing running tools. 17.21 PT 9-5/8” x 7” annulus to 1,000 psi for 30 minutes charted. PT 9-5/8” x 7” annulus to 1,000 psi for 30 minutes charted. Page 39 Milne Point Unit M-45 SB Producer Drilling Procedure 18.0 Run Upper Completion 18.1 Confirm VBR’s have been tested on 4-1/2” and 5” test joints to 250/3,000 psi. 18.2 RU to run 4-1/2” completion. Verify the jet pump completion components and depths with Ops Engineer. 18.3 PU, MU and RIH with the following 4-1/2” jet pump completion: a. WLEG b. XX joints, 4-1/2”, 12.6#, L-80, TXP tubing c. 3.813” XN nipple (no-go ID = 3.725”) with RHC plug body installed, 10’ handling pups above and below. d. 1 joint, 4-1/2”, 12.6#, L-80, TXP tubing e. Retrievable Packer, 7” x 4-1/2” f. 1 joint, 4-1/2”, 12.6#, L-80, TXP tubing g. 3.813” X nipple, 10’ handling pups above and below h. 4-1/2” Multi-Drop Gauge Mandrel with gauge installed i. Sliding Sleeve with 3.813” X nipple j. 4-1/2” Gauge Mandrel with gauge installed k. XX joints, 4-1/2”, 12.6#, L-80, TXP tubing 18.4 Continue to RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.5 PU and MU the tubing hanger with blast pup joint and landing joint. Terminate the TEC wire. 18.6 Record PU and SO weights before landing hanger on the tally along with band/clamp summary. 18.7 Land tubing hanger and RILDS. 18.8 LD landing joint. 18.9 Install BPV. ND BOP. Install the plug off tool into the BPV. 18.10 NU the tubing head adapter and tree. Test tubing hanger void to 500/5,000 psi. Terminate the cap strings. 18.11 PT the tree to 250/5,000 psi tree. Pull the plug off tool and BPV. 18.12 RU LRS. Reverse circulate 80 bbls of diesel (actual volume determined by base of the permafrost) down the IA taking returns up the tubing. Place the tubing and IA in communication. Allow time for the diesel to u-tube and equalize. JET PUMP COMPLETION Page 40 Milne Point Unit M-45 SB Producer Drilling Procedure 18.13 Close the master valve and set the ball & rod on top. RU the lubricator, open the master valve to drop the ball & rod and close the master valve. RD the lubricator. RU to set the packer and to PT. 18.14 Slowly pressure up to 3,500 psi to set the packer. 18.15 PT the 4-1/2” tubing to 3,500 psi for 30 minutes charted. 18.16 Bleed tubing to 2,000 psi. 18.17 PT the IA to 3,500 psi for 30 minutes charted testing the packer and 7” casing. 18.18 RD testing equipment. 18.19 Install all tree gauges. Secure the tree and cellar. Releease the rig. 18.20 RDMO Doyon 14. 18.21 Turn the well over to operations via handover form. 18.22 RU HES slickline. a. Open the sliding sleeve by shifting the sleeve down into the open position. b. Pull the ball & rod from RHC plug body. c. Pull the RHC plug body from XN nipple. d. Set 12C jet pump in the sliding sleeve (verify jet pump size with Production Engineer). 18.23 RD HES slickline. 18.24 Prepare to hand over well to production. Ensure necessary forms filled out and well handedover with valve alignment as per operations personnel. 18.25 Notify AOGCC of SVS testing. Test SVS on horizontal run of tree within 5 days of the start of production. Set low pressure trip below 275 psi Moose Pad header & separator pressure. MIT-IA PT the IA to 3,500 psi for 30 minutes charted testing the packer and 7” casing . Notify AOGCC of SVS testing. Test SVS on horizontal run of tree within 5 days of the start of yg y production. Set low pressure trip below 275 psi Moose Pad header & separator pressure. PT the 4-1/2” tubing to 3,500 psi for 30 minutes charted.MIT-T Page 41 Milne Point Unit M-45 SB Producer Drilling Procedure 19.0 Doyon 14 Diverter Schematic Page 42 Milne Point Unit M-45 SB Producer Drilling Procedure 20.0 Doyon 14 BOP Schematic Page 43 Milne Point Unit M-45 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 44 Milne Point Unit M-45 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 45 Milne Point Unit M-45 SB Producer Drilling Procedure 23.0 Formation Tops & Information L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) Page 46 Milne Point Unit M-45 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas 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: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific: x There are no wells with a clearance factor <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. 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 47 Milne Point Unit M-45 SB Producer Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 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 48 Milne Point Unit M-45 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific: x M-08DSW wp02 has a CF of .8, this is a planned future water source well and does not exist. Its well path will be adjusted when it is drilled to avoid existing wells. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitoryy, y y y drilling parameters for signs of magnetic interference with another well. Reference A/C report ingp g directional plan. Well Specific: x p M-08DSW wp02 has a CF of .8, this is a planned future water source well and does notp,p exist. Its well path will be adjusted when it is drilled to avoid existing wells. Page 49 Milne Point Unit M-45 SB Producer Drilling Procedure 25.0 Doyon 14 Layout Page 50 Milne Point Unit M-45 SB Producer Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 51 Milne Point Unit M-45 SB Producer Drilling Procedure 27.0 Doyon 14 Choke Manifold Schematic Page 52 Milne Point Unit M-45 SB Producer Drilling Procedure 28.0 Casing Design 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1311 psi (see attached MASP determination & calculation) 1311 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 1234 9-5/8"4-1/2" 05,212 03,744 5,212 14,337 3,744 3,508 5,212 9,125 40 12.6 L-80 L-80 DWC H625 208,480 114,975 208,480 114,975 916 279 4.39 2.43 1,850 1,733 3,090 8,540 1.67 4.93 1,311 1,311 5,750 9,020 4.39 6.88 Design Criteria: Hole Size Grade Connection Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: Drilling Mode MASP: Hole Size DATE: 5.5.2020 WELL: MPU M-45 DESIGN BY: Joe Engel Hole Size Casing Section Collapse Resistance w/o tension (Psi) Worst case safety factor (Burst) MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Top (TVD) Tension at Top of Section (lbs) Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) 4.39 2.43 1,850 1,733 4.39 6.8 1.67 4.93 Page 53 Milne Point Unit M-45 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP MD TVD Planned Top: 5212 3744 Planned TD: 14337 3508 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 3,777 3,735 1662 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date MPU L-52 8.8-9.35 Surface 3952 2017 MPU L-51 8.9-9.3 Surface 3930 2017 MPU L-53 9-9.25 Surface 3891 2017 MPU J-27 9-9.3 Surface 3666 2015 MPU J-28 9-9.3 Surface 3617 2015 MPI - 19 9 - 9.3 ppg Surface 4,079 2004 MPI - 18 9 - 10 ppg Surface 3,848 2011 MPI - 17 9 - 9.5 ppg Surface 3,864 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 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: 3744 (ft) x 0.78(psi/ft)= 2920 2920(psi) - [0.1(psi/ft)*3744(ft)]= 2546 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3744 (ft) x 0.45(psi/ft)= 1685.0 psi 1685(psi) - 0.1(psi/ft)*3744(ft) 1311.0 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section MPU M-45 Milne Point Unit See P. 45 EMW=8.46 ppg DLB EMW=8.46 ppg, at least 0.5 ppg overbalance. DLB Page 54 Milne Point Unit M-45 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 55 Milne Point Unit M-45 SB Producer Drilling Procedure 31.0 Surface Plat (As Staked) (NAD 27) Page 56 Milne Point Unit M-45 SB Producer Drilling Procedure 32.0 Schrader Bluff Nb Sand Offset MW vs TVD Chart 30 April, 2020 Plan: MPU M-45 wp05 Milne Point M Pt Moose Pad Plan: MPU M-45 MPU M-45 -750075015002250300037504500True Vertical Depth (1500 usft/in)-3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250Vertical