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219-132
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, January 16, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-21 MILNE PT UNIT M-21 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/16/2024 M-21 50-029-23649-00-00 219-132-0 W SPT 3847 2191320 1500 700 698 697 694 4YRTST P Sully Sullivan 11/27/2023 Monobore well 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT M-21 Inspection Date: Tubing OA Packer Depth 82 1818 1741 1717IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS231130053813 BBL Pumped:2.5 BBL Returned:2.4 Tuesday, January 16, 2024 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191320 Well Name/No. MILNE PT UNIT M-21 MD 14000 TVD 3644 Completion Date 11/1/2019 REQUIRED INFORMATION Mud Log No Operator Hilcorp Alaska LLC API No. 50-029-23649-00-00 Completion Status 1WINJ Current Status 1WINJ UIC Yes Samples No 1/ Directional Survey Yes/ DATA INFORMATION List of Logs Obtained: Dual GR, ABG, EWR Phase 4, ADR, Wellbore profile Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data ED C 31447 Digital Data Log 11/22/2019 31447 Log Header Scans (from Master Well Data/Logs) Interval OH / Start Stop CH Received Comments 105 14000 11/22/2019 Electronic Data Set, Filename: MPU M-21 LWD Final.las 4905 13963 11/22/2019 Electronic Data Set, Filename: MPU M-21 ADR Quadrants All Curves.las 11/22/2019 Electronic File: MPU M-21 LWD Final MD.cgm 11/22/2019 Electronic File: MPU M-21 LWD Final TVD.cgm 11/22/2019 Electronic File: MPU M-21i_Definitive Survey Report.pdf 11/22/2019 Electronic File: MPU M-21i_Definitive Survey Report.txt 11/22/2019 Electronic File: MPU M-21 LWD Final MD.emf 11/22/2019 Electronic File: MPU M-21 LWD Final TVD.emf 11/22/2019 Electronic File: MPU_M21_Geosteering.dlis 11/22/2019 Electronic File: MPU_M21_Geosteering.ver 11/22/2019 Electronic File: MPU M-21 LWD Final MD.pdf 11/22/2019 Electronic File: MPU M-21 LWD Final TVD.pdf 11/22/2019 Electronic File: MPU M-21 LWD Final MD.tif 11/22/2019 Electronic File: MPU M-21 LWD Final TVD.tif 11/22/2019 Electronic File: EMFView3_1.zip 11/22/2019 Electronic File: Readme.txt 0 0 2191320 MILNE PT UNIT M-21 LOG HEADERS AOGCC Page 1 of 2 Wednesday, March 18, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191320 Well Name/No. MILNE PT UNIT M-21 Operator Hilcorp Alaska LLC MD 14000 TVD 3644 Completion Date 11/1/2019 Completion Status 1WINJ Current Status 1WINJ Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report D Production Test Information Y /0 Geologic Markers/Tops COMPLIANCE HISTORY Completion Date: 11/1/2019 Release Date: 10/4/2019 Description Comments: API No. 50-029-23649-00-00 UIC Yes Directional / Inclination Data Mud Logs, Image Files, Digital Data Y /i) Core Chips Y /® Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files t_% Core Photographs Y /O Daily Operations Summary G) Cuttings Samples Y /g) Laboratory Analyses Y / NA Date Comments Compliance Reviewed By:Date: AOGCC Page 2 of 2 Wednesday, March 18, 2020 MEMORANDUM TO: Jim Reg +�+ P.I. Supervisor I� FROM: Matt Herrera Petroleum Inspector Ntate of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, December 3, 2019 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC M-21 MILNE PT UNIT M-21 Sre: Inspector Reviewed By: P.I. Supry NON -CONFIDENTIAL Comm Well Name MILNE PT UNIT M-21 API Well Number 50-029-23649-00-00 Inspector Name: Matt Herrera Permit Number: 219-132-0 Inspection Date: 11/30/2019 Insp Num: mitMFH191130164336 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 1500 Tubing 809 811 809 809 " Well �� �� 2191320 TYPe Test SPT Test SI 3800 - - - - - M-21 Type In' � �' TVD g -- - -- - - IA _ zsz tats - lzao 1z1s - -1 PTD - -1 OA -- — - -- Yp p _ _ BBL Pumped: 2.4 BBL Returned: i 23 Interval INITAL P/F P ✓� Notes: IA Pressure tested to 1800 PSI Per Operator ✓ Monobore completion no OA Tuesday, December 3, 2019 Page I of I STATE OF ALASKA R E C E ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ARD L(W 1a. Well Status: Oil Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑� WAG[:] WDSPL ❑ No. of Completions: 1 1b. Well Cl s f et' Developn e .7 Ccploratory❑ Service Y�� Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 11/1/2019 14. Permit to Drill Number / Sundry: 219-132 ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: October 16, 2019 15. API Number: 50-029-23649-00-00 ' 4a. Location of Well (Governmental Section): Surface: 5038' FSL, 411' FEL, Sec 14, T1 3N, R9E, UM, AK Top of Productive Interval: 758' FNL, 44' FWL, Sec 13, T13N, R9E, UM, AK , Total Depth: 691' FSL, 489' FEL, Sec 23, T1 3N, R9E, UM, AK ! 8. Date TD Reached: October 26, 2019 16. Well Name and Number: MPU M-21 9. Ref Elevations: KB: 58.87' . GL: 25' , BF: 25' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 13,998' MD / 3,644' TVD 18. Property Designation: , ADL025514, ADL355023, ADL388235 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 533754 y- 6027890 Zone- 4 TPI: x- 534211 y- 6027375 Zone- 4 Total Depth: x- 533727 y- 6018262 Zone- 4 11. Total Depth MD/TVD: 14,000' MD / 3,644' TVD 19. DNR Approval Number: LONS 16-004 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 1,963' MD / 1,856' TVD 5. Directional or Inclination Survey: Yes (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: I N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary DGR Dual Gamma Ray / ABG At -Bit -Gamma Ray / EWR Phase 4 / ADR Azimuthal Deep Resistivity / Wellbore Profile 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 215# X-42 Surface 80 Surface 80 42" 14 yards 9-5/8" 40# L-80 Surface 4,917' Surface 3,857' 12-1/4" Stg 1 L - 280 sx /T - 400 sx �--� Stg 2 L - 550 sx / T - 270 sx 230 bbls - 4-1/2" 13.5# L-80 4,744' 14,000' 3,847' 3,644' 8-1/2" Injection Liner w/ ICDs & Swell Packers _ 24. Open to production or injection? Yes 0 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): Liner Run on 10/30/2019 '"See attached schematic for ICD/Swell Packer Detail" ,,OFAPLETION 4ATE VZOM VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" 4,757' 4,744' MD / 3,847' TVD Liner Top Packer 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No E Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period -00. Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): 7orm 10-407 Revised 5/2017UED ON PAGE 2 CONTI Submit ORIGINIAL only -/�` �' '�BDMS �' NOV 2 7 2019 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� Sidewall Cores: Yes ❑ No E] If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1,963' 1,856' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 4,833' 3,853' information, including reports, per 20 AAC 25.071. SV5 1,343' 1,315' SV1 2,007 1,893' Ugnu LA3 3,386' 3,167' ` SB NA 4,085' 3,679' ` SB OA 4,833' 3,853' " Formation at total depth: SB OA , 31. List of Attachments: Wellbore Schematic, Driling and Completion Reports, Definitive Directional Survey, Casing and Cement Reports Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdingera_hilcofp.com Authorized Contact Phone: 777-8389 Signature: — - Date: j - Z5' . Ct INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. =orm 10-407 Revised 5/2017 Submit ORIGINAL Only Ifilcom Alaska. LLC Schematic Milne Point Unit Well: MPU M-21 PTD: 219-132 API: 50-029-23649-00-00 TREE & WELLHEAD Tree I Cameron 3-1/8" 5M w/ 4-1/16" 5M Cameron Wing Wellhead I Cameron 11" 5K x sliplock bottom w/ (2) 2-1/16" 5K outs OPEN HOLE/ CEMENT DETAIL 42" 14 yards 12-1/4" Stg 1 Lead - 280 sx / Tail - 400 sx Top Stg 2 Lead - 550 sx / Tail - 270 sx 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34" Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TXP 8.679" Surface 4,917' 0.0758 4-1/2" Liner 13.5 / L-80 / Hyd 625 3.795" 4,744' 14,000' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 1 2.867" 1 Surf 1 4,757' 1 0.0870 TD =14,000' (MD) /TD = 3,644'(TVD) PBTD =13,998' (MD) / PBTD = 3,644' (TVD) WELL INCLINATION DETAIL KOP @ 500' Hole Angle @ Liner Top = 86" Max Hole Angle = 97° @ 6,482' MD JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,296' 3-1/2" X Nipple (2.813" Packing Bore) 2.813" 2 4,276' 31/2" XN Nipple (2.813" Packing Bore; 2.75" No -Go) 2.750" 3 4,513' 3-1/2" Gauge Mandrel SGM-F5, XDPG 2.935" 4 