Section at 184.00° (1500 usft/in)M-45 wp04 HeelM-45 wp04 CP1M-45 wp04 CP2M-45 wp04 CP3M-45 wp04 CP4M-45 wp04 toe9 5/8" x 12 1/4"6 5/8" x 8 1/2"5001000150020002500300035004000450050005500 6000 65 00 700 0 7500 80 00 8500 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 11 0 0 0 11 5 0 0 1 2 0 0 0 1250 0 130 00 1350 01400014338MPU M-45 wp05Start Dir 3º/100' : 280' MD, 280'TVDStart Dir 4º/100' : 550' MD, 549.1'TVDEnd Dir : 1247.23' MD, 1194.91' TVDStartDir4º/100':2403.42'MD,2149.65'TVDEndDir:4911.91'MD,3717.45'TVDStartDir4º/100':5211.91'MD,3743.6'TVDEndDir:5345.82'MD,3749.57'TVDStartDir3º/100':5841.57'MD,3750.5'TVDEndDir:6401.82'MD,3739.29'TVDStartDir3º/100':8798.44'MD,3658.6'TVDEndDir:8828.42'MD,3657.38'TVDStartDir3º/100':11694.16'MD,3520.77'TVDEndDir:11895.4'MD, 3521.78'TVDStartDir3º/100':12135.74'MD,3535.63'TVDEndDir:12276.07'MD,3538.69'TVDTotalDepth:14337.79'MD,3508.6'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU M-4524.90+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006027889.76533993.77 70° 29' 13.996 N 149° 43' 19.751 WSURVEY PROGRAMDate: 2018-12-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.50 700.00 MPU M-45 wp05 (MPU M-45) 3_Gyro-GC_Csg700.00 5211.91 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+Sag5211.91 14337.79 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-45, True NorthVertical (TVD) Reference:MPU M-45 as-built RKB @ 58.60usftMeasured Depth Reference:MPU M-45 as-built RKB @ 58.60usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Moose PadWell:Plan: MPU M-45Wellbore:MPU M-45Design:MPU M-45 wp05CASING DETAILSTVD TVDSS MD SizeName3743.60 3685.00 5211.91 9-5/8 9 5/8" x 12 1/4"3508.60 3450.00 14337.79 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.50 0.00 0.00 33.50 0.00 0.00 0.00 0.00 0.002 280.00 0.00 0.00 280.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD3 550.00 8.10 15.00 549.10 18.40 4.93 3.00 15.00 -18.70 Start Dir 4º/100' : 550' MD, 549.1'TVD4 1247.23 34.33 48.42 1194.91 199.96 167.95 4.00 41.61 -211.18 End Dir : 1247.23' MD, 1194.91' TVD5 2403.42 34.33 48.42 2149.65 632.79 655.73 0.00 0.00 -676.99 Start Dir 4º/100' : 2403.42' MD, 2149.65'TVD6 4911.91 85.00 165.00 3717.45 -376.84 1823.05 4.00 115.10 248.76 End Dir : 4911.91' MD, 3717.45' TVD7 5211.91 85.00 165.00 3743.60 -665.52 1900.40 0.00 0.00 531.33 M-45 wp04 Heel Start Dir 4º/100' : 5211.91' MD, 3743.6'TVD8 5345.82 89.89 167.19 3749.57 -795.33 1932.53 4.00 24.11 658.59 End Dir : 5345.82' MD, 3749.57' TVD9 5841.57 89.89 167.19 3750.50 -1278.72 2042.49 0.00 0.00 1133.13 Start Dir 3º/100' : 5841.57' MD, 3750.5'TVD10 6274.02 91.93 180.00 3743.60 -1707.50 2090.65 3.00 80.90 1557.51 M-45 wp04 CP111 6401.82 91.93 183.84 3739.29 -1835.13 2086.38 3.00 89.94 1685.12 End Dir : 6401.82' MD, 3739.29' TVD12 8798.44 91.93 183.84 3658.60 -4225.02 1926.13 0.00 0.00 4080.37 M-45 wp04 CP2 Start Dir 3º/100' : 8798.44' MD, 3658.6'TVD13 8828.42 92.73 184.24 3657.38 -4254.91 1924.02 3.00 26.82 4110.33 End Dir : 8828.42' MD, 3657.38' TVD14 11694.16 92.73 184.24 3520.77 -7109.54 1712.26 0.00 0.00 6972.78 Start Dir 3º/100' : 11694.16' MD, 3520.77'TVD15 11785.24 90.00 184.27 3518.60 -7200.34 1705.51 3.00 179.42 7063.83 M-45 wp04 CP316 11895.40 86.70 184.21 3521.78 -7310.14 1697.37 3.00 -178.99 7173.93 End Dir : 11895.4' MD, 3521.78' TVD17 12135.74 86.70 184.21 3535.63 -7549.43 1679.74 0.00 0.00 7413.87 Start Dir 3º/100' : 12135.74' MD, 3535.63'TVD18 12214.85 89.00 184.78 3538.60 -7628.24 1673.55 3.00 13.86 7492.92 M-45 wp04 CP419 12276.07 90.84 184.75 3538.69 -7689.24 1668.46 3.00 -1.03 7554.13 End Dir : 12276.07' MD, 3538.69' TVD20 14337.79 90.84 184.75 3508.60 -9743.67 1497.86 0.00 0.00 9615.45 M-45 wp04 toe Total Depth : 14337.79' MD, 3508.6' TVD -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West(-)/East(+) (1500 usft/in) M-45 wp04 toe M-45 wp04 CP4 M-45 wp04 CP3 M-45 wp04 CP2 M-45 wp04 CP1 M-45 wp04 Heel MPU 500' Buffer 9 5/8" x 12 1/4" 6 5/8" x 8 1/2" 1 2 5 0 1 7 5 0 25003000325035003 7 5 0 3509 MPU M-45 wp05 Start Dir 3º/100' : 280' MD, 280'TVD Start Dir 4º/100' : 550' MD, 549.1'TVD End Dir : 1247.23' MD, 1194.91' TVD End Dir : 4911.91' MD, 3717.45' TVD Start Dir 4º/100' : 5211.91' MD, 3743.6'TVD Start Dir 3º/100' : 5841.57' MD, 3750.5'TVD End Dir : 6401.82' MD, 3739.29' TVD Start Dir 3º/100' : 8798.44' MD, 3658.6'TVD End Dir : 8828.42' MD, 3657.38' TVD Start Dir 3º/100' : 11694.16' MD, 3520.77'TVDStart Dir 3º/100' : 12135.74' MD, 3535.63'TVD End Dir : 12276.07' MD, 3538.69' TVD Total Depth : 14337.79' MD, 3508.6' TVD CASING DETAILS TVD TVDSS MD Size Name 3743.60 3685.00 5211.91 9-5/8 9 5/8" x 12 1/4" 3508.60 3450.00 14337.79 6-5/8 6 5/8" x 8 1/2" Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-45 Wellbore: MPU M-45 Plan: MPU M-45 wp05 WELL DETAILS: Plan: MPU M-45 24.90+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 6027889.76 533993.77 70° 29' 13.996 N 149° 43' 19.751 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU M-45, True North Vertical (TVD) Reference:MPU M-45 as-built RKB @ 58.60usft Measured Depth Reference:MPU M-45 as-built RKB @ 58.60usft Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt Moose Pad usft Map usft usft °0.26Slot Radius:"13-3/16 6,027,877.65 533,363.92 5.00 70° 29' 13.905 N 149° 43' 38.286 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU M-45, Slot 48 usft usft 0.00 0.00 6,027,889.76 533,993.77 24.90Wellhead Elevation:25.10 usft0.50 70° 29' 13.996 N 149° 43' 19.751 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-45 Model NameMagnetics BGGM2019 5/18/2020 16.01 80.89 57,384.27303409 Phase:Version: Audit Notes: Design MPU M-45 wp05 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:33.50 184.000.000.0033.50 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0033.500.000.0033.50 -25.10 0.000.000.000.000.000.00280.000.000.00280.00 221.40 15.000.003.003.004.9318.40549.1015.008.10550.00 490.50 41.614.793.764.00167.95199.961,194.9148.4234.331,247.23 1,136.31 0.000.000.000.00655.73632.792,149.6548.4234.332,403.42 2,091.05 115.104.652.024.001,823.05-376.843,717.45165.0085.004,911.91 3,658.85 0.000.000.000.001,900.40-665.523,743.60165.0085.005,211.91 3,685.00 24.111.633.654.001,932.53-795.333,749.57167.1989.895,345.82 3,690.97 0.000.000.000.002,042.49-1,278.723,750.50167.1989.895,841.57 3,691.90 80.902.960.473.002,090.65-1,707.503,743.60180.0091.936,274.02 3,685.00 89.943.000.003.002,086.38-1,835.133,739.29183.8491.936,401.82 3,680.69 0.000.000.000.001,926.13-4,225.023,658.60183.8491.938,798.44 3,600.00 26.821.352.683.001,924.02-4,254.913,657.38184.2492.738,828.42 3,598.78 0.000.000.000.001,712.26-7,109.543,520.77184.2492.7311,694.16 3,462.17 179.420.03-3.003.001,705.51-7,200.343,518.60184.2790.0011,785.24 3,460.00 -178.99-0.05-3.003.001,697.37-7,310.143,521.78184.2186.7011,895.40 3,463.18 0.000.000.000.001,679.74-7,549.433,535.63184.2186.7012,135.74 3,477.03 13.860.722.913.001,673.55-7,628.243,538.60184.7889.0012,214.85 3,480.00 -1.03-0.053.003.001,668.46-7,689.243,538.69184.7590.8412,276.07 3,480.09 0.000.000.000.001,497.86-9,743.673,508.60184.7590.8414,337.79 3,450.00 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -25.10 Vert Section 33.50 0.00 33.50 0.00 0.000.00 533,993.776,027,889.76-25.10 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 533,993.776,027,889.7641.40 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 533,993.776,027,889.76141.40 0.00 0.00 280.00 0.00 280.00 0.00 0.000.00 533,993.776,027,889.76221.40 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 300.00 0.60 300.00 0.10 0.0315.00 533,993.806,027,889.86241.40 3.00 -0.10 400.00 3.60 399.92 3.64 0.9815.00 533,994.736,027,893.40341.32 3.00 -3.70 500.00 6.60 499.51 12.23 3.2815.00 533,996.996,027,902.00440.91 3.00 -12.42 550.00 8.10 549.10 18.40 4.9315.00 533,998.626,027,908.18490.50 3.00 -18.70 Start Dir 4º/100' : 550' MD, 549.1'TVD 600.00 9.69 598.50 25.68 7.4822.92 534,001.136,027,915.47539.90 4.00 -26.14 700.00 13.20 696.51 43.04 16.9332.70 534,010.506,027,932.88637.91 4.00 -44.12 800.00 16.92 793.06 64.08 32.1338.33 534,025.606,027,953.98734.46 4.00 -66.16 900.00 20.75 887.69 88.68 53.0141.96 534,046.376,027,978.67829.09 4.00 -92.16 1,000.00 24.63 979.93 116.72 79.4744.50 534,072.706,028,006.84921.33 4.00 -121.98 1,100.00 28.54 1,069.34 148.08 111.3846.37 534,104.466,028,038.341,010.74 4.00 -155.49 1,200.00 32.47 1,155.49 182.60 148.5947.83 534,141.516,028,073.021,096.89 4.00 -192.52 1,247.23 34.33 1,194.91 199.96 167.9548.42 534,160.796,028,090.461,136.31 4.00 -211.18 End Dir : 1247.23' MD, 1194.91' TVD 1,300.00 34.33 1,238.49 219.71 190.2148.42 534,182.966,028,110.321,179.89 0.00 -232.44 1,400.00 34.33 1,321.06 257.15 232.4048.42 534,224.976,028,147.941,262.46 0.00 -272.73 1,500.00 34.33 1,403.64 294.58 274.5948.42 534,266.986,028,185.571,345.04 0.00 -313.02 1,600.00 34.33 1,486.21 332.02 316.7848.42 534,308.996,028,223.191,427.61 0.00 -353.31 1,700.00 34.33 1,568.79 369.45 358.9648.42 534,351.016,028,260.811,510.19 0.00 -393.59 1,800.00 34.33 1,651.37 406.89 401.1548.42 534,393.026,028,298.441,592.77 0.00 -433.88 1,900.00 34.33 1,733.94 444.33 443.3448.42 534,435.036,028,336.061,675.34 0.00 -474.17 2,000.00 34.33 1,816.52 481.76 485.5348.42 534,477.046,028,373.691,757.92 0.00 -514.46 2,100.00 34.33 1,899.09 519.20 527.7248.42 534,519.066,028,411.311,840.49 0.00 -554.74 2,200.00 34.33 1,981.67 556.63 569.9048.42 534,561.076,028,448.941,923.07 0.00 -595.03 2,300.00 34.33 2,064.24 594.07 612.0948.42 534,603.086,028,486.562,005.64 0.00 -635.32 2,403.42 34.33 2,149.64 632.78 655.7248.42 534,646.536,028,525.472,091.04 0.00 -676.98 Start Dir 4º/100' : 2403.42' MD, 2149.65'TVD 2,500.00 32.86 2,230.11 665.95 697.5454.87 534,688.196,028,558.832,171.51 4.00 -712.99 2,600.00 31.71 2,314.68 693.89 742.9662.05 534,733.486,028,586.972,256.08 4.00 -744.03 2,700.00 30.98 2,400.12 715.18 790.3369.61 534,780.746,028,608.482,341.52 4.00 -768.57 2,800.00 30.72 2,486.00 729.73 839.4077.40 534,829.746,028,623.242,427.40 4.00 -786.50 2,900.00 30.92 2,571.92 737.45 889.9485.20 534,880.256,028,631.202,513.32 4.00 -797.73 3,000.00 31.58 2,657.45 738.31 941.7192.82 534,932.016,028,632.292,598.85 4.00 -802.20 3,100.00 32.67 2,742.17 732.31 994.45100.06 534,984.776,028,626.532,683.57 4.00 -799.89 3,200.00 34.14 2,825.68 719.47 1,047.91106.81 535,038.286,028,613.942,767.08 4.00 -790.82 3,300.00 35.97 2,907.56 699.87 1,101.83113.02 535,092.286,028,594.582,848.96 4.00 -775.02 3,400.00 38.08 2,987.42 673.58 1,155.93118.66 535,146.506,028,568.552,928.82 4.00 -752.57 3,500.00 40.43 3,064.87 640.75 1,209.97123.77 535,200.686,028,535.973,006.27 4.00 -723.59 3,600.00 42.99 3,139.53 601.53 1,263.67128.39 535,254.556,028,497.003,080.93 4.00 -688.21 3,700.00 45.72 3,211.04 556.11 1,316.78132.58 535,307.866,028,451.833,152.44 4.00 -646.61 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,220.44 Vert Section 3,800.00 48.59 3,279.04 504.72 1,369.03136.38 535,360.346,028,400.683,220.44 4.00 -598.99 3,900.00 51.57 3,343.21 447.60 1,420.17139.86 535,411.746,028,343.813,284.61 4.00 -545.58 4,000.00 54.65 3,403.24 385.04 1,469.95143.06 535,461.806,028,281.483,344.64 4.00 -486.64 4,100.00 57.81 3,458.83 317.33 1,518.14146.01 535,510.296,028,214.003,400.23 4.00 -422.46 4,200.00 61.03 3,509.71 244.81 1,564.48148.77 535,556.966,028,141.703,451.11 4.00 -353.35 4,300.00 64.30 3,555.63 167.84 1,608.77151.36 535,601.606,028,064.933,497.03 4.00 -279.65 4,400.00 67.61 3,596.37 86.77 1,650.78153.81 535,643.976,027,984.073,537.77 4.00 -201.71 4,500.00 70.96 3,631.74 2.02 1,690.31156.15 535,683.886,027,899.513,573.14 4.00 -119.93 4,600.00 74.34 3,661.55 -86.01 1,727.16158.39 535,721.146,027,811.663,602.95 4.00 -34.68 4,700.00 77.74 3,685.67 -176.88 1,761.16160.56 535,755.556,027,720.953,627.07 4.00 53.60 4,800.00 81.16 3,703.97 -270.16 1,792.14162.68 535,786.956,027,627.823,645.37 4.00 144.49 4,900.00 84.59 3,716.37 -365.39 1,819.95164.75 535,815.196,027,532.733,657.77 4.00 237.55 4,911.91 85.00 3,717.45 -376.84 1,823.05165.00 535,818.346,027,521.293,658.85 4.00 248.75 End Dir : 4911.91' MD, 3717.45' TVD 5,000.00 85.00 3,725.13 -461.61 1,845.76165.00 535,841.446,027,436.643,666.53 0.00 331.73 5,100.00 85.00 3,733.85 -557.83 1,871.54165.00 535,867.666,027,340.543,675.25 0.00 425.92 5,200.00 85.00 3,742.56 -654.06 1,897.32165.00 535,893.886,027,244.453,683.96 0.00 520.11 5,211.91 85.00 3,743.60 -665.52 1,900.40165.00 535,897.006,027,233.003,685.00 0.00 531.33 Start Dir 4º/100' : 5211.91' MD, 3743.6'TVD - 9 5/8" x 12 1/4" 5,300.00 88.22 3,748.81 -750.72 1,922.08166.44 535,919.076,027,147.903,690.21 4.00 614.82 5,345.82 89.89 3,749.57 -795.33 1,932.53167.19 535,929.736,027,103.353,690.97 4.00 658.58 End Dir : 5345.82' MD, 3749.57' TVD 5,400.00 89.89 3,749.67 -848.16 1,944.55167.19 535,941.986,027,050.583,691.07 0.00 710.45 5,500.00 89.89 3,749.86 -945.67 1,966.73167.19 535,964.616,026,953.193,691.26 0.00 806.17 5,600.00 89.89 3,750.05 -1,043.17 1,988.91167.19 535,987.236,026,855.793,691.45 0.00 901.89 5,700.00 89.89 3,750.24 -1,140.68 2,011.09167.19 536,009.856,026,758.393,691.64 0.00 997.62 5,800.00 89.89 3,750.42 -1,238.19 2,033.27167.19 536,032.486,026,661.003,691.82 0.00 1,093.34 5,841.57 89.89 3,750.50 -1,278.73 2,042.49167.19 536,041.886,026,620.513,691.90 0.00 1,133.14 Start Dir 3º/100' : 5841.57' MD, 3750.5'TVD 5,900.00 90.17 3,750.47 -1,335.89 2,054.59168.92 536,054.246,026,563.413,691.87 3.00 1,189.31 6,000.00 90.64 3,749.76 -1,434.47 2,071.27171.88 536,071.376,026,464.913,691.16 3.00 1,286.50 6,100.00 91.12 3,748.23 -1,533.78 2,082.83174.84 536,083.386,026,365.673,689.63 3.00 1,384.75 6,200.00 91.59 3,745.87 -1,633.53 2,089.24177.81 536,090.256,026,265.953,687.27 3.00 1,483.82 6,274.02 91.93 3,743.60 -1,707.50 2,090.65180.00 536,092.006,026,192.003,685.00 3.00 1,557.51 6,300.00 91.93 3,742.72 -1,733.47 2,090.48180.78 536,091.946,026,166.043,684.12 3.00 1,583.42 6,401.82 91.93 3,739.29 -1,835.13 2,086.38183.84 536,088.316,026,064.363,680.69 3.00 1,685.13 End Dir : 6401.82' MD, 3739.29' TVD 6,500.00 91.93 3,735.99 -1,933.04 2,079.81183.84 536,082.196,025,966.443,677.39 0.00 1,783.25 6,600.00 91.93 3,732.62 -2,032.76 2,073.13183.84 536,075.966,025,866.703,674.02 0.00 1,883.19 6,700.00 91.93 3,729.25 -2,132.48 2,066.44183.84 536,069.736,025,766.963,670.65 0.00 1,983.13 6,800.00 91.93 3,725.89 -2,232.20 2,059.76183.84 536,063.506,025,667.223,667.29 0.00 2,083.08 6,900.00 91.93 3,722.52 -2,331.92 2,053.07183.84 536,057.276,025,567.483,663.92 0.00 2,183.02 7,000.00 91.93 3,719.15 -2,431.64 2,046.38183.84 536,051.046,025,467.743,660.55 0.00 2,282.96 7,100.00 91.93 3,715.79 -2,531.35 2,039.70183.84 536,044.816,025,368.003,657.19 0.00 2,382.91 7,200.00 91.93 3,712.42 -2,631.07 2,033.01183.84 536,038.586,025,268.263,653.82 0.00 2,482.85 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,650.45 Vert Section 7,300.00 91.93 3,709.05 -2,730.79 2,026.32183.84 536,032.356,025,168.533,650.45 0.00 2,582.79 7,400.00 91.93 3,705.69 -2,830.51 2,019.64183.84 536,026.126,025,068.793,647.09 0.00 2,682.74 7,500.00 91.93 3,702.32 -2,930.23 2,012.95183.84 536,019.896,024,969.053,643.72 0.00 2,782.68 7,600.00 91.93 3,698.95 -3,029.95 2,006.26183.84 536,013.666,024,869.313,640.35 0.00 2,882.62 7,700.00 91.93 3,695.58 -3,129.67 1,999.58183.84 536,007.436,024,769.573,636.98 0.00 2,982.56 7,800.00 91.93 3,692.22 -3,229.39 1,992.89183.84 536,001.206,024,669.833,633.62 0.00 3,082.51 7,900.00 91.93 3,688.85 -3,329.11 1,986.20183.84 535,994.976,024,570.093,630.25 0.00 3,182.45 8,000.00 91.93 3,685.48 -3,428.83 1,979.52183.84 535,988.746,024,470.353,626.88 0.00 3,282.39 8,100.00 91.93 3,682.12 -3,528.55 1,972.83183.84 535,982.516,024,370.613,623.52 0.00 3,382.34 8,200.00 91.93 3,678.75 -3,628.27 1,966.14183.84 