4,747' 8.25" No Go Locater sub (1.86" off No Go) 2.980" 5 4,748' 7.38" Tieback above the SLZXP Liner Top Packer (Btm @ 4,757') 2.992" Lower Completion 6 4,744' SLZXP Liner Top Packer 7" X 9-5/8", L-80 (TVD = 3,847') 6.180" 7 13,998' Shoe 3.970" Depth Depth ICD/Swell Packer Detail MD TVD See Pa Le 2 GENERAL WELL INFO API#: 50-029-23649-00-00 Completed by Doyon 14: 11/01/2019 Revised By: DH 11/22/2019 Depth MD Depth ND ICD/Swell Packer Detail 4,940' 3,859' Tendeka Water Swell Packer 5,043' 3,858'• Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,318' 3,855' Tendeka Water Swell Packer 5,586' 3,860' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,695' 3,863' Tendeka Water Swell Packer 6,170' 3,872' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,404' 3,869' Tendeka Water Swell Packer 6,879' 3,828' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,278' 3,794' Tendeka Water Swell Packer 7,423' 3,777' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,700' 3,754' Tendeka Water Swell Packer 8,096' 3,741' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,660' 3,719' Tendeka Water Swell Packer 9,056' 3,709' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,503' 3,681' Tendeka Water Swell Packer 9,854' 3,661' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,169' 3,652' Tendeka Water Swell Packer 10,355' 3,643' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,547' 3,637' Tendeka Water Swell Packer 10,815' 3,637' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,967' 3,638' Tendeka Water Swell Packer 11,443' 3,673' Tendeka Water Swell Packer 11,755' 3,667' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,991' 3,665' Tendeka Water Swell Packer 12,427' 3,653' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,662' 3,639' Tendeka Water Swell Packer 12,723' 3,638' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,914' 3,642' Tendeka Water Swell Packer 13,100' 3,649' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,665' 3,641' Tendeka Water Swell Packer ' 13,726' 3,640'. Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge MPU M-21 schematic 11-22-19 Page 2 of 2 DH 11/22/20019 W1 Well Name: Field: County/State: Location (LAT/LONG): Elevation (RKB): API #: Spud Date: Job Name: Contractor AFE #: AFE $: Hilcorp Energy Company Composite Report MP M-21 Milne Point Alaska 33.87 10/16/2019 1913623D MPU M-21 Drilling Doyon 14 Activity Date Ops Summary 10/15/2019 Freeze protect M-17, blow down & rig down lines and secure well. Rig released from M-17 at 08:OO;Skid rig floor into moving position.;Move rig off M-17. Place matting boards on east side of pad and move rig from south to north side of the pad. Move rig onto M- 21. Spot, level and shim rig. Install handrails on stairs and grating at all landings. Skid rig floor into drilling position.;Skid rig floor into drilling position. Install boiler and air heater exhaust stacks. Sim -ops: spot rock washer into position.;N/U surface diverter system and install diverter lines. 207' total length, 203' from sub -structure and 11 9'from nearest ignition source (air heater). Spot mud man, Sperry, geologist shacks and fuel trailer. Load BHA into the pipe shed and prepare mud pits for fluid.;lnstall riser and bell nipple. Install turn buckles. Finish rig acceptance checklist - rig accepted at midnight. Load pipe shed with 17 joints of 5" drill pipe and 22 joints of 5" drill pipe.;C/O top drive saver sub. Install new saver sub prior to beginning drilling a new well. Load 86 bbls water in to pit #4 and 580 bbls spud mud in the mud pits.;Clear rig floor. M/U two joints of 5" HWDP.•Perform diverter function test on 5" HWDP. Knife valve open in 15 sec. & diverter close in 35 sec. 3000 PSI system pressure, 1850 PSI after closure, 38 sec. 200 PSI recovery, 156 sec. full recovery. 2050 PSI avg - 6 nitrogen bottles. AOGCC inspector Austin McLeod waived witness at 17:25 on 15 Oct.;Prepare pipeshed and rig floor to P/U HWDP. 10/16/2019 M/U & rack back 6 stands of 5" HWDP.;Slip & cut drilling line. 44' of line cut off. Service top drive, draw works and blocks. "" Rig on high line at 08:30 "';Bring BHA #1 tools to rig floor.;Attempt to install mouse hole and had to remove the side flanges on the BOPS to clear.;lnstall Mouse hole. Conduct a full rig evacuation and muster drill. Milne Point Emergency Response came to location also. Crew all in shop in 5 min. accounted for in 9 and full pad accounted for in 17 due to waiting on production to get there hands accounted for. Over all Great drill.;Spent time talking with the crews about lessons learned and also other emergency response team in what the next step would be.;Clean cellar area. Perform Pre spud meeting. PJSM, P/U Motor & bit. Rotary lock would not function to M/U bit.;Remove rotary table cover and found pin had backed out of rotary lock. Had to cut free and replace lock. Then work free. Install cover.;Torque 12-1/4" Kymera bit to 8" mud motor, M/U XO sub & stand of HWDP. Tag fill @ 105'w/ 10K. Fill mud lines & pressure test to 300 PSI low / 3500 PSI high - good. Clean out conductor w/ fresh water f/ 105't/ 114'w/ 450 GPM, 450 PSI, 40 RPM, 1 K TQ, 1 K WOB. Flowline 90% full w/ just water.;Drill 12-1/4" surface hole f/ 114't/ 218', 114' drilled 767hr AROP. Drill 1st 10' with water then swap to spud mud. 450 GPM, 930 PSI, 40 RPM, 1 K TQ, 1 K WOB. 49K PU / 50K SO / 50K ROT.;BROOH f/ 218't/ 123' then pull on elevators to 37'. P/U and inspect bit. Remove gravel lodged in cones of bit.;lnspect flowline, found 25% blocked with dried solids. Clean solids out of the flow line. Jet with 10 BPM, 330 PSI through cement hose down flow line. Utilize breaker bar and pressure washer to dislodge dried solids.;M/U MWD tools (DGR, EWR, directional & PWD) to 90'. Measure TF offset to motor: 142°=318/809'360. Test & initialize MWD tools. M/U three NMDC to 177'. M/U XO and stand of HWDP. Pulse test MWD good. Wash down to bottom with 450 GPM, 730 PSI, 40 RPM, 1 K TQ - no fill observed.;Drill 12-1/4" surface hole f/ 218't/ 639', 421' drilled, 95.567hr AROP. Began 3°/100' build at 454'. 450 GPM, 950 PSI, 40 RPM, 3K TQ, 5-15K WOB. 8.95 ppg MW, 203 vis, 9.55 ECD. 75K PU / 76K SO / 76K ROT.;Last survey at 578.52' MD / 578.46' TVD, 2.99° inc, 25.16° azm, 2.82' from plan, 2.75' high and 0.61' right.; 10/17/2019 Drill 12.25" surface hole f/ 639't/ 1217', 578' drilled, 96.337hr AROP. 510 GPM, 1320 PSI 60 RPM, 4K TQ, 10K WOB. Max gas Ou. 9 ppg MW, 140 vis, 9.71 ECD. 89K PU / 89K SO / 90K ROT.;Drill 12.25" surface hole f/ 1217' t/ 1970', 753' drilled, 125.57hr AROP. 490 GPM, 1380 PSI, 60 RPM, 4K TQ, 8-10K WOB. Max gas 56u. 9.1 ppg MW, 151 vis, 10.02 ECD. 109K PU / 100K SO / 102K ROT. End 3°/100' build at 1834'. Hold 31.5° tangent. Base of permafrost @ 1963' MD / 1856' TVD.;Drill 12.25" surface hole f/ 1970' t/ 2637', 667' drilled, 111.177hr AROP. 500 GPM, 1390 PSI, 60 RPM, 4K TQ, 2K WOB. Max gas 57u. 9.2 ppg MW, 152 vis, 10.02 ECD. 120K PU / 107K SO / 115K ROT. Hi vis sweeps @ 2051' back on strokes w/ 40% inc. & 2541' back on strokes w/ 10% increase.;Begin 5°/100' drop and turn at 2285'.;Dri1112.25" surface hole f/ 2637' t/ 3306', 669' drilled, 111.5'/hr AROP. 525 GPM, 1610 PSI, 60 RPM, 6-7K TQ, 3-12K WOB. Max gas 59u. 9.1 ppg MW, 124 vis, 9.83 ECD. 144K PU / 117K SO / 130K ROT. Begin 5°/100' build and turn at 3112'. Sweep @ 3131' back on strokes w/ 10% increase.;Last survey @ 3241.97' MD / 3034.93' TVD, 19.55° inc, 161.66° azm, 6.34' from plan, 2.15' high and 5.96' left. 10/18/2019 Drill 12.25" surface hole f/ 3306'V 3874', 568' drilled, 94.6771hr AROP. 525 GPM, 1870 PSI, 80 RPM, 10K TQ, 15K WOB. 159K PU / 120K SO / 135K ROT. 9.0 ppg MW, 120 vis, 9.83 ECD, max gas 246u. Added 0.25% ScreenKleen prior to drilling the Ugnu L & M -sands. Top of Ungu L @ 3386'& Ugnu M @ 3691'.;Drill 12.25" surface hole f/ 3874't/ 4540', 666' drilled, 11 17h AROP. 525 GPM, 1860 PSI, 80 RPM, 10K TQ, 5-15K WOB. 155K PU / 110K SO / 130K ROT. 9.1 ppg MW, 65 vis, 9.92 ECD, max gas 860u. Pumped high vis sweep at 4127' back on time w/ no increase. Top of Schrader Bluff N -sands at 4085'.;Drill 12.25" surface hole f/ 4540't/ 4924', 384' drilled, 85.337hr AROP. 525 GPM, 1760 PSI, 60 RPM, 13K TQ, 10-20K WOB. 145K PU / 110K SO / 120K RO. 9.2 ppg MW, 59 vis, 9.92 ECD, max gas 547u.;OA-1 sand top @ 4833' MD / 3852' TVD. TD of surface hole @ 4924' MD / 3857' TVD - Tinto the OA -1. Landed 294' south of the Y- coordinate of 6027603'. Last survey @ 4857.65' MD / 3854.29' TVD, 85.24° inc, 184.20° azm, 7.97' from plan, 0.21' low & 7.96' right.;Pump out f/ 4924't/ 4863' (start of last slide). CBU while reciprocating f/ 4863' U 4826'@ 550 GPM, 1680 PSI, 80 RPM, 8K TQ. Pump 30 bbl low vis then 30 bbl high vis sweeps while reciprocating f/ 4826't/ 4731'. Back 100 strokes late w/ no increase. CBU while reciprocating f/ 4731't/ 4636'.;3.6 total bottoms up pumped while circulating. TIH f/ 4636't/ 4924' with no fill observed. Perform flow check - static.;BROOH f/ 4924't/ 3780', 550 GPM, 1550 PSI, 80 RPM, 7K TQ. 5 min/stand pulling speed, slowing as necessary. 