535,976.286,024,270.873,620.15 0.00 3,482.28 8,300.00 91.93 3,675.38 -3,727.99 1,959.46183.84 535,970.056,024,171.143,616.78 0.00 3,582.22 8,400.00 91.93 3,672.02 -3,827.71 1,952.77183.84 535,963.826,024,071.403,613.42 0.00 3,682.16 8,500.00 91.93 3,668.65 -3,927.43 1,946.08183.84 535,957.596,023,971.663,610.05 0.00 3,782.11 8,600.00 91.93 3,665.28 -4,027.15 1,939.40183.84 535,951.366,023,871.923,606.68 0.00 3,882.05 8,700.00 91.93 3,661.91 -4,126.86 1,932.71183.84 535,945.136,023,772.183,603.31 0.00 3,981.99 8,798.44 91.93 3,658.60 -4,225.03 1,926.13183.84 535,939.006,023,674.003,600.00 0.00 4,080.38 Start Dir 3º/100' : 8798.44' MD, 3658.6'TVD 8,800.00 91.97 3,658.55 -4,226.58 1,926.03183.86 535,938.906,023,672.443,599.95 3.01 4,081.94 8,828.42 92.73 3,657.38 -4,254.91 1,924.02184.24 535,937.036,023,644.113,598.78 3.00 4,110.33 End Dir : 8828.42' MD, 3657.38' TVD 8,900.00 92.73 3,653.97 -4,326.21 1,918.73184.24 535,932.066,023,572.793,595.37 0.00 4,181.83 9,000.00 92.73 3,649.20 -4,425.82 1,911.34184.24 535,925.136,023,473.153,590.60 0.00 4,281.71 9,100.00 92.73 3,644.43 -4,525.44 1,903.95184.24 535,918.206,023,373.523,585.83 0.00 4,381.60 9,200.00 92.73 3,639.67 -4,625.05 1,896.56184.24 535,911.266,023,273.883,581.07 0.00 4,481.49 9,300.00 92.73 3,634.90 -4,724.66 1,889.17184.24 535,904.336,023,174.253,576.30 0.00 4,581.37 9,400.00 92.73 3,630.13 -4,824.27 1,881.78184.24 535,897.406,023,074.613,571.53 0.00 4,681.26 9,500.00 92.73 3,625.37 -4,923.89 1,874.40184.24 535,890.476,022,974.983,566.77 0.00 4,781.14 9,600.00 92.73 3,620.60 -5,023.50 1,867.01184.24 535,883.536,022,875.343,562.00 0.00 4,881.03 9,700.00 92.73 3,615.83 -5,123.11 1,859.62184.24 535,876.606,022,775.713,557.23 0.00 4,980.91 9,800.00 92.73 3,611.07 -5,222.73 1,852.23184.24 535,869.676,022,676.073,552.47 0.00 5,080.80 9,900.00 92.73 3,606.30 -5,322.34 1,844.84184.24 535,862.736,022,576.433,547.70 0.00 5,180.68 10,000.00 92.73 3,601.53 -5,421.95 1,837.45184.24 535,855.806,022,476.803,542.93 0.00 5,280.57 10,100.00 92.73 3,596.76 -5,521.56 1,830.06184.24 535,848.876,022,377.163,538.16 0.00 5,380.45 10,200.00 92.73 3,592.00 -5,621.18 1,822.67184.24 535,841.936,022,277.533,533.40 0.00 5,480.34 10,300.00 92.73 3,587.23 -5,720.79 1,815.28184.24 535,835.006,022,177.893,528.63 0.00 5,580.23 10,400.00 92.73 3,582.46 -5,820.40 1,807.89184.24 535,828.076,022,078.263,523.86 0.00 5,680.11 10,500.00 92.73 3,577.70 -5,920.01 1,800.50184.24 535,821.136,021,978.623,519.10 0.00 5,780.00 10,600.00 92.73 3,572.93 -6,019.63 1,793.11184.24 535,814.206,021,878.993,514.33 0.00 5,879.88 10,700.00 92.73 3,568.16 -6,119.24 1,785.72184.24 535,807.276,021,779.353,509.56 0.00 5,979.77 10,800.00 92.73 3,563.40 -6,218.85 1,778.34184.24 535,800.336,021,679.713,504.80 0.00 6,079.65 10,900.00 92.73 3,558.63 -6,318.46 1,770.95184.24 535,793.406,021,580.083,500.03 0.00 6,179.54 11,000.00 92.73 3,553.86 -6,418.08 1,763.56184.24 535,786.476,021,480.443,495.26 0.00 6,279.42 11,100.00 92.73 3,549.09 -6,517.69 1,756.17184.24 535,779.546,021,380.813,490.49 0.00 6,379.31 11,200.00 92.73 3,544.33 -6,617.30 1,748.78184.24 535,772.606,021,281.173,485.73 0.00 6,479.19 11,300.00 92.73 3,539.56 -6,716.91 1,741.39184.24 535,765.676,021,181.543,480.96 0.00 6,579.08 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,476.19 Vert Section 11,400.00 92.73 3,534.79 -6,816.53 1,734.00184.24 535,758.746,021,081.903,476.19 0.00 6,678.96 11,500.00 92.73 3,530.03 -6,916.14 1,726.61184.24 535,751.806,020,982.273,471.43 0.00 6,778.85 11,600.00 92.73 3,525.26 -7,015.75 1,719.22184.24 535,744.876,020,882.633,466.66 0.00 6,878.74 11,694.16 92.73 3,520.77 -7,109.55 1,712.26184.24 535,738.346,020,788.813,462.17 0.00 6,972.79 Start Dir 3º/100' : 11694.16' MD, 3520.77'TVD 11,700.00 92.56 3,520.50 -7,115.37 1,711.83184.24 535,737.946,020,782.993,461.90 3.00 6,978.62 11,785.24 90.00 3,518.60 -7,200.34 1,705.51184.27 535,732.006,020,698.003,460.00 3.00 7,063.83 11,800.00 89.56 3,518.66 -7,215.06 1,704.41184.26 535,730.976,020,683.283,460.06 3.00 7,078.59 11,895.40 86.70 3,521.78 -7,310.14 1,697.37184.21 535,724.366,020,588.183,463.18 3.00 7,173.93 End Dir : 11895.4' MD, 3521.78' TVD 11,900.00 86.70 3,522.04 -7,314.72 1,697.03184.21 535,724.046,020,583.593,463.44 0.00 7,178.52 12,000.00 86.70 3,527.80 -7,414.28 1,689.70184.21 535,717.176,020,484.013,469.20 0.00 7,278.36 12,100.00 86.70 3,533.57 -7,513.85 1,682.37184.21 535,710.296,020,384.423,474.97 0.00 7,378.19 12,135.74 86.70 3,535.63 -7,549.43 1,679.74184.21 535,707.846,020,348.833,477.03 0.00 7,413.87 Start Dir 3º/100' : 12135.74' MD, 3535.63'TVD 12,200.00 88.57 3,538.28 -7,613.44 1,674.77184.67 535,703.166,020,284.803,479.68 3.00 7,478.07 12,214.85 89.00 3,538.60 -7,628.24 1,673.55184.78 535,702.006,020,270.003,480.00 3.00 7,492.92 12,276.07 90.84 3,538.69 -7,689.24 1,668.46184.75 535,697.206,020,208.983,480.09 3.00 7,554.13 End Dir : 12276.07' MD, 3538.69' TVD 12,300.00 90.84 3,538.34 -7,713.09 1,666.48184.75 535,695.326,020,185.133,479.74 0.00 7,578.05 12,400.00 90.84 3,536.88 -7,812.74 1,658.21184.75 535,687.516,020,085.463,478.28 0.00 7,678.03 12,500.00 90.84 3,535.42 -7,912.38 1,649.93184.75 535,679.696,019,985.783,476.82 0.00 7,778.01 12,600.00 90.84 3,533.96 -8,012.03 1,641.66184.75 535,671.876,019,886.113,475.36 0.00 7,877.99 12,700.00 90.84 3,532.50 -8,111.67 1,633.39184.75 535,664.056,019,786.443,473.90 0.00 7,977.98 12,800.00 90.84 3,531.04 -8,211.32 1,625.11184.75 535,656.236,019,686.763,472.44 0.00 8,077.96 12,900.00 90.84 3,529.58 -8,310.97 1,616.84184.75 535,648.416,019,587.093,470.98 0.00 8,177.94 13,000.00 90.84 3,528.12 -8,410.61 1,608.56184.75 535,640.606,019,487.423,469.52 0.00 8,277.92 13,100.00 90.84 3,526.66 -8,510.26 1,600.29184.75 535,632.786,019,387.743,468.06 0.00 8,377.90 13,200.00 90.84 3,525.20 -8,609.91 1,592.01184.75 535,624.966,019,288.073,466.60 0.00 8,477.88 13,300.00 90.84 3,523.74 -8,709.55 1,583.74184.75 535,617.146,019,188.403,465.14 0.00 8,577.86 13,400.00 90.84 3,522.29 -8,809.20 1,575.46184.75 535,609.326,019,088.723,463.69 0.00 8,677.84 13,500.00 90.84 3,520.83 -8,908.85 1,567.19184.75 535,601.506,018,989.053,462.23 0.00 8,777.82 13,600.00 90.84 3,519.37 -9,008.49 1,558.91184.75 535,593.686,018,889.383,460.77 0.00 8,877.80 13,700.00 90.84 3,517.91 -9,108.14 1,550.64184.75 535,585.876,018,789.703,459.31 0.00 8,977.78 13,800.00 90.84 3,516.45 -9,207.78 1,542.36184.75 535,578.056,018,690.033,457.85 0.00 9,077.76 13,900.00 90.84 3,514.99 -9,307.43 1,534.09184.75 535,570.236,018,590.363,456.39 0.00 9,177.75 14,000.00 90.84 3,513.53 -9,407.08 1,525.81184.75 535,562.416,018,490.683,454.93 0.00 9,277.73 14,100.00 90.84 3,512.07 -9,506.72 1,517.54184.75 535,554.596,018,391.013,453.47 0.00 9,377.71 14,200.00 90.84 3,510.61 -9,606.37 1,509.26184.75 535,546.776,018,291.343,452.01 0.00 9,477.69 14,300.00 90.84 3,509.15 -9,706.02 1,500.99184.75 535,538.956,018,191.663,450.55 0.00 9,577.67 14,337.79 90.84 3,508.60 -9,743.67 1,497.86184.75 535,536.006,018,154.003,450.00 0.00 9,615.45 Total Depth : 14337.79' MD, 3508.6' TVD 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Standard Proposal Report Well: Wellbore: Plan: MPU M-45 MPU M-45 Survey Calculation Method:Minimum Curvature MPU M-45 as-built RKB @ 58.60usft Design:MPU M-45 wp05 Database:NORTH US + CANADA MD Reference:MPU M-45 as-built RKB @ 58.60usft North Reference: Well Plan: MPU M-45 True Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) M-45 wp04 CP1 3,743.60 6,026,192.00 536,092.00-1,707.50 2,090.650.00 0.00 -plan hits target center - Point M-45 wp04 toe 3,508.60 6,018,154.00 535,536.00-9,743.67 1,497.860.00 0.00 -plan hits target center - Point M-45 wp04 CP2 3,658.60 6,023,674.00 535,939.00-4,225.02 1,926.130.00 0.00 -plan hits target center - Point M-45 wp04 Heel 3,743.60 6,027,233.00 535,897.00-665.52 1,900.400.00 0.00 -plan hits target center - Circle (radius 30.00) M-45 wp04 CP4 3,538.60 6,020,270.00 535,702.00-7,628.24 1,673.550.00 0.00 -plan hits target center - Point M-45 wp04 CP3 3,518.60 6,020,698.00 535,732.00-7,200.34 1,705.510.00 0.00 -plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" x 12 1/4"3,743.605,211.91 9-5/8 12-1/4 6 5/8" x 8 1/2"3,508.6014,337.79 6-5/8 8-1/2 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD 550.00 549.10 18.40 4.93 Start Dir 4º/100' : 550' MD, 549.1'TVD 1,247.23 1,194.91 199.96 167.95 End Dir : 1247.23' MD, 1194.91' TVD 2,403.42 2,149.64 632.78 655.72 Start Dir 4º/100' : 2403.42' MD, 2149.65'TVD 4,911.91 3,717.45 -376.84 1,823.05 End Dir : 4911.91' MD, 3717.45' TVD 5,211.91 3,743.60 -665.52 1,900.40 Start Dir 4º/100' : 5211.91' MD, 3743.6'TVD 5,345.82 3,749.57 -795.33 1,932.53 End Dir : 5345.82' MD, 3749.57' TVD 5,841.57 3,750.50 -1,278.73 2,042.49 Start Dir 3º/100' : 5841.57' MD, 3750.5'TVD 6,401.82 3,739.29 -1,835.13 2,086.38 End Dir : 6401.82' MD, 3739.29' TVD 8,798.44 3,658.60 -4,225.03 1,926.13 Start Dir 3º/100' : 8798.44' MD, 3658.6'TVD 8,828.42 3,657.38 -4,254.91 1,924.02 End Dir : 8828.42' MD, 3657.38' TVD 11,694.16 3,520.77 -7,109.55 1,712.26 Start Dir 3º/100' : 11694.16' MD, 3520.77'TVD 11,895.40 3,521.78 -7,310.14 1,697.37 End Dir : 11895.4' MD, 3521.78' TVD 12,135.74 3,535.63 -7,549.43 1,679.74 Start Dir 3º/100' : 12135.74' MD, 3535.63'TVD 12,276.07 3,538.69 -7,689.24 1,668.46 End Dir : 12276.07' MD, 3538.69' TVD 14,337.79 3,508.60 -9,743.67 1,497.86 Total Depth : 14337.79' MD, 3508.6' TVD 4/30/2020 5:19:49PM COMPASS 5000.15 Build 91E Page 8 30 April, 2020Milne PointM Pt Moose PadPlan: MPU M-45MPU M-45MPU M-45 wp05Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,027,889.76 N, 533,993.77 E (70° 29' 14.00" N, 149° 43' 19.75" W)Datum Height: MPU M-45 as-built RKB @ 58.60usftScan Range: 33.50 to 5,211.91 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00Scan Range: 33.50 to 5,211.91 usft. Measured Depth. Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 5,211.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadM Pt M PadM Pt Moose PadMPU M-10 - MPU M-10 - MPU M-10120.04 33.50 118.63 34.03 85.03633.50Centre Distance Pass - MPU M-10 - MPU M-10 - MPU M-10120.57 233.50 118.46 233.31 57.271233.50Ellipse Separation Pass - MPU M-10 - MPU M-10 - MPU M-10276.73 1,533.50 263.87 1,422.86 21.5251,533.50Clearance Factor Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1120.04 33.50 118.63 34.03 85.03633.50Centre Distance Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1120.57 233.50 118.46 233.31 57.271233.50Ellipse Separation Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1276.73 1,533.50 263.87 1,422.86 21.5241,533.50Clearance Factor Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2120.04 33.50 118.63 34.03 85.03633.50Centre Distance Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2120.57 233.50 118.46 233.31 57.271233.50Ellipse Separation Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2276.73 1,533.50 263.87 1,422.86 21.5251,533.50Clearance Factor Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3120.04 33.50 118.63 34.03 85.03633.50Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3120.57 233.50 118.46 233.31 57.271233.50Ellipse Separation Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3276.73 1,533.50 263.87 1,422.86 21.5251,533.50Clearance Factor Pass - MPU M-11 - MPU M-11 - MPU M-1126.20 432.74 23.02 433.61 8.243432.74Centre Distance Pass - MPU M-11 - MPU M-11 - MPU M-1126.30 458.50 22.97 459.30 7.886458.50Ellipse Separation Pass - MPU M-11 - MPU M-11 - MPU M-1128.09 533.50 24.29 533.99 7.403533.50Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-1259.89 33.50 58.47 34.25 42.42333.50Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-1260.26 158.50 58.25 158.69 30.006158.50Ellipse Separation Pass - MPU M-12 - MPU M-12 - MPU M-12330.30 5,108.50 280.19 5,015.66 6.5925,108.50Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB159.89 33.50 58.47 34.25 42.42333.50Centre Distance Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB160.26 158.50 58.25 158.69 30.006158.50Ellipse Separation Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1370.76 5,211.91 289.69 5,107.00 4.5735,211.91Clearance Factor Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB259.89 33.50 58.47 34.25 42.42333.50Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB260.26 158.50 58.25 158.69 30.006158.50Ellipse Separation Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2330.30 5,108.50 280.07 5,015.66 6.5765,108.50Clearance Factor Pass - 30 April, 2020-17:23COMPASSPage 2 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 5,211.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-13 - MPU M-13i - MPU M-13123.30 290.38 120.92 291.28 51.923290.38Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13123.38 308.50 120.90 309.40 49.756308.50Ellipse Separation Pass - MPU M-13 - MPU M-13i - MPU M-13444.99 5,211.91 372.80 4,395.68 6.1645,211.91Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14151.80 301.11 149.23 302.86 59.118301.11Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14151.81 308.50 149.20 310.28 58.152308.50Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-141,236.73 5,211.91 1,164.73 4,399.52 17.1765,211.91Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i218.56 33.50 216.65 33.94 114.34033.50Ellipse Separation Pass - MPU M-15i - MPU M-15 - MPU M-15i271.43 708.50 266.50 691.91 55.017708.50Clearance Factor Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1218.56 33.50 216.65 33.94 114.34033.50Ellipse Separation Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1271.43 708.50 266.50 691.91 55.017708.50Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16297.01 33.50 295.59 34.18 210.39533.50Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16385.40 858.50 379.90 828.26 70.142858.50Clearance Factor Pass - MPU M-17i - MPU M-17i - MPU M-17i380.74 33.50 379.32 34.00 269.70933.50Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i381.14 283.50 378.74 282.58 159.113283.50Ellipse Separation Pass - MPU M-17i - MPU M-17i - MPU M-17i502.38 958.50 496.16 905.73 80.708958.50Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18409.23 33.50 407.82 34.42 289.89333.50Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18409.25 58.50 407.79 58.24 280.56158.50Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18529.38 958.50 523.20 904.16 85.688958.50Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1409.23 33.50 407.82 34.42 289.89333.50Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1409.25 58.50 407.79 58.24 280.56158.50Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1529.38 958.50 523.20 904.16 85.688958.50Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2409.23 33.50 407.82 34.42 289.89333.50Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2409.25 58.50 407.79 58.24 280.56158.50Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2529.38 958.50 523.20 904.16 85.688958.50Clearance Factor Pass - MPU M-19i - MPU M-19i - MPU M-19i495.77 226.95 493.53 227.81 221.277226.95Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i495.87 283.50 493.38 282.74 199.328283.50Ellipse Separation Pass - MPU M-19i - MPU M-19i - MPU M-19i672.04 1,033.50 665.29 917.21 99.6291,033.50Clearance Factor Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1495.77 226.95 493.53 227.81 221.277226.95Centre Distance Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1495.87 283.50 493.38 282.74 199.328283.50Ellipse Separation Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1672.04 1,033.50 665.29 917.21 99.6271,033.50Clearance FactorPass - 30 April, 2020-17:23COMPASSPage 3 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 5,211.