10/19/2019 BROOH F/ 3780'T/ 1778', 550 GPM, 1550 PSI, 80 RPM, 7K TQ. 5 min/stand pulling speed, slowing as necessary through slides. MW in 9.1, MW out 9.4+ ECDs 9.6-10.3. Slow down when ECDs above 10.;BROOH F/ 1778'T/ 733'. , 500- 550 GPM, 1000-1300 PSI, 50- 80 RPM, 5K TQ. 5 min/stand pulling speed, slowing as necessary through slides. MW in 9.1, MW out 9.4+ ECDs 9.6-10.3. Slow down when ECDs above 10. Attempt to pump out and saw over pulls above 50K.; Back ream over pull at 643' then pumped out to 363'. Pulled last three stand HWDP on elevators. BDTD. Monitor Well static. PJSM, UD 3 NMFCD. Hole took calculated hole volume for the trip out.;Down load tools & clean up rig floor. L/D BHA from 77'. Bit Grade 1 -2 -BT -S -E -1 -NO -TD. Clear BHA components and clean rig floor. 3 BPH static losses.;PJSM. Rig up to run 9-5/8" casing. M/U Doyon Volant casing running tool with cement swivel, 4' bail extensions, 9-5/8" elevators, spiders and strap tongs. 3 BPH static losses.;PJSM. M/U 9-5/8" 40# L-80 TXP BTC -SR casing shoe track to 160.89' - float shoe joint, spacer joint, float collarjoint w/ bypass baffle installed and baffle adapter. Thread lock connections & torque to 20,960 ft/lbs with Doyon Volant tool. Check floats - good.;Two 9-5/8"x12-1/4" Expand-o-lizers w/ 4 stop rings installed on shoe joint, one floating on joint #2, one each with two each stop rings on joints #3 & 4. 3 BPH static Iosses.;Run 9-5/8" 40# L-80 TXP BTC -SR casing f/ 160' t/ 2372' Torque to 20,960 ft/lbs with Doyon Volant tool. Fill on the fly & top off every 10 joints. Install 9-5/8"x12-1/4" Expand-o-lizer on each joint from #5 - 25, then every other joint #27 - 59. Losing 3 BPH while running casing.;Stage up pumps in 1 bbl increments to 6 BPM, 140 PSI. CBU while reciprocating 25'. 1717 strokes pumped. 9.35 ppg MW, 40 vis in and 9.45 ppg MW, 59 vis out. 9 bbls lost while circulating.; Run 9-5/8" 40# L-80 TXP BTC -SR casing f/ 2372't/ 3125' Torque to 20,960 ft/lbs with Doyon Volant tool. Fill on the fly & top off every 10 joints. Install 9- 5/8"x12-1/4" Expand-o-lizer on joint #61, every joint #63-72 & every other joint # 74 - 78.;Halliburton ES cementer between joints #68 & 69. Pup joints above and below ES cement have one each 9-5/8"x12-1/4" Expand-o-lizer and stop ring. Losing 2 BPH. 28 bbls daily losses (midnight), 28 bbls cumulative losses. 10/20/2019 Run 9-5/8" 40# L-80 TXP BTC -SR casing F/ 3125'T/ 4924' Wash down last 20' at 2 bpm. tag on depth. Torque to 20,960 fUlbs with Doyon Volant tool. Fill on the fly & top off every 10 joints. Install 9-5/8"x12-1/4" Expand-o-lizer as per tally.;Stage up pumps to 8 bpm while working pipe. up/dn 225/145. Full returns. Circ & condition full circulation while treating mud for cmt job. Work pipe 20-30' while circulating. 9.3 in and out. Not much cuttings just very fine solids. PJSM, Cmt job.;R/U cmt line, Blow down top drive. Verify circ through cmt line with both pumps after pulling suction screens. Good. Line up to HES.and pump 5 bbl H2O. Test lines to 1000/4000 psi. Good. Pump 60 bbl of 10 ppg Tuned spacer with 4# red dye and Pot -E -flake in first 10 bbl.;Drop bypass plug Mix and pump 117 bbl 121b lead cmt at 3-5 bpm (280 SX) Mix and pump 82 bbl of 15.8 Tail cmt at 3-5 bpm (400SX) Drop opening plug_ HFS pump �0 bbl H2o. Line up to 1 rig and displace with 1645 stks. (166 BBL) Line up to HES and mix and pump 83 bbl tuned spacer at 6 bpm.;"` AOGCC notified of upcoming BOP test at 13:39 on 20 Oct 2019 "".;Displace with rig at 6 bpm 9.3 ppg mud. Bump plug 916 strokes. 10 strokes early from calculated. Hold 600 over FCP for 5 min. Good. FCP 610 PSI at 3 bpm. Bleed down and check floats good. Open EScmt tool at 2850 Dsi. Pressure dropped to 250. Stage up pumps to 7 bpm at 300 psi.;Saw Pot -E -flake back at 1200 strokes and mud push at 1600. Dump to rock washer at 2000 strokes and dump 120 bbl total. Got back mud push and trace cmt. We did see a PH of 11.1 from 8. We also seen an increase in MW to 9.6 ppg. Circulate total of 4000 strokes. 2.6 btm ups.;UP/DN 250/145 . ROT 225 at 16-20K TQ. Work pipe & Rot throughout cmt job until last 10 bbl. Worked pipe F/ 250K T/140K while displacing out cmt & spacers. Clean no clambered up mud. Parked pipe in the upstroke @ 4917' with 250K. CIP at 14:20. Trace cmt back.;Shut down and flush out BOPS with black water from hole fill. Flush surface equipment. Line back up and continue to circ through the ES cmt tool at 6 bpm at 196 psi while waiting on next stage. Break out Volant tool, inspect cup & dies - good.;PJSM with Doyon, M-1, Peak, Halliburton and HAK personnel. Blow air through lines to cement unit, batch up spacer. Continue to pump 6 BPM, 230 PSI. 1st stage tail @ 100 PSI compressive strength at 21:38.;Perform 2nd job. stage surface cement Pump 5 bbls 8.34 ppq water 3.5 BPM 168 PSI Mix & pump 60 bbls of 10.0 ppq Tuned Spacer Q 5 BPM 288 PSI with 4# red dye and Pol-E-flake in first 10 bbl..;Mix & pump 452 bbls 10.7 ppg Perm L lead cement (550 sks, 4.407 sk/ft^3 yield) @ 6 BPM, 413 PSI ICP / 485 PSI FCP. Overboard spacer at 218 bbls lead pumped. Observed dyed cement & Pol-E-flake back at 283 bbls lead pumped. 10.6 ppg cement back at 442 bbls lead cement pumped.;Mix & pump 56.2 bbls 15.8 ppg Premium G tail cement (270 sks, 1.169 sk/ft^3 yield) @ 5 BPM, 542 PSI. Pump 20 bbls 8.34 ppg water @ 5 BPM, 237 PSI. Drop closing plug. Displace with 9.4 ppg spud mud from the rig @ 6 BPM, 230 PSI ICP / 580 PSI FCP. Slow to 3 BPM, 380 PSI for last 10 bbls.;Bumped plug 2.73 bbls early @ 1432 stks. CIP @ 00:10. Increase pressure & observe ES cementer shift closed @ 12 I. Continue up to 1610 PSI & hold for 5 min. Bleed off with no flow, verified ES cementer shifted closed. 230.17 bbls cement to surface.:Blow down cement lines. Flush diverter stack with treated black water, cycling annular 3x times. N/D diverter line & knife valve.;Hoist annular. Install casing slips & land casing with 100K on slips. Rough cut casing & UD 16.67' cut joint. Set annular back down on diverter adapter. N/D flow nipple & riser. 10/21/2019 N/D diverter & diverter adapter. Install Cameron T-103 nipple and test to 500 PSI for 5 min & 2475 PSI for 10 min. Install T-103 tubing head and test to 500 PSI for 5 min. & 5000 PSI for 10 min.; Install 4" hydraulic actuated valve on MPD head.;N/U BOP stack, install riser, turnbuckles and kill line.;R/U to test BOP equipment: install test plug and 3-1/2" test joint. Fill stack, choke and all lines with freshwater. Perform shell test, choke line to fig floor leaking at gasket. Blow down and replace Oteco gasket. Refill and perform good shell test.;Test BOP w/ AOGCC inspector Brian Bixbywitnessing testing. Test H2S & LEL gas alarms, PVT & flow - good. All tests performed against a test plug with fresh water for 5 min. each 250 PSI low / 3000 PSI high & charted. #1: Annular on 3.5" test joint, valves 1, 12, 13, 14, 3" kill Demco & upper IBOP.;#2: Upper 2.875"x5" VBR on 3.5" test joint, valves 9, 11, HCR kill & lower IBOP. #3: Valves 5, 8, 10, manual kill & 5" TIW #1 #4: Valves 4, 6, 7 & 5" TIW #2. #5: Valve 2 & 5" dart valve. #6 Lower 3.5"x6" VBR on 3.5" test joint & 4" TIW #7: Upper 2.875"x5" VBR on 5" test joint, HCR choke & 4" dart.;#8: Manual choke #9: Lower 3.5"x6" VBR on 5" test joint. #10: Blind rams & valve 3. #11: Hydraulic choke "A" #12: Hydraulic choke "B" Accumulator test: 3000 PSI system, 1700 PSI after closure, 47 sec. 200 PSI recovery, 197 sec. full recovery, 1966 PSI six bottle nitrogen avg.;Pull trip nipple. Install MPD test cap on MPD head. Test MPD head and 4" hyd. activated valve to 1200 PSI for 5 min. Test MPD lines and manifold to 1200 PSI for 5 min. - good tests. Drain system, pull test plug and re- install trip nipple.; Re -install test joint and pull test plug. Blow down all lines. Install 9" I.D. wear bushing.; Inspect saver sub -good. Mobilize BHA components to the rig floor. M/U BHA #2: new 8-1/2" Smith XR+ bit, and Sperry 6-3/4" mud motor with 1.15° AKO to 32'. TIH f/ 32' out of the derrick with 5" HWDP & 5" DP and tagged cement stringer with 5K at 2187'.;Ream f/ 2187't/ 2205'w/ 470 GPM. 950 GPM, 40 RPM, 4K TQ. Drill ES cementer f/ 2205't/ 2208'w/ 8K WOB. 95K PU / 92K SO 195 ROT. Ream through cementer two time then run through without pumps to 2295'- no drag observed. Blow down top drive.;TIH f/ 2295't/ 4741' on elevators and tagged cement stringer w/ 5K. Rack back stand to 4678'. 