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-20 - MPU M-20 - MPU M-20150.09 283.50 147.81 284.04 65.668283.50Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20150.27 333.50 147.70 334.22 58.415333.50Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20483.25 3,183.50 447.79 3,619.98 13.6303,183.50Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1150.09 283.50 147.81 284.04 65.668283.50Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1150.27 333.50 147.70 334.22 58.415333.50Ellipse Separation Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1483.25 3,183.50 447.79 3,619.98 13.6303,183.50Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2150.09 283.50 147.81 284.04 65.668283.50Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2150.27 333.50 147.70 334.22 58.415333.50Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2483.25 3,183.50 447.79 3,619.98 13.6303,183.50Clearance Factor Pass - MPU M-21i - MPU M-21i - MPU M-21i239.89 304.14 237.29 305.18 92.245304.14Centre Distance Pass - MPU M-21i - MPU M-21i - MPU M-21i239.95 333.50 237.21 334.44 87.299333.50Ellipse Separation Pass - MPU M-21i - MPU M-21i - MPU M-21i673.14 2,533.50 649.16 2,562.48 28.0762,533.50Clearance Factor Pass - MPU M-34 - MPU M-34 - MPU M-34241.85 294.21 239.28 295.69 94.108294.21Centre Distance Pass - MPU M-34 - MPU M-34 - MPU M-34241.89 308.50 239.25 309.68 91.630308.50Ellipse Separation Pass - MPU M-34 - MPU M-34 - MPU M-34293.20 683.50 288.44 645.93 61.543683.50Clearance Factor Pass - MPU M-35i - MPU M-35i - MPU M-35i172.58 33.50 170.67 34.40 90.28933.50Ellipse Separation Pass - MPU M-35i - MPU M-35i - MPU M-35i218.17 608.50 213.82 586.65 50.127608.50Clearance Factor Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1172.58 33.50 170.67 34.40 90.28933.50Ellipse Separation Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1218.17 608.50 213.82 586.65 50.127608.50Clearance Factor Pass - MPU M-43 - MPU M-43 - MPU M-4360.13 33.50 58.21 33.68 31.45633.50Ellipse Separation Pass - MPU M-43 - MPU M-43 - MPU M-43161.70 1,358.50 150.97 1,297.51 15.0701,358.50Clearance Factor Pass - MPU M-43 - MPU M-43PB1 - MPU M-43PB160.13 33.50 58.21 33.68 31.45633.50Ellipse Separation Pass - MPU M-43 - MPU M-43PB1 - MPU M-43PB1161.70 1,358.50 150.98 1,297.51 15.0801,358.50Clearance Factor Pass - MPU M-43 - MPU M-43PB2 - MPU M-43PB260.13 33.50 58.21 33.68 31.45633.50Ellipse Separation Pass - MPU M-43 - MPU M-43PB2 - MPU M-43PB2161.70 1,358.50 150.98 1,297.51 15.0801,358.50Clearance Factor Pass - MPU M-43 - MPU M-43PB3 - MPU M-43PB360.13 33.50 58.21 33.68 31.45633.50Ellipse Separation Pass - MPU M-43 - MPU M-43PB3 - MPU M-43PB3161.70 1,358.50 150.98 1,297.51 15.0801,358.50Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02137.65 258.50 135.05 238.90 52.825258.50Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02137.65 283.50 134.92 263.90 50.337283.50Ellipse Separation Pass - Plan: MPU M-27 - M-27 - M-27 wp02324.62 4,758.50 275.204,277.59 6.5684,758.50Clearance Factor Pass - 30 April, 2020-17:23COMPASSPage 4 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 5,211.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU M-28i - M-28i - M-28i wp01153.18 258.50 150.57 238.90 58.829258.50Centre Distance Pass - Plan: MPU M-28i - M-28i - M-28i wp01153.31 308.50 150.44 288.90 53.511308.50Ellipse Separation Pass - Plan: MPU M-28i - M-28i - M-28i wp01917.72 5,211.91 863.79 4,149.81 17.0175,211.91Clearance Factor Pass - Plan: MPU M-29 - M-29 - M-29 wp02172.56 258.50 169.96 238.90 66.321258.50Centre Distance Pass - Plan: MPU M-29 - M-29 - M-29 wp02172.67 308.50 169.81 288.90 60.321308.50Ellipse Separation Pass - Plan: MPU M-29 - M-29 - M-29 wp021,264.44 5,211.91 1,226.56 3,940.39 33.3845,211.91Clearance Factor Pass - Plan: MPU M-30i - M-30i - M-30i wp02194.66 258.50 192.06 238.90 74.857258.50Centre Distance Pass - Plan: MPU M-30i - M-30i - M-30i wp02194.77 308.50 191.91 288.12 68.169308.50Ellipse Separation Pass - Plan: MPU M-30i - M-30i - M-30i wp021,485.26 5,211.91 1,444.66 3,785.70 36.5885,211.91Clearance Factor Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp02119.99 258.50 117.53 258.50 48.838258.50Centre Distance Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp02120.05 308.50 117.38 308.50 45.042308.50Ellipse Separation Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp02413.34 2,883.50 380.44 3,098.42 12.5662,883.50Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 179.97 258.50 177.51 258.70 73.255258.50Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 180.02 308.50 177.36 308.70 67.551308.50Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 339.62 3,358.50 302.27 3,490.35 9.0943,358.50Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc611.02 562.98 606.97 609.03 150.878562.98Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc1,021.66 1,608.50 1,009.57 1,425.50 84.4651,608.50Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M-N1 - Kup N1 209.79 258.50 207.16 258.60 79.685258.50Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M-N1 - Kup N1 209.88 308.50 206.99 308.05 72.588308.50Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M-N1 - Kup N1 269.78 858.50 263.80 836.95 45.113858.50Clearance Factor Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02150.09 281.53 147.54 281.66 58.836281.53Centre Distance Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02153.34 1,358.50 144.98 1,291.01 18.3341,358.50Ellipse Separation Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02865.84 5,211.91 811.90 6,261.74 16.0525,211.91Clearance Factor Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44i150.09 85.72 148.15 85.92 77.03585.72Ellipse Separation Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44i201.01 233.50 196.89 100.00 48.775233.50Clearance Factor Pass - Slot 37 - Placeholder - Slot 37 - Placeholder - Slot 37- 194.31 258.50 191.67 220.90 73.662258.50Centre Distance Pass - Slot 37 - Placeholder - Slot 37 - Placeholder - Slot 37- 194.31 283.50 191.54 245.90 70.226283.50Ellipse Separation Pass - Slot 37 - Placeholder - Slot 37 - Placeholder - Slot 37- 237.67 708.50 232.48 667.18 45.790708.50Clearance Factor Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 89.82 258.50 87.19 220.90 34.119258.50Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 89.87 308.50 86.98 270.90 31.064308.50Ellipse Separation Pass - 30 April, 2020-17:23COMPASSPage 5 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 5,211.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningSlot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 101.71 608.50 97.05 569.28 21.802608.50Clearance Factor Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 137.45 258.50 134.81 220.90 52.002258.50Centre Distance Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 137.45 283.50 134.68 245.90 49.566283.50Ellipse Separation Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 165.32 608.50 160.63 569.28 35.260608.50Clearance Factor Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 127.30 258.50 124.66 220.90 48.130258.50Centre Distance Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 127.31 283.50 124.53 245.90 45.872283.50Ellipse Separation Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 155.46 608.50 150.77 569.28 33.147608.50Clearance Factor Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 29.77 258.50 27.14 220.90 11.310258.50Centre Distance Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 29.83 308.50 26.93 270.90 10.310308.50Ellipse Separation Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 34.10 483.50 30.19 445.52 8.727483.50Clearance Factor Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 127.41 258.50 124.77 220.90 48.181258.50Centre Distance Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 127.41 283.50 124.64 245.90 45.921283.50Ellipse Separation Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 160.24 658.50 155.30 618.38 32.467658.50Clearance Factor Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 84.99 723.85 79.77 682.09 16.278723.85Centre Distance Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 85.01 733.50 79.75 691.44 16.147733.50Ellipse Separation Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 88.74 833.50 82.98 787.40 15.396833.50Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.50 700.00 MPU M-45 wp05 3_Gyro-GC_Csg700.00 5,211.91 MPU M-45 wp05 3_MWD+IFR2+MS+Sag5,211.91 14,337.79 MPU M-45 wp05 3_MWD+IFR2+MS+Sag30 April, 2020-17:23COMPASSPage 6 of 9 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Ellipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.30 April, 2020-17:23COMPASSPage 7 of 9 0.001.002.003.004.00Separation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU M-45 NAD 1927 (NADCON CONUS)Alaska Zone 0424.90+N/-S +E/-W Northing Easting Latittude Longitude0.000.006027889.76533993.7770° 29' 13.996 N149° 43' 19.751 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-45, True NorthVertical (TVD) Reference:MPU M-45 as-built RKB @ 58.60usftMeasured Depth Reference:MPU M-45 as-built RKB @ 58.60usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2018-12-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.50 700.00 MPU M-45 wp05 (MPU M-45) 3_Gyro-GC_Csg700.00 5211.91 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+Sag5211.91 14337.79 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPU M-11Slot 42 - PlaceholderSlot 54 - PlaceholderMPU M-43MPU M-12Slot 46 - PlaceholderNO GLOBAL FILTER: Using user defined selection & filtering criteria33.50 To 14337.79Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-45Wellbore: MPU M-45Plan: MPU M-45 wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3743.60 3685.00 5211.91 9-5/8 9 5/8" x 12 1/4"3508.60 3450.00 14337.79 6-5/8 6 5/8" x 8 1/2" 30 April, 2020Milne PointM Pt Moose PadPlan: MPU M-45MPU M-45MPU M-45 wp05Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,027,889.76 N, 533,993.77 E (70° 29' 14.00" N, 149° 43' 19.75" W)Datum Height: MPU M-45 as-built RKB @ 58.60usftScan Range: 5,211.91 to 14,337.79 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00Scan Range: 5,211.91 to 14,337.79 usft. Measured Depth. Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,211.91 to 14,337.79 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-20 - MPL-20 - MPL-20941.35 6,511.91 823.78 12,117.12 8.0076,511.91Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20791.37 7,111.91 716.02 12,554.64 10.5027,111.91Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20788.11 7,203.80 718.64 12,613.90 11.3447,203.80Centre Distance Pass - MPL-36 - MPL-36 - MPL-361,085.14 7,886.91 940.82 13,317.72 7.5197,886.91Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36936.74 8,486.91 837.92 13,716.68 9.4798,486.91Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36927.92 8,667.96 844.42 13,847.80 11.1128,667.96Centre Distance Pass - MPL-36 - MPL-36L1 - MPL-36L11,085.14 7,886.91 935.45 13,317.72 7.2497,886.91Clearance Factor Pass - MPL-36 - MPL-36L1 - MPL-36L1936.74 8,486.91 835.45 13,716.68 9.2488,486.91Ellipse Separation Pass - MPL-36 - MPL-36L1 - MPL-36L1927.92 8,667.96 843.26 13,847.80 10.9618,667.96Centre Distance Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB11,085.14 7,886.91 931.45 13,317.72 7.0617,886.91Clearance Factor Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1939.27 8,461.91 833.51 13,697.26 8.8818,461.91Ellipse Separation Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1927.92 8,667.96 842.39 13,847.80 10.8498,667.96Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB11,085.14 7,886.91 940.85 13,317.72 7.5217,886.91Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1936.74 8,486.91 837.93 13,716.68 9.4808,486.91Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1927.92 8,667.96 844.42 13,847.80 11.1138,667.96Centre Distance Pass - M Pt M PadM-01 - M-01 - M-01399.61 9,386.91 254.35 4,544.47 2.7519,386.91Clearance Factor Pass - M-01 - M-01 - M-01395.50 9,436.91 252.47 4,575.79 2.7659,436.91Ellipse Separation Pass - M-01 - M-01 - M-01394.85 9,465.88 253.69 4,593.92 2.7979,465.88Centre Distance Pass - M-01 - M-01A - M-01A669.56 9,976.94 447.68 4,820.70 3.0189,976.94Centre Distance Pass - M-01 - M-01A - M-01A671.31 10,061.91 444.62 4,890.84 2.96110,061.91Ellipse Separation Pass - M-01 - M-01A - M-01A698.89 10,336.91 459.98 5,150.95 2.92510,336.91Clearance Factor Pass - M Pt Moose PadMPU M-10 - MPU M-10 - MPU M-101,404.95 5,211.91 1,341.94 3,906.67 22.2965,211.91Clearance Factor Pass - MPU M-10 - MPU M-10PB1 - MPU M-10PB11,404.95 5,211.91 1,341.94 3,906.67 22.2945,211.91Clearance Factor Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB21,404.95 5,211.91 1,341.94 3,906.67 22.2955,211.91Clearance Factor Pass - 30 April, 2020-17:24COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,211.91 to 14,337.79 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-10 - MPU M-10PB3 - MPU M-10PB31,404.95 5,211.91 1,341.94 3,906.67 22.2955,211.91Clearance Factor Pass - MPU M-11 - MPU M-11 - MPU M-111,120.35 5,211.91 1,044.90 4,490.86 14.8495,211.91Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12377.96 5,211.91 321.45 5,093.18 6.6885,211.91Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1370.76 5,211.91 289.69 5,107.00 4.5735,211.91Clearance Factor Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2377.96 5,211.91 321.32 5,093.18 6.6745,211.91Clearance Factor Pass - MPU M-13 - MPU M-13i - MPU M-13188.14 5,686.91 128.36 4,776.03 3.1475,686.91Clearance Factor Pass - MPU M-13 - MPU M-13i - MPU M-13155.29 5,786.91 114.44 4,854.64 3.8015,786.91Ellipse Separation Pass - MPU M-13 - MPU M-13i - MPU M-13144.94 5,871.72 121.74 4,923.17 6.2485,871.72Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14241.04 6,686.91 175.82 5,401.90 3.6966,686.91Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14200.05 6,786.91 155.89 5,450.55 4.5306,786.91Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14190.61 6,857.47 162.65 5,486.93 6.8166,857.47Centre Distance Pass - MPU M-15i - MPU M-15 - MPU M-15i218.89 7,636.91 134.62 5,799.16 2.5977,636.91Clearance Factor Pass - MPU M-15i - MPU M-15 - MPU M-15i184.34 7,711.91 119.59 5,838.97 2.8477,711.91Ellipse Separation Pass - MPU M-15i - MPU M-15 - MPU M-15i167.09 7,804.11 131.60 5,887.90 4.7087,804.11Centre Distance Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1218.89 7,636.91 134.40 5,799.16 2.5917,636.91Clearance Factor Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1184.34 7,711.91 119.37 5,838.97 2.8377,711.91Ellipse Separation Pass - MPU M-15i - MPU M-15PB1 - MPU M-15PB1167.09 7,804.11 131.38 5,887.90 4.6807,804.11Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16166.65 8,636.91 67.33 6,418.29 1.6788,636.91Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16154.72 8,661.91 63.91 6,431.98 1.7048,661.91Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16132.33 8,756.38 85.49 6,482.64 2.8258,756.38Centre Distance Pass - MPU M-17i - MPU M-17i - MPU M-17i164.85 9,611.91 55.89 7,177.92 1.5139,611.91Clearance Factor Pass - MPU M-17i - MPU M-17i - MPU M-17i153.87 9,636.91 54.89 7,191.00 1.5559,636.91Ellipse Separation Pass - MPU M-17i - MPU M-17i - MPU M-17i136.61 9,719.21 79.60 7,233.78 2.3969,719.21Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18203.12 10,536.91 78.42 8,005.07 1.62910,536.91Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18179.73 10,586.91 74.00 8,034.21 1.70010,586.91Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18157.73 10,691.42 100.31 8,100.51 2.74710,691.42Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1203.12 10,536.9178.40 8,005.07 1.62910,536.91Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1179.73 10,586.91 73.99 8,034.21 1.70010,586.91Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1157.73 10,691.42 100.31 8,100.51 