160K PU / 84K SO.;R/U test equipment. Fill drill pipe. Close UPR on 5" drill pipe. Purge kill & choke lines with 9.1 ppg spud mud. Pressure test casing to 2600 PSI for 30 min. on chart. Pumped 3.9 6YsJ bled back 3.9 bbls. 0 bbls daily losses, 103 bbls cumulative losses i f' 10/22/2019 R/D test equipment & blow down choke manifold, choke and kill lines. M/U TD.;Wash down f/ 4678', drill cement f/ 4741', drill BA on depth @ 4795', drill out 9 5/8" shoe track to 4917', cleanout rathole and drill 20' new formation to 4944'600 gpm, 1790 psi, 40 rpm, 5-10k tq, 10- 15k wob.;Circulate and condition mud for FIT 595 gpm, 1710 psi, 40 rpm, 10k tq, with good 9.1 ppg MW in/out. Pull into 9 5/8" casing. PU/180K, SO/107K.;Parked @ 4865', R/U test equipment, close UPR, purge air from lines, Perform FIT to 12 ppg with existing 9.1 ppg MW, apply 581 psi, bleed off pressure, open UPR, BD, R/D test equipment. Good test. 1.5 BBLS pumped, 1.5 bbls bled back.;Flow check well, static, POOH on elevators racking back 5" DP f/ 4865' to 585'. Correct displacement on TOOH.;Lay down 15 jts 5" HWDP, Rack jar stand in Derrick, Drain motor, L/D remaining BHA. 8-1/2 tri -cone bit grade= 1-1-WT-A-E-I-NO-BHA.;Clear and clean the rig floor, Mobilize RSS BHA components to the rig floor. Install split bushings. Monitor well, static.;Hold PJSM. M/U 8-1/2" production drilling BHA #3 to 84': SK616MJ1D bit, NRP sleeve, Geo -Pilot, MWD (ADR/ILS/DGR/PWD/DM/TM) initialize tools. M/U 2 float subs, TIH w/ 3 NM flex collars, HWDP, jars & 1 stand drill pipe to 366'. Pulse test MWD 450 GPM, 840 PSI - good. Blow down top drive.;TIH f/ 366't/ 2175'. Fill pipe and break in Geo -Pilot seals, 500 GPM, 2230 PSI, 60 RPM, 2K TQ. Blow down top drive. Kick while tripping drill - 80 sec. well secure and 120 sec. all hands responded.;Continue to TIH f/ 2175't/ 4554'. Fill pipe & reduce volume in pit #4. Pick up singles from the pipe shed f/ 4554' U 4901'. 160K PU / 92K SO.;PJSM. Remove trip nipple and install MPD RCD. Fill lines, no leaks. Pump 3 BPM, 140 PSI. Remove short mousehole and install 90' mousehole. Install drip pan on BOP stack.;PJSM for displacement. Pick up singles f/ 4901' U 4944'. Pump 30 bbl Hi -Vis spacer followed by 8.8 ppg Flo -Pro NT mud w/ 1 % Lo -Torg @ 8 BPM, 670 PSI, 60 RPM, 10K TQ. Rotate 60 RPM & reciprocate 30'. 160K PU / 92K SO / 112K ROT.;Good clean mud back, shut down, UD single & rack a stand back to 4839'. Shut MPD choke, monitor well - static.;PJSM. Slip and cut drilling line - 34' of line cut. Service rig: grease blocks, top drive & draw works. Check accumulator pressure on top drive. Check bolt torque on top drive lock rings. Pump 2 BPM, 100 PSI to keep top drive & MPD lines warm. 10/23/2019 Drill 8-1/2" lateral f/ 4944' t/ 5679', 735' drilled, 122.57hr AROP. 500 GPM, 1280 PSI, 120 RPM, 10-12K TQ, 10-12K WOB. 8.9 ppg MW, 37 vis, 9.6 ECD, 459u max gas 153K PU / 93K SO / 120K ROT.;Pump 30 bbl hi vis sweep @ 5540', sweep back on time w/ 20% increase. Drill in the OA -1, undulate down to OA -3 @ 5409' Entered OA -2 @ 5653' md, 3862' tvd.;Drill 8-1/2" lateral f/ 5679't/ 6457', 778' drilled, 129.6'/hr AROP. 525 GPM, 1490 PSI, 120 RPM, 15K TQ, 10-15K WOB. 8.9 ppg MW, 43 vis, 10.1 ECD, 503u max gas 170K PU / 74K SO/ 118K ROT,.; Enter OA -3 @ 5858' md, 3839' tvd, encounter fault #1 at 6345' and (11' DTN), buildup to 97 deg to re-claim OA -sand. Pump 30 bbl hi vis sweep @ 5980', back on time with 100% increase; Drill 8-1/2" lateral f/ 6457' t/ 7040', 583' drilled, 97.2'/hr AROP. 525 GPM, 1610 PSI, 120 RPM, 13K TQ, 10-15K WOB. 8.8 ppg MW, 49 vis, 10.6 ECD, 656u max gas. 165K PU / 65K SO / 118K ROT. Sweep at 6552' on time w/ 100% inc. Re-entered OA sands @ 6475' MD, 3854' TVD & OA -3 at 6552' MD, 3805' TVD.;Drill 8-1/2" lateral f/ 7040't/ 7883', 843' drilled, 140.57hr AROP. 525 GPM, 1730 PSI, 120 RPM, 14K TQ, 10-15K WOB. 9.1 ppg MW, 45 vis, 10.78 ECD, 1436u max gas. 175K PU / no SO / 105K ROT. Lost slack off weight @ 7788'. 30 bbl sweep @ 7500 back on time w/ 100% increase.;Began planned undulation to OA -1 at 7217'. Crossed OA -2 @ 7170' MD, 3805' TVD & entered OA -1 @ 7370' MD, 3783' TVD. Encountered OA -2 @ 7580' MD, 3762' TVD then began planned undulation down to OA -3. Entered OA -3 @ 7830' MD, 3749' TVD.;Last survey at 7743.88' MD / 3752.49' TVD, 93.96° inc, 183.33° azm, 5.27' from plan, 1.44' high & 5.07' right' Drilled 9 concretions for a total thickness of 47'(1.7% of the lateral). 10/24/2019 Drill 8-1/2" lateral f/ 7883' U 8265', 382' drilled, 109.1'/hr AROP. 529 GPM, 1710 PSI, 120 RPM, 14K TQ, 7-10K WOB. 9.1 ppg MW, 47 vis, 10.6 ECD, 3445u max gas. 188K PU / no SO / 107K ROT.;Pump 30 bbl hi vis sweep @ 7988', back on time with 25% increase. Drill in OA-3.;After making connection Sperry detection server locked up, unable to read tools, rack back stand to have room to rotate and work pipe, troubleshoot and get detection server operating, M/U std. Rotate 120 rpm, 14k tq, 540 gpm, 1730 psi, reciprocating pipe 90', seen gas spike 3380u. BGG 43u.;Drill 8-1/2" lateral f/ 8265' to 8359', 94' drilled, 1887hr AROP. Drill in OA -3. 548 GPM, 1710 PSI, 120 RPM, 14K TQ, 7-10K WOB. 9.1 ppg MW, 47 vis, 10.6 ECD, 570u max gas. 188K PU / no SO / 107K ROT.;Sperry depth not tracking on computer, troubleshoot MWD computer, depth tracking, Pump 400 gpm, 1200 psi, 60 rpm, 13k tq, reciprocate pipe.;Drill 8-1/2" lateral f/ 8359' to 9026', 667' drilled, 111.27hr AROP. 553 GPM, 1820 PSI, 120 RPM, 13-15K TQ, 10-15K WOB. 9.1 ppg MW, 47 vis, 10.6 ECD, 737u max gas. 185K PU / 50K SO / 118K ROT.;Pump 30 bbl hi vis sweep @ 8549', back on time with 20% increase. Pump 30 bbls hi vis sweep @ 9016', 50 stks late with 50% increase. Continue to drill in OA-3.;Drill 8-1/2" lateral f/ 9026' to 9883', 857' drilled, 142.87hr AROP. 550 GPM, 1990 PSI, 120 RPM, 18K TQ, 10-12K WOB. 8.95 ppg MW, 45 vis, 11.0 ECD, 741u max gas. 205K PU / no SO / 100K ROT. Entered OA -2 @ 9410' MD / 3688' TVD & OA -1 @ 9600' MD / 3674' TVD.;MPD choke full open while drilling 60 PSI friction loss, 51 PSI shut in.;Drill 8- 1/2" lateral f/ 9883't/ 10437', 554' drilled, 92.37hr AROP. 550 GPM, 2070 PSI, 120 RPM, 20K TQ, 5-15K WOB. 8.95 ppg MW, 43 vis, 10.86 ECD, 512u max gas. 225K PU / no SO / 103K ROT.;Drilled 19 concretions for a total thickness of 124'(2.2% of the lateral). MPD choke full open while drilling 60 PSI friction loss, 48 PSI shut in. Last survey @ 10290.12' MD / 3645.40' TVD, 92.23° inc, 184.78° azm, 44.27' from plan, 43.35' low & 8.94' right. 10/25/2019 Drill 8-1/2" lateral f/ 10437't/ 10836', 399' drilled, 66.5'/hr AROP. 550 GPM, 2050 PSI, 110 RPM, 20K TQ, 10-15K WOB. 9 ppg MW, 42 vis, 11 ECD, 312u max gas. 200K PU / no SO / 112K ROT.;MPD choke full open while drilling 60 PSI friction loss, avg 30 PSI shut in. Pump 30 bbl hi vis sweep @ 10550', back 100 stks late, 25% increase. Drill in the OA -1 steering down aim for 90 deg inc.;Drill 8-1/2" lateral f/ 10836't/ 11433', 597' drilled, 99.57hr AROP. 550 GPM, 1900 PSI, 110 RPM, 20K TQ, 10-15K WOB. 9 ppg MW, 49 vis, 11.7 ECD, 152u max gas. 205K PU / no SO / 105K ROT. MPD choke full open while drilling 60 PSI friction loss, avg 42 PSI shut in.;Continue to drill in the OA -1 steering down & target 90 deg inc, encounter fault #2 @ 10935' MD / 3637' TVD ( 82' DTS ) drilling shale above OA sand, target 85 deg inc. Pump 30 bbl hi vis sweep @ 11026', back on time, 50% increase. Entered SB OA -1 sand at 11487' MD / 3675' TVD, 552' out of zone.;Drill 8-1/2" lateral f/ 11433't/ 11978', 545' drilled, 90.87hr AROP. 500 GPM, 1900 PSI, 120 RPM, 21 K TQ, 10K WOB. 9.1 ppg MW, 50 vis, 11.4 ECD, 642u max gas. 200K PU / no SO / 105K ROT. Pump 30 bbl hi vis sweep @ 11504', back on time, 50% increase. Entered OA -2 at 11955' MD / 3607' TVD.;MPD choke full open while drilling 60 PSI friction loss, avg 44 PSI shut in. Performed 290 bbl dump and dilute at 11597'.;Drill 8-1/2" lateral f/ 11978' t/ 12535', 557' drilled, 92.87hr AROP. 500 GPM, 1990 PSI, 110 RPM, 23K TQ, 10- 17K WOB. 9.2 ppg MW, 42 vis, 11.38 ECD, 389u max gas. 205K PU / no SO /105K ROT. Pump 30 bbl hi vis sweep @ 12073', back 200 strokes late w/ 20% increase.; Entered OA -3 @ 12065' MD / 3606' TVD. MPD choke full open while drilling 60 PSI friction loss, avg 46 PSI shut in. Last survey @ 12383.52' MD / 3655.70' TVD, 93.47° inc, 188.49° azm, 40.29' from plan, 38.13' low & 13.01' right. Drilled 36 concretions: total thickness of 254' (3.4% of the lateral). 10/26/2019 Drill 8-1/2" lateral f/ 12535't/ 12984', 449' drilled, 74.87hr AROP. 500 GPM, 2050 PSI, 120 RPM, 23K TQ, 12K WOB. 9.1 ppg MW, 42 vis, 11.4 ECD, 313u max gas. 205K PU / no SO /105K ROT. MPD choke open drlg, closed on connections building to 50-60 psi.;Drill in the OA -3 target 93.5 deg, encounter fault #3 @ 12621' MD w/ 29' DTS throw putting us in the top of OA -1, at 12768' encounter fault #4 w/ 13' DTS throw putting us in the shale above OA -sand, target 87 deg. Pump 30 bbl hi vis sweep @ 12740', back on time, no increase.;Drill 8- 1/2" lateral f/ 12984't/ 13562', 578' drilled, 963/hr AROP. 497 GPM, 2070 PSI, 120 RPM, 24K TQ, 11 K WOB. 9.2 ppg MW, 42 vis, 11.5 ECD, 289u max gas. 205K PU / no SO /110K ROT. MPD choke open drlg, closed on connections building to 30-40 psi.;Continue to target 87°, back in OA -1 @ 12987', out of zone 219', encounter fault #5 @ 13158 w/ 24' DTN throw, enter shale below OA -4 @ 13325', target 94° to reclaim OA -3. At 13322' dump and dilute with 290 bbls new 8.8 ppg flo-pro mud. Entered OA sands at 13445', 120' out of zone and OA - 3 at 13532'.;Drill 8-1/2" lateral f/ 13562't/ 14000', 438' drilled, 973/hr AROP. TD of production hole called by geologist. 500 GPM, 2130 PSI, 110 RPM, 26K TQ, 6K WOB. 9.2 ppg MW, 43 vis, 11.7 ECD, 351u max gas. MPD choke open drlg, closed on connections building to 50-60 psi. Remained in OA -3 .;Obtain final survey @ 13931.09' MD / 3642.96' TVD, 88.83° inc, 183.04' azm, 47.56' from plan, 47.10' low and 6.57' left. 48 concretions were drilled in the lateral, for a total thickness of 392' (4.3%). Five faults were crossed in the lateral. 1021' total footage drilled out of zone.;Pump 30 bbl low vis / hi vis tandem sweeps. 500 GPM, 2190 PSI, 110 RPM, 25K TQ. Back 200 stks late w/ no increase. Reciprocate pipe & rack back a stand every bottoms up to 13630'. Circulated a total of 4.8 bottoms up. Prepare mud pits, empty & clean pit #4 & 5. Fill pit #4 & 5 w/ seawater.;Mix hi -vis spacer in the pill pit, Mix 100 bbls SAPP pill in pit #4. Conduct PJSM for displacement. Ream back to bottom w/ 335 GPM, 1230 PSI, 40 RPM, 19K TQ due to no slack -off weight.;Pump SAPP chemical train: 30 bbl hi -vis spacer, 40 bbls seawater, 30 bbls SAPP pill #1, 40 bbls seawater, 30 bbls SAPP pill #2, 40 bbls seawater, 30 bbls SAPP pill #3, 40 bbls seawater and 30 bbl hi -vis spacer. 260 GPM, 980 PSI, 50-100 RPM, 24K TQ 10/27/2019 Displace wellbore w/ 1039 bbls 4% lube (2% Lube 776 & 2% Lo-Torq) 8.45 ppg 2% KCI brine, 8 BPM, 1100 PSI ICP, 1000 PSI FCP, 80 RPM, 24k Tq start -13K Tq final, continue to circ, no losses displacing. Perform PST tests: 8.25 sec avg x 3 tests in & 8.27 sec avg x 3 tests out.;UD single parking @ 13974' Monitor well with MPD closed choke. Bleed off and monitor for 5 min. Initial pressure build to 63 psi, bleed off, final build to 57 psi, M/U single, wash back to bttm. PU 165K, SO 65K, ROT 113K after displacing, obtain new SPRs;BROOH f/ 14000't/ 13556' at 5/10 min/std, 500 GPM, 1480 psi, 120 RPM, 14K Tq, UD 5" DP breaking down stds in mouse hole while BR. MPD choke fully open BR, hold 60 psi during connections.;BROOH f/ 13556't/ 11 218'at 5/10 min/std, 500 GPM, 1480 psi, 110 RPM, 15K Tq, UD 5" DP breaking down stds in mouse hole while BR. MPD choke fully open BR, hold 60-90 psi during connections. 180 PU / no SO / 115K ROT. Brine wt in/out 8.7 ppg.;BROOH f/ 11218't/ 8932' at 5/15 min/std, 500 GPM, 1440 psi, 110 RPM, 10K Tq, UD 5" DP breaking down stds in mouse hole while BR. MPD choke fully open BR, hold 50-90 psi during connections. 145K PU / no SO / 115K ROT. Brine wt in 8.7 ppg /out 8.75 ppg.;BROOH f/ 8932't/ 6926' at 5/15 min/std, 520 GPM, 1430 PSI, 120 RPM, 7K TQ. MPD choke fully open BR, hold 50-90 psi during connections. 155K PU / 90K SO / 120K ROT. Brine wt in 8.7 ppg / out 8.75 ppg. 10/28/2019 BROOH f/ 6926' t/ 4917' @ csg shoe, pulling 5/10 min/std, 520 GPM, 1350 PSI, 120 RPM, 6K TQ. ( slow to 60 RPM pulling BHA thru shoe ) UD 5 DP while BROOK MPD choke fully open BR, hold 50-90 psi during connections. Brine wt in 8.9 ppg / out 8.9 ppg, 33 bbl loss BR to shoe.;4915' pump 30 bbl hi vis sweep, circulate sweep around cleaning up 9 5/8" csg, 500 gpm, 1170 psi, 40 rpm, 3-4k TQ. working pipe 75', sweep back on time w/ no increase. Circulate 2 BU total, 8.9 ppg in/ out. PU 135K, SO 105K, ROT 105K.;Shut down pumps, monitor well with MPD, 11 psi start, 5 min build to 49 psi, bleed off w/ 2" steady flow, shut in, perform several times with final flowing 1/4" stream, shut in building to 26 psi. Total .5 bbl bled back.;PJSM. Weight up active pit and circulate 9 ppg mud around cap the well f/ shoe up 500 GPM - 1170 psi, 40 RPM - 2k Tq. Rot & Recip string 75'., flow check well 15 min, continues to flow f/ 1" stream receding to 1/4" stream, continue to wt up to 9.1 ppg 360 gpm, 630 psi.;Good 9.1 ppg brine in / out. Monitor for flow, 1/4 BPH slight flow initially slowed to static in 15 min. 18 bbls lost while weighting up.;PJSM. Remove MPD RCD and install trip nipple. Rack stand back, install FOSV & 5' pup joint. Losing 1.5 BPH static losses. 3 bbls Iost.;Slip and cut 53' of drilling line. Inspect drawwork brake bands. Grease top drive & check oil. Losing 1.5 BPH static losses. 3 bbls Iost.;Pump 25 bbls 10.3 ppg dry job. Blow down top drive. POOH racking back 5" drill pipe in the derrick f/ 4839'V 271'. 135K PU / 125K SO. 11.1 bbls Iost.;Perform flow check - slight losses. PJSM. UD 2 joints, HWDP, jars, two float subs and three NMDC to 83'. Read MWD tools. Unable to read logging data, will read in the pipe shed. UD MWD, Geo -pilot and bit from 83'. No unusual wear on BHA. Bit graded: 3 -3 -BT -A -X-1 -WT-TD.; 1.75 BPH static losses while reading MWD tools. 18.2 bbl lost for entire trip out from the shoe. 10/29/2019 Clear rig floor. Mobilize 4-1/2" casing equipment to the rig floor. R/U elevators, slips and Doyon casing double stack tongs. Ready safety joint with XOs and FOSV, set in short mouse hole. 1.5 BPH loss rate.;PJSM. P/U 4-1/2" shoe ( float shoe w/ ports welded closed ) tubing joint w/ 2 each 7.1" centralizers,. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 43't/ 1215'. TQ to 9600 ft/lbs, install 1 stop ring & 7.5" centralizer on ea. jt. Ensure pipe is auto filling. 2 bph loss rate.;Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 1215't/ 4880'. Tq to 9600 ft/lbs, install 1 stop ring & 7.5" centralizer on ea. jt. P/U 90k, S/O 85k. 2 bph loss rate. Submitted 24 hr notice for MIT Test to AOGCC.;Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 4880't/ 9230'. Tq to 9600 fUlbs, install 1 stop ring & 7.5" centralizer on ea. jt 2 bph loss rate.;M/U Baker 7"x9-5/8" SLZXP liner top packer w/ 7.375" seal bore 7" x 9-5/8". Hyd setting tool - 8x 1/2" screws set at 2648 psi, 15% Brass.;RIH w/ 4-1/2" liner on 5" HWDP to 9350', 118K PU / 75K SO. Obtain parameters: Pump 3 BPM - 430 psi, 1 BPM - 140 psi, 10 RPM - 5K Tq.;RIH w/ 4-1/2" injection liner on 5" HWDP stands f/ 9350'V 11897'. Fill pipe on the fly and top off every 3 stands. 