2.74710,691.42Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2203.12 10,536.91 78.42 8,005.07 1.62910,536.91Clearance Factor Pass - 30 April, 2020-17:24COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,211.91 to 14,337.79 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-18 - MPU M-18PB2 - MPU M-18PB2179.73 10,586.91 74.00 8,034.21 1.70010,586.91Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2157.73 10,691.42 100.31 8,100.51 2.74710,691.42Centre Distance Pass - MPU M-19i - MPU M-19i - MPU M-19i240.35 11,536.91 113.67 8,839.86 1.89711,536.91Clearance Factor Pass - MPU M-19i - MPU M-19i - MPU M-19i206.13 11,611.91 104.38 8,879.39 2.02611,611.91Ellipse Separation Pass - MPU M-19i - MPU M-19i - MPU M-19i186.31 11,718.04 120.97 8,938.70 2.85211,718.04Centre Distance Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1240.35 11,536.91 113.63 8,839.86 1.89711,536.91Clearance Factor Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1206.13 11,611.91 104.35 8,879.39 2.02511,611.91Ellipse Separation Pass - MPU M-19i - MPU M-19PB1 - MPU M-19PB1186.31 11,718.04 120.76 8,938.70 2.84211,718.04Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20907.60 5,211.91 853.66 5,686.73 16.8275,211.91Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-201,038.95 14,337.79 774.54 14,825.68 3.92914,337.79Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1907.60 5,211.91 853.54 5,686.73 16.7895,211.91Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB11,086.14 12,811.91 841.98 13,188.00 4.44912,811.91Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2907.60 5,211.91 853.53 5,686.73 16.7885,211.91Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB21,060.50 13,486.91 810.92 13,926.00 4.24913,486.91Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB21,060.36 13,504.64 810.86 13,926.00 4.25013,504.64Ellipse Separation Pass - MPU M-34 - MPU M-34 - MPU M-34194.518,911.9161.856,347.031.4668,911.91Clearance FactorPass - MPU M-34 - MPU M-34 - MPU M-34187.338,936.9159.876,369.541.4708,936.91Ellipse SeparationPass - MPU M-34 - MPU M-34 - MPU M-34168.85 9,062.43 83.74 6,471.29 1.9849,062.43Centre Distance Pass - MPU M-35i - MPU M-35i - MPU M-35i140.797,861.9129.365,601.681.2647,861.91Clearance FactorPass - MPU M-35i - MPU M-35i - MPU M-35i133.187,886.9128.215,620.251.2697,886.91Ellipse SeparationPass - MPU M-35i - MPU M-35i - MPU M-35i123.12 7,959.90 48.80 5,675.23 1.6577,959.90Centre Distance Pass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1140.797,861.9129.355,601.681.2637,861.91Clearance FactorPass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1133.187,886.9128.215,620.251.2697,886.91Ellipse SeparationPass - MPU M-35i - MPU M-35PB1 - MPU M-35PB1123.12 7,959.90 48.80 5,675.23 1.6577,959.90Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02587.28 5,211.91 529.02 4,081.96 10.0825,211.91Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02587.28 5,211.91 529.02 4,081.96 10.0825,211.91Ellipse Separation Pass - Plan: MPU M-28i - M-28i - M-28i wp01917.72 5,211.91 863.79 4,149.81 17.0175,211.91Ellipse Separation Pass - Plan: MPU M-28i - M-28i - M-28i wp011,032.50 5,536.91 965.62 4,110.64 15.4375,536.91Clearance Factor Pass - Plan: MPU M-29 - M-29 - M-29 wp021,264.44 5,211.91 1,226.56 3,940.39 33.3845,211.91Centre Distance Pass - Plan: MPU M-29 - M-29 - M-29 wp021,267.90 5,336.91 1,225.01 3,984.94 29.5655,336.91Ellipse Separation Pass - 30 April, 2020-17:24COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU M-45 - MPU M-45 wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,211.91 to 14,337.79 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Moose Pad - Plan: MPU M-45 - MPU M-45 - MPU M-45 wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU M-29 - M-29 - M-29 wp021,547.81 6,186.91 1,466.85 4,227.16 19.1186,186.91Clearance Factor Pass - Plan: MPU M-30i - M-30i - M-30i wp021,485.26 5,211.91 1,444.66 3,785.70 36.5885,211.91Ellipse Separation Pass - Plan: MPU M-30i - M-30i - M-30i wp021,673.61 5,886.91 1,606.02 3,977.88 24.7655,886.91Clearance Factor Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp02911.74 5,211.91 858.84 5,353.39 17.2345,211.91Centre Distance Pass - Plan: MPU M-46 - MPU M-46 - MPU M-46 wp021,055.28 14,337.79 772.39 14,442.33 3.73014,337.79Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc101.717,511.91-23.675,653.130.8117,511.91Ellipse SeparationFAIL - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc93.067,536.91-23.235,658.930.8007,536.91Clearance FactorFAIL - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc90.307,560.03-11.075,664.210.8917,560.03Centre DistanceFAIL - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02713.67 6,199.20 646.71 7,235.14 10.6586,199.20Centre Distance Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02714.04 6,236.91 646.39 7,272.85 10.5546,236.91Ellipse Separation Pass - Rig: MPU M-44i - MPU M-44i - MPU M-44 wp02938.41 14,286.91 663.74 15,351.84 3.41614,286.91Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.50 700.00 MPU M-45 wp05 3_Gyro-GC_Csg700.00 5,211.91 MPU M-45 wp05 3_MWD+IFR2+MS+Sag5,211.91 14,337.79 MPU M-45 wp05 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.30 April, 2020-17:24COMPASSPage 5 of 7M-08 not drilled yet 0.001.002.003.004.00Separation Factor5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500Measured Depth (1000 usft/in)MPU M-46 wp02MPU M-20PB1MPU M-20PB2No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU M-45 NAD 1927 (NADCON CONUS)Alaska Zone 0424.90+N/-S +E/-W Northing Easting Latittude Longitude0.000.006027889.76533993.77 70° 29' 13.996 N149° 43' 19.751 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-45, True NorthVertical (TVD) Reference:MPU M-45 as-built RKB @ 58.60usftMeasured Depth Reference:MPU M-45 as-built RKB @ 58.60usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2018-12-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.50 700.00 MPU M-45 wp05 (MPU M-45) 3_Gyro-GC_Csg700.00 5211.91 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+Sag5211.91 14337.79 MPU M-45 wp05 (MPU M-45) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500Measured Depth (1000 usft/in)M-08DSW wp02 - McLawsNO GLOBAL FILTER: Using user defined selection & filtering criteria33.50 To 14337.79Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-45Wellbore: MPU M-45Plan: MPU M-45 wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3743.60 3685.00 5211.91 9-5/8 9 5/8" x 12 1/4"3508.60 3450.00 14337.79 6-5/8 6 5/8" x 8 1/2" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. MPU M-45 220-044 X Milne Point Unit Schrader Bluff Oil X X WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT M-45Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200440MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" conductor set at 113 ft18 Conductor string providedNA19 Surface casing protects all known USDWsYes 9 5/8" casing will be fully cemented using 2 stage cmt .. ES at 2500 ft20 CMT vol adequate to circulate on conductor & surf csgYes production lateral will use 4.5" slotted/screen liner.21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC provided.. No issues.23 Casing designs adequate for C, T, B & permafrostYes Rig has steel pits. Drilling waste will be transported offsite to approved disposal well.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes M-08 has not been drilled yet but will be watched at that time.26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes Max form pressure = 1685 psi (8.5 ppg EMW) will drill with 8.9-9.5 ppg mud28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MASP = 1311 psi … will test BOP to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate5/5/2020ApprGLSDate5/14/2020ApprDLBDate5/5/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateReverse Jet Pump Completion glsJMP5/14/2020dts 5/14/2020JLC 5/14/2020