2 bph loss rate. P/U 175k, S/O 130k. 10/30/2019 RIH w/ 4-1/2" injection liner on 5" HWDP sin lyes f/ 11 897' V 13926'. Drift and M/U stand DP and TD, RIH tag TD on depth 14000', set down 15k to verify TD ( verify HWDP count 151 jts and 3 jts out ) Fill pipe on the fly and top off every 3 stands ran. 2 bph loss rate. P/U 263k, S/O 100k.;P/U to 13982', breakout single, drop 29/32" phenolic ball, M/U TD, RIH tag TD, P/U to 250k putting string in tension, 35 bbl losses TIH with HWDP.;R/U test pump and chart recorder. Pump down at 3 BPM, 640 PSI. Slow to 2 BPM, 500 PSI for last 100 strokes. Ball on seat at 385 strokes. Pressure up to 2500 psi and set packer. Pressure to 2800 psi hold 5 min. Continue to pressure up to 3800 psi with rig pumps then swap over to test pump.;Pressure up to neutralize pusher tool @ 4500 PSI w/ test pump. Pressure bleed off indicating circ sub opened. Bleed off shut in pump pressure, S/O putting tool in compression and attempt to pick up 5' to confirm release, pusher tool did not release.;S/O to 163k, break out TD, Drop 1.5" phenolic ball, M/U TD. Put string in tension @ 225k, pump ball on seat 2.5 bpm, 800 psi, slow to 2 bpm, slight pressure increase @ 300 stks, pump DP volume, ball did not seat. Perform secondary release procedure.; apply 1 turn to the left, 4.6k tq, work string f/ 150k to 250k, observed set down shear, verify relase w/ 180k SO and 220k PU.;Close bag & test 9 5/8" annulus x 7" x 9-5/8" packer to 1580 psi for 10 min, good, bleed off to 500 psi, back off annular pressure, strip out 9' until pressure drop observed, open bag. TOL @ 4744'.;POOH to 4670' rack back std 5" DP, BD TD. Flow check well, slight losses, TOOH UD 5" HWDP to the shed ( 151 joints ). Lay down Liner packer running tool. 7.5 bbls total loss on trip out of hole.;Clear and clean rig floor, Lay down 4.5" handling equipment. Change out master bushings. Blow down Choke.;Drain Stack & pull wear bushing. Perform dummy run with 3.5" hanger. Install wear bushing.;M/U 3 1/2" perforated clean-out tool with 8.25" no-go and XO, TIH with stands 5" DP V 2395'. 88k PU, 88k SO.;See completions report for remainder of daily activity. I Tl Well Name: Field: County/State: Location (LAT/LONG): Elevation (RKB): API #: Spud Date: Job Name: Contractor AFE #: AFE $: Hilcorp Energy Company Composite Report MP M-21 Milne Point Alaska 33.87 10/16/2019 1913623C MPU M-21 Completion Doyon 14 Activity Date Ops Summary 10/30/2019 See drilling report for previous activity, Run in hole with 3-1/2" wash tool and 8.25" no-go on 5" DP f/ 2395' t/ 4679'. M/U TopDrive to a stand of 5" DP. RIH tag up no-go at 4744'w/ 5k. PU 130K, SO 120K., Pull wash tool above TOL. Pump 500 GPM - 400 psi, 40 RPM - 3k Tq. 100% increase in sand with bottoms up, cleaning up with second bottoms up. Hold PJSM with crew on displacing to 9.1 ppg clean brine. No losses recorded while circulating., Pump 30 bbl hi vis spacer, Displace w/ 455 bbls clean 9.1 ppg brine 6 bpm, 150 psi. 40 rpm, 3k torque reciprocating pipe, take dirty returns to rock washer, pumped 130 bbls over calculated displacement until clean returns. No Iosses.,Get new SPRs, Flow check well, static. L/D 1 single BD TD.,PJSM, POOH L/D 5" drill pipe to shed f/ 4707' to 3767'. Losses at 0.5 BPH. 10/31/2019 POOH L/D 5" drill pipe to shed f/ 3767' to surface, UD no go and wash tool. Losses at 0.5 BPH. 5.2 bbl losses. AOGCC Rep Matt Herrera waived witness of upcoming MIT 10/31/2019 at 06:21., Pull 9" ID wear bushing. Load tools to rig floor, R/U to run 3 1/2" upper completion, ready crossover on FOSV, hang sheave, R/U SLB spool with tech -wire on rig floor. Static loss rate 1 bph.,PJSM with all parties involved. review well control plan w/ tech wire across BOPS. P/U and run Baker bullet seal assembly, 7 jts. of 3-1/2" tubing to 233'. Torque to 3200 ft/lbs Doyon double tongs. 1 BPH loss test., Install SLB 2 1 below, installing with stack rate.- good gauge with pups above and while gauge bolt snapped, remove broken bolt, dress threads and assemble same, pressure test to 5000 PSI for 5 min.,Run 3-1/2" 9.3# L-80 EUE tubing f/ 256't/ 4740' at jt 152, Torque to 3100 ft/lbs with Doyon double stack tongs. Install cross coupler Cannon clamp on every joint to w secure TEC wire. Continuous monitoring of gauge while running. 1 BPH Iosses.,M/U jt 153, RIH and no go out 19' in @ 4759'. Saw good t p indication of seals engaging, set down 5K. Space out. UD 3 joints and M/U space out pups. 6.10' & 6.08'. M/U joint #151 & RIH. Up/Dn .�►1 ` 7 75/70K with blocks at 40K. M/U hanger and landing joint. 11 bbls loss on TIH with 3-1/2" completion tubing. 138 Full Cannon clamps and 1 h `� centralized clamp ran.,SLB get final reading and terminate tech wire to hanger. Drain stack RIH with hanger to 2' above landing mark. R/U, JJJ circ sub and 5' pup jt. close bag and pressure up to 400 psi. P/U until pressure dumped plus 6".,PJSM with Doyon, M-1 and Peak. Test lines to 1000 psi. Reverse circulate 143 bbls corrosion inhibited 9.1 ppg brine @ 4 BPM, 560 PSI, Pump down OA taking returns out of the 3 1/2" tbg, Lineup and reverse circ 160 bbls diesel from vac truck 4 bpm, 530 psi ICP freeze protecting 9 5/8" x 3 1/2" annulus to 2500' FCP 780 psi, S/O closing ports, drain stack to cellar. Land hanger w/ 30k on Hanger, RILDS.,R/D lines f/ pump in sub and XO, R/U test equipment, pre-injection MIT 3 1/2" x 9 5/8" annulus with diesel to 2500 psi for 30 charted min. Good test bleed off pressure. AOGCC representative Matt Herrera waived witness of the test.,R/D test equipment, blow down lines, back out and L/D landing jt, WH rep install S BPV and dart. L/D mouse holes., KCL viscosified brine w/ 4% lube cumulative losses to formation = 191 bbls. Daily (midnight) 2% KCL �L brine losses to formation = 20 bbls cumulative losses for interval = 20 bbls.,Hauled 0 bbls H2O from L -Pad Lake for total = 430 bbls 11/1/2019 WH rep finish installing BPV and dart. L/D mouse holes.,PJSM, N/D BOP stack and rack on stump. Remove MPD choke line f/ cellar. Clean cellar box, Empty and clean pits. SLB perform downhole gauge test. Swap from Hi -line to Gen power @ 09:15, Hilcorp electricians R/D Hi -line cable from back of rig, stage adaptor and tree behind rig **Submitted Notification to AOGCC for upcoming Diverter Test on M- 15 at 08:22.**,Set adapter flange and tree on wellhead, SLB rep terminate tech wire to adapter flange, take final reading, ( pressure 1764.92 psi, temp 73.92° ) N/U adapter flange and tree, WH rep test hanger void to 500 psi f/ 5 min, 5000 psi f/ 10 min.,R/U test equipment, test tree with diesel to 250/5000 psi 5 min each, 1st attempt flange between wing and master slightly weeping, torque same, good test, charted. R/U to freeze protect 3-1/2" tubing.,PJSM. Bullhead 23 bbls diesel down tubing through BPV @ 2 bpm. ICP 510 & FCP 980 psi. freeze protecting tbg to 2500'. Flush lines with water, pump out cutting box, blow down line and rig down lines. Clean wellhead and cellar box. Release rig at 19:OO.,See MPU M-15 for details. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M -21i 500292364900 Sperry Drilling Definitive Survey Report 30 October, 2019 Sperry Drininq Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -21i Project: Milne Point TVD Reference: MPU M-21 Actual RKB @ 58.87usft Site: M Pt Moose Pad MD Reference: MPU M-21 Actual RKB @ 58.87usft Well: MPU M -21i North Reference: True Wellbore: MPU M -21i Survey Calculation Method: Minimum Curvature Design: MPU M -21i Database: NORTH US + CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M -21i Map Map Vertical Well Position +N/ -S 0.00 usft Northing: Easting 6,027,889.77 usf Latitude: 70° 29' 14.007 N (usft) +E/ -W 0.00 usft Easting: (ft) 533,753.82 usf Longitude: 149° 43'26.812 W Position Uncertainty 0.50 usft Wellhead Elevation: 6,027,889.77 0.00 usf Ground Level: 25.00 usft Wellbore MPU M -21i -0.03 6,027,889.90 533,753.79 0.05 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 0.23 -0.26 3_MWD+IFR2+MS+Sag (1) 0.25 0.36 6,027,890.02 (nT) 0.17 BGGM2018 10/16/2019 0.86 16.41 80.94 57,410.66345537 Design MPU M -21i 3.74 2.29 6,027,893.52 533,756.09 Audit Notes: -3.87 3_MWD+IFR2+MS+Sag (1) 10.74 5.29 6,027,900.54 533,759.06 Version: 1.0 Phase: ACTUAL Tie On Depth: 33.87 Vertical Section: 2.35 Depth From (TVD) +N/ -S +E/ -W Direction 533,769.07 3.24 (usft) (usft) (usft) (°) 533,776.12 2.64 33.87 0.00 0.00 183.40 Survey Program Date 10/28/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 209.28 4,857.65 MPU M-21 MWD+IFR2+MS+Sag (1) (MF 3_MWD+IFR2+MS+Sag H081 Ma: IIFR dec & multi -station analysis + se 10/16/2019 4,957.59 13,931.09 MPU M-21 MWD+IFR2+MS+Sag (2) (MF 3_MWD+IFR2+MS+Sag H081 Ma: IIFR dec & multi -station analysis + sa 10/23/2019 Survey MD Inc Azi TVD TVDSS (usft) (1 (°) (usft) (usft) 33.87 0.00 0.00 33.87 -25.00 209.28 0.09 348.02 209.28 150.41 299.11 0.20 70.57 299.11 240.24 392.60 0.14 121.62 392.60 333.73 486.17 0.98 30.70 486.16 427.29 578.52 2.99 25.16 578.45 519.58 671.08 6.46 22.30 670.69 611.82 765.99 8.68 20.63 764.76 705.89 861.20 11.74 18.39 858.45 799.58 956.55 14.22 20.36 951.36 892.49 1,051.50 16.39 20.14 1,042.94 984.07 1,146.78 20.00 20.51 1,133.44 1,074.57 1,242.08 22.62 21.15 1,222.22 1,163.35 10/30/2019 12:20:51 PM Map Map Vertical +N/ -S +E/ -W Northing Easting DLS Section (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 UNDEFINED 0.13 -0.03 6,027,889.90 533,753.79 0.05 -0.13 3_MWD+IFR2+MS+Sag (1) 0.26 0.10 6,027,890.03 533,753.92 0.23 -0.26 3_MWD+IFR2+MS+Sag (1) 0.25 0.36 6,027,890.02 533,754.17 0.17 -0.27 3_MWD+IFR2+MS+Sag (1) 0.88 0.86 6,027,890.65 533,754.68 1.06 -0.93 3_MWD+IFR2+MS+Sag (1) 3.74 2.29 6,027,893.52 533,756.09 2.18 -3.87 3_MWD+IFR2+MS+Sag (1) 10.74 5.29 6,027,900.54 533,759.06 3.76 -11.04 3_MWD+IFR2+MS+Sag (1) 22.39 9.84 6,027,912.20 533,763.56 2.35 -22.93 3_MWD+IFR2+MS+Sag (1) 38.31 15.43 6,027,928.14 533,769.07 3.24 -39.15 3_MWD+IFR2+MS+Sag (1) 58.49 22.57 6,027,948.36 533,776.12 2.64 -59.73 3_MWD+IFR2+MS+Sag (1) 82.01 31.24 6,027,971.91 533,784.68 2.29 -83.71 3_MWD+IFR2+MS+Sag (1) 109.90 41.58 6,027,999.84 533,794.89 3.79 -112.17 3_MWD+IFR2+MS+Sag (1) 142.26 53.90 6,028,032.26 533,807.07 2.76 -145.21 3_MWD+IFR2+MS+Sag (1) Page 2 COMPASS 5000.15 Build 91 10/302019 12:20:51PM Page 3 COMPASS 5000.15 Build 91 i Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU Mi-21i Project: Milne Point TVD Reference: MPU M-21 Actual RKB @ 58.87usft Site: M Pt Moose Pad MD Reference: MPU M-21 Actual RKB @ 58.87usft Well: MPU M-21i North Reference: True Wellbore: MPU M-21 i Survey Calculation Method: Minimum Curvature Design: MPU M-21i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,337.38 24.84 22.01 1,309.45 1,250.58 177.92 68.02 6,028,067.97 533,821.02 2.36 -181.64 3_MWD+IFR2+MS+Sag (1) 1,432.07 25.73 22.17 1,395.07 1,336.20 215.39 83.23 6,028,105.51 533,836.06 0.94 -219.95 3_MWD+IFR2+MS+Sag (1) 1,527.74 28.82 21.61 1,480.09 1,421.22 256.07 99.56 6,028,146.26 533,852.21 3.24 -261.52 3_MWD+IFR2+MS+Sag (1) 1,623.15 29.14 22.90 1,563.56 1,504.69 298.85 117.07 6,028,189.12 533,869.52 0.74 -305.27 3_MWD+IFR2+MS+Sag (1) 1,718.12 29.57 21.04 1,646.34 1,587.47 342.02 134.48 6,028,232.36 533,886.74 1.06 -349.40 3_MWD+IFR2+MS+Sag (1) 1,811.29 31.44 19.62 1,726.61 1,667.74 386.37 150.90 6,028,276.78 533,902.95 2.15 -394.64 3_MWD+IFR2+MS+Sag (1) 1,904.51 31.11 19.65 1,806.28 1,747.41 431.95 167.16 6,028,322.43 533,919.00 0.35 -441.10 3_MWD+IFR2+MS+Sag (1) 2,002.67 32.72 19.90 1,889.60 1,830.73 480.78 184.72 6,028,371.34 533,936.33 1.65 -490.89 3_MWD+IFR2+MS+Sag (1) 2,098.19 32.10 20.33 1,970.24 1,911.37 528.86 202.32 6,028,419.49 533,953.72 0.69 -539.92 3_MWD+IFR2+MS+Sag (1) 2,193.46 32.17 21.06 2,050.91 1,992.04 576.26 220.23 6,028,466.97 533,971.41 0.41 -588.31 3_MWD+IFR2+MS+Sag (1) 2,288.16 31.42 21.51 2,131.40 2,072.53 622.75 238.34 6,028,513.54 533,989.31 0.83 -635.79 3_MWD+IFR2+MS+Sag (1) 2,384.54 27.73 25.02 2,215.22 2,156.35 666.46 257.04 6,028,557.33 534,007.81 4.23 -680.53 3_MWD+IFR2+MS+Sag (1) 2,478.60 23.89 29.61 2,299.89 2,241.02 702.87 275.72 6,028,593.81 534,026.32 4.60 -717.98 3_MWD+IFR2+MS+Sag (1) 2,574.58 19.69 34.70 2,389.00 2,330.13 733.07 294.54 6,028,624.10 534,045.00 4.79 -749.25 3_MWD+IFR2+MS+Sag (1) 2,670.05 16.43 40.01 2,479.76 2,420.89 756.65 312.38 6,028,647.75 534,062.73 3.82 -773.84 3_MWD+IFR2+MS+Sag (1) 2,765.72 13.56 51.69 2,572.18 2,513.31 773.97 329.88 6,028,665.15 534,080.16 4.34 -792.17 3_MWD+IFR2+MS+Sag (1) 2,861.41 11.65 70.96 2,665.60 2,606.73 784.08 347.83 6,028,675.34 534,098.05 4.80 -803.33 3_MWD+IFR2+MS+Sag (1) 2,956.33 11.32 99.65 2,758.70 2,699.83 785.65 366.09 6,028,676.99 534,116.30 5.97 -805.98 3_MWD+IFR2+MS+Sag (1) 3,051.72 13.13 127.37 2,852.00 2,793.13 777.49 383.94 6,028,668.92 534,134.19 6.37 -798.90 3_MWD+IFR2+MS+Sag (1) 3,146.46 15.50 148.88 2,943.86 2,884.99 760.11 399.05 6,028,651.61 534,149.38 6.10 -782.44 3_MWD+IFR2+MS+Sag (1) 3,241.97 19.55 161.66 3,034.95 2,976.08 734.00 410.69 6,028,625.55 534,161.13 5.83 -757.06 3_MWD+IFR2+MS+Sag (1) 3,337.32 24.35 168.53 3,123.38 3,064.51 699.56 419.62 6,028,591.16 534,170.22 5.70 -723.22 3_MWD+IFR2+MS+Sag (1) 3,432.46 27.29 170.25 3,209.01 3,150.14 658.84 427.22 6,028,550.47 534,178.00 3.19 -683.01 3_MWD+IFR2+MS+Sag (1) 3,526.77 31.48 170.70 3,291.17 3,232.30 613.21 434.86 6,028,504.88 534,185.85 4.45 -637.92 3_MWD+IFR2+MS+Sag (1) 3,621.88 36.44 170.01 3,370.03 3,311.16 560.85 443.78 6,028,452.57 534,195.01 5.23 -586.18 3_MWD+IFR2+MS+Sag (1) 3,717.80 40.97 170.15 3,444.86 3,385.99 501.78 454.11 6,028,393.56 534,205.60 4.72 -527.83 3_MWD+IFR2+MS+Sag (1) 3,813.58 44.28 173.26 3,515.34 3,456.47 437.62 463.41 6,028,329.44 534,215.19 4.10 -464.33 3_MWD+IFR2+MS+Sag (1) 3,909.02 49.32 175.41 3,580.65 3,521.78 368.41 470.22 6,028,260.27 534,222.31 5.53 -395.65 3_MWD+IFR2+MS+Sag (1) 4,002.69 57.11 175.70 3,636.70 3,577.83 293.67 476.02 6,028,185.57 534,228.45 8.32 -321.38 3_MWD+IFR2+MS+Sag (1) 4,098.26 60.87 176.22 3,685.93 3,627.06 211.98 481.78 6,028,103.91 534,234.58 3.96 -240.18 3_MWD+IFR2+MS+Sag (1) 4,193.65 65.48 178.14 3,728.97 3,670.10 126.98 485.94 6,028,018.94 534,239.13 5.16 -155.58 3_MWD+IFR2+MS+Sag (1) 4,288.89 65.62 179.60 3,768.39 3,709.52 40.30 487.65 6,027,932.28 534,241.23 1.40 -69.15 3_MWD+IFR2+MS+Sag (1) 4,383.98 72.71 182.36 3,802.19 3,743.32 -48.49 486.08 6,027,843.49 534,240.06 7.93 19.57 3_MWD+IFR2+MS+Sag (1) 4,478.59 79.51 183.23 3,824.89 3,766.02 -140.17 481.59 6,027,751.81 534,235.99 7.24 111.36 3_MWD+IFR2+MS+Sag (1) 4,573.80 83.94 184.03 3,838.59 3,779.72 -234.17 475.62 6,027,657.78 534,230.45 4.73 205.55 3_MWD+IFR2+MS+Sag (1) 4,668.43 89.32 184.14 3,844.15 3,785.28 -328.36 468.90 6,027,563.57 534,224.15 5.69 299.98 3_MWD+IFR2+MS+Sag (1) 4,764.28 86.54 184.09 3,847.62 3,788.75 -423.89 462.02 6,027,468.02 534,217.72 2.90 395.75 3_MWD+IFR2+MS+Sag (1) 4,857.65 85.24 184.20 3,854.31 3,795.44 -516.78 455.29 6,027,375.11 534,211.41 1.40 488.87 3_MWD+IFR2+MS+Sag (1) 4,957.59 89.59 184.29 3,858.81 3,799.94 -616.32 447.90 6,027,275.55 534,204.47 4.35 588.67 3_MWD+IFR2+MS+Sag (2) 5,053.68 91.37 184.82 3,858.01 3,799.14 -712.10 440.27 6,027,179.75 534,197.28 1.93 684.73 3_MWD+IFR2+MS+Sag (2) 10/302019 12:20:51PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -21i Wellbore: MPU M -21i Design: MPU M -21i Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M -21i MPU M-21 Actual RKB @ 58.87usft MPU M-21 Actual RKB @ 58.87usft True Minimum Curvature NORTH US + CANADA Map Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') 5,148.25 90.07 184.93 3,856.82 3,797.95 -806.32 432.24 6,027,085.50 534,189.67 1.38 5,243.99 90.75 185.74 3,856.14 3,797.27 -901.64 423.34 6,026,990.15 534,181.20 1.10 5,339.58 90.38 184.58 3,855.19 3,796.32 -996.83 414.74 6,026,894.93 534,173.04 1.27 5,434.72 89.76 182.94 3,855.08 3,796.21 -1,091.77 408.50 6,026,799.98 534,167.23 1.84 5,530.41 87.41 180.33 3,857.44 3,798.57 -1,187.37 405.77 6,026,704.37 534,164.93 3.67 5,625.68 87.97 181.50 3,861.28 3,802.41 -1,282.55 404.25 6,026,609.19 534,163.85 1.36 5,719.90 88.40 180.57 3,864.26 3,805.39 -1,376.71 402.55 6,026,515.04 534,162.57 1.09 5,814.59 88.16 180.61 3,867.11 3,808.24 -1,471.35 401.57 6,026,420.40 534,162.03 0.26 5,910.76 89.58 180.81 3,869.00 3,810.13 -1,567.49 400.38 6,026,324.27 534,161.27 1.49 6,006.31 89.51 181.75 3,869.76 3,810.89 -1,663.01 398.25 6,026,228.75 534,159.57 0.99 6,101.17 88.90 182.40 3,871.08 3,812.21 -1,757.80 394.81 6,026,133.95 534,156.57 0.94 6,197.50 89.14 184.14 3,872.73 3,813.86 -1,853.96 389.32 6,026,037.78 534,151.51 1.82 6,292.16 90.01 184.78 3,873.43 3,814.56 -1,948.32 381.96 6,025,943.39 534,144.58 1.14 6,387.79 93.41 185.41 3,870.57 3,811.70 -2,043.52 373.47 6,025,848.17 534,136.53 3.62 6,481.78 97.33 185.24 3,861.78 3,802.91 -2,136.68 364.79 6,025,754.98 534,128.27 4.17 6,577.10 95.51 184.01 3,851.12 3,792.25 -2,231.08 357.15 6,025,660.55 534,121.06 2.30 6,671.68 94.59 182.62 3,842.80 3,783.93 -2,325.14 351.71 6,025,566.48 534,116.04 1.76 6,767.07 93.71 180.97 3,835.89 3,777.02 -2,420.22 348.73 6,025,471.39 534,113.49 1.96 6,862.25 94.03 180.82 3,829.47 3,770.60 -2,515.18 347.24 6,025,376.44 534,112.44 0.37 6,957.52 94.28 182.91 3,822.56 3,763.69 -2,610.14 344.15 6,025,281.48 534,109.78 2.20 7,052.68 94.52 183.93 3,815.26 3,756.39 -2,704.85 338.49 6,025,186.75 534,104.55 1.10 7,146.04 94.96 184.11 3,807.55 3,748.68 -2,797.66 331.97 6,025,093.92 534,098.45 0.51 7,241.57 96.26 184.00 3,798.21 3,739.34 -2,892.49 325.25 6,024,999.07 534,092.16 1.37 7,335.32 97.07 184.64 3,787.33 3,728.46 -2,985.34 318.23 6,024,906.20 534,085.57 1.10 7,427.85 96.13 185.14 3,776.69 3,717.82 -3,076.92 310.40 6,024,814.59 534,078.15 1.15 7,521.06 95.20 184.57 3,767.49 3,708.62 -3,169.34 302.55 6,024,722.14 534,070.72 1.17 7,618.59 94.33 183.78 3,759.39 3,700.52 -3,266.28 295.47 6,024,625.19 534,064.08 1.20 7,713.68 93.96 183.33 3,752.52 3,693.65 -3,360.94 289.59 6,024,530.51 534,058.63 0.61 7,813.27 90.00 183.25 3,749.08 3,690.21 -3,460.28 283.88 6,024,431.15 534,053.37 3.98 7,908.09 91.43 182.88 3,747.90 3,689.03 -3,554.96 278.81 6,024,336.47 534,048.73 1.56 8,003.99 92.05 184.20 3,744.98 3,686.11 -3,650.63 272.89 6,024,240.78 534,043.25 1.52 8,099.27 93.29 185.10 3,740.54 3,681.67 -3,745.49 265.18 6,024,145.89 534,035.97 1.61 8,195.14 92.91 184.20 3,735.36 3,676.49 -3,840.90 257.42 6,024,050.46 534,028.64 1.02 8,288.69 92.54 182.99 3,730.91 3,672.04 -3,934.16 251.56 6,023,957.18 534,023.20 1.35 8,384.19 92.29 182.13 3,726.89 3,668.02 -4,029.48 247.30 6,023,861.85 534,019.38 0.94 8,479.36 91.61 181.27 3,723.65 3,664.78 -4,124.55 244.48 6,023,766.78 534,016.99 1.15 8,574.41 91.43 182.01 3,721.13 3,662.26 -4,219.53 241.76 6,023,671.80 534,014.70 0.80 8,669.38 91.37 181.30 3,718.81 3,659.94 -4,314.43 239.01 6,023,576.90 534,012.39 0.75 8,765.32 91.55 181.85 3,716.36 3,657.49 -4,410.30 236.38 6,023,481.02 534,010.19 0.60 8,860.91 91.18 181.69 3,714.09 3,655.22 -4,505.82 233.43 6,023,385.50 534,007.67 0.42 Vertical Section (ft) Survey Tool Name 779.26 3_MWD+IFR2+MS+Sag (2) 874.94 3_MWD+IFR2+MS+Sag (2) 970.48 3_MWD+IFR2+MS+Sag (2) 1,065.62 3_MWD+IFR2+MS+Sag (2) 1,161.22 3_MWD+IFR2+MS+Sag (2) 1,256.32 3_MWD+IFR2+MS+Sag (2) 1,350.41 3_MWD+IFR2+MS+Sag (2) 1,444.94 3_MWD+IFR2+MS+Sag (2) 1,540.99 3_MWD+IFR2+MS+Sag (2) 1,636.47 3_MWD+IFR2+MS+Sag (2) 1,731.29 3_MWD+IFR2+MS+Sag (2) 1,827.60 3_MWD+IFR2+MS+Sag (2) 1,922.24 3_MWD+IFR2+MS+Sag (2) 2,017.77 3_MWD+IFR2+MS+Sag (2) 2,111.28 3_MWD+IFR2+MS+Sag (2) 2,205.97 3_MWD+IFR2+MS+Sag (2) 2,300.18 3_MWD+IFR2+MS+Sag (2) 2,395.28 3_MWD+IFR2+MS+Sag (2) 2,490.15 3_MWD+IFR2+MS+Sag (2) 2,585.13 3_MWD+IFR2+MS+Sag (2) 2,680.01 3_MWD+IFR2+MS+Sag (2) 2,773.05 3_MWD+IFR2+MS+Sag (2) 2,868.11 3_MWD+IFR2+MS+Sag (2) 2,961.22 3_MWD+IFR2+MS+Sag (2) 3,053.10 3_MWD+IFR2+MS+Sag (2) 3,145.82 3_MWD+IFR2+MS+Sag (2) 3,243.01 3_MWD+IFR2+MS+Sag (2) 3,337.85 3_MWD+IFR2+MS+Sag (2) 3,437.36 3_MWD+IFR2+MS+Sag (2) 3,532.16 3_MWD+IFR2+MS+Sag (2) 3,628.02 3_MWD+IFR2+MS+Sag (2) 3,723.17 3_MWD+IFR2+MS+Sag (2) 3,818.87 3_MWD+IFR2+MS+Sag (2) 3,912.32 3_MWD+IFR2+MS+Sag (2) 4,007.72 3_MWD+IFR2+MS+Sag (2) 4,102.79 3_MWD+IFR2+MS+Sag (2) 4,197.76 3_MWD+IFR2+MS+Sag (2) 4,292.66 3_MWD+IFR2+MS+Sag (2) 4,388.52 3_MWD+IFR2+MS+Sag (2) 4,484.04 3_MWD+IFR2+MS+Sag (2) 10/3012019 12:20:51PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: HilcorpAlaska, LLC Local Co-ordinate Reference: Well MPU M -21i Project: Milne Point TVD Reference: MPU M-21 Actual RKB @ 58.87usft Site: M Pt Moose Pad MD Reference: MPU M-21 Actual RKB @ 58.87usft Well: MPU M -21i North Reference: True Wellbore: MPU M -21i Survey Calculation Method: Minimum Curvature Design: MPU M -21i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) V) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,956.40 91.37 182.49 3,711.96 3,653.09 -4,601.22 229.94 6,023,290.09 534,004.62 0.86 4,579.48 3_MWD+IFR2+MS+Sag (2) 9,051.68 91.55 183.11 3,709.53 3,650.66 -4,696.36 225.29 6,023,194.95 534,000.40 0.68 4,674.73 3_MWD+IFR2+MS+Sag (2) 9,147.50 92.04 184.33 3,706.53 3,647.66 -4,791.92 219.08 6,023,099.36 533,994.62 1.37 4,770.50 3_MWD+IFR2+MS+Sag (2) 9,241.46 94.41 184.54 3,701.25 3,642.38 -4,885.45 211.82 6,023,005.82 533,987.79 2.53 4,864.29 3_MWD+IFR2+MS+Sag (2) 9,337.53 94.34 184.94 3,693.92 3,635.05 -4,980.91 203.91 6,022,910.33 533,980.31 0.42 4,960.05 3_MWD+IFR2+MS+Sag (2) 9,432.26 94.27 184.81 3,686.81 3,627.94 -5,075.03 195.88 6,022,816.18 533,972.71 0.16 5,054.48 3_MWD+IFR2+MS+Sag (2) 9,528.74 94.71 185.13 3,679.25 3,620.38 -5,170.85 187.55 6,022,720.33 533,964.81 0.56 5,150.63 3_MWD+IFR2+MS+Sag (2) 9,623.17 93.90 185.39 3,672.17 3,613.30 -5,264.62 178.92 6,022,626.54 533,956.61 0.90 5,244.74 3_MWD+IFR2+MS+Sag (2) 9,718.07 92.97 183.32 3,666.48 3,607.61 -5,359.07 171.72 6,022,532.06 533,949.85 2.39 5,339.45 3_MWD+IFR2+MS+Sag (2) 9,812.76 91.74 181.52 3,662.59 3,603.72 -5,453.59 167.73 6,022,437.54 533,946.28 2.30 5,434.04 3_MWD+IFR2+MS+Sag (2) 9,909.12 91.30 181.90 3,660.03 3,601.16 -5,549.87 164.86 6,022,341.25 533,943.84 0.60 5,530.33 3_MWD+IFR2+MS+Sag (2) 10,003.85 91.37 183.56 3,657.83 3,598.96 -5,644.47 160.35 6,022,246.65 533,939.76 1.75 5,625.02 3_MWD+IFR2+MS+Sag (2) 10,099.45 91.74 185.28 3,655.23 3,596.36 -5,739.74 152.98 6,022,151.35 533,932.83 1.84 5,720.57 3_MWD+IFR2+MS+Sag (2) 10,194.32 93.91 186.96 3,650.55 3,591.68 -5,833.95 142.88 6,022,057.11 533,923.16 2.89 5,815.21 3_MWD+IFR2+MS+Sag (2) 10,290.12 92.23 184.78 3,645.42 3,586.55 -5,929.10 133.10 6,021,961.92 533,913.81 2.87 5,910.77 3_MWD+IFR2+MS+Sag (2) 10,384.71 92.67 182.72 3,641.38 3,582.51 -6,023.40 126.92 6,021,867.61 533,908.06 2.22 6,005.27 3_MWD+IFR2+MS+Sag (2) 10,480.47 91.49 183.52 3,637.90 3,579.03 -6,118.95 121.71 6,021,772.04 533,903.29 1.49 6,100.96 3_MWD+IFR2+MS+Sag (2) 10,575.75 89.70 181.82 3,636.91 3,578.04 -6,214.11 117.27 6,021,676.87 533,899.28 2.59 6,196.22 3_MWD+IFR2+MS+Sag (2) 10,671.25 90.32 182.09 3,636.90 3,578.03 -6,309.56 114.02 6,021,581.42 533,896.46 0.71 6,291.69 3_MWD+IFR2+MS+Sag (2) 10,766.46 89.82 181.78 3,636.78 3,577.91 -6,404.71 110.80 6,021,486.26 533,893.67 0.62 6,386.87 3_MWD+IFR2+MS+Sag (2) 10,861.99 89.95 181.69 3,636.97 3,578.10 -6,500.20 107.91 6,021,390.77 533,891.22 0.17 6,482.36 3_MWD+IFR2+MS+Sag (2) 10,956.29 89.70 181.82 3,637.26 3,578.39 -6,594.45 105.02 6,021,296.51 533,888.76 0.30 6,576.62 3_MWD+IFR2+MS+Sag (2) 11,051.47 85.73 182.98 3,641.06 3,582.19 -6,689.45 101.04 6,021,201.50 533,885.21 4.35 6,671.69 3_MWD+IFR2+MS+Sag (2) 11,146.92 83.69 183.67 3,649.86 3,590.99 -6,784.33 95.53 6,021,106.61 533,880.13 2.26 6,766.72 3_MWD+IFR2+MS+Sag (2) 11,241.89 84.44 184.10 3,659.68 3,600.81 -6,878.57 89.13 6,021,012.35 533,874.15 0.91 6,861.18 3_MWD+IFR2+MS+Sag (2) 11,337.36 86.86 184.46 3,666.92 3,608.05 -6,973.50 82.02 6,020,917.41 533,867.48 2.56 6,956.36 3_MWD+IFR2+MS+Sag (2) 11,432.45 86.73 184.17 3,672.23 3,613.36 -7,068.17 74.88 6,020,822.71 533,860.77 0.33 7,051.29 3_MWD+IFR2+MS+Sag (2) 11,527.89 89.64 183.96 3,675.26 3,616.39 -7,163.31 68.12 6,020,727.55 533,854.44 3.06 7,146.66 3_MWD+IFR2+MS+Sag (2) 11,622.56 93.23 184.44 3,672.88 3,614.01 -7,257.68 61.19 6,020,633.16 533,847.94 3.83 7,241.28 3_MWD+IFR2+MS+Sag (2) 11,716.99 92.48 183.84 3,668.18 3,609.31 -7,351.75 54.38 6,020,539.07 533,841.56 1.02 7,335.58 3_MWD+IFR2+MS+Sag (2) 11,812.79 90.19 182.08 3,665.95 3,607.08 -7,447.38 49.44 6,020,443.42 533,837.05 3.01 7,431.34 3_MWD+IFR2+MS+Sag (2) 11,907.93 90.19 182.15 3,665.63 3,606.76 -7,542.46 45.92 6,020,348.34 533,833.97 0.07 7,526.46 3_MWD+IFR2+MS+Sag (2) 12,002.69 90.32 183.56 3,665.21 3,606.34 -7,637.10 41.21 6,020,253.69 533,829.68 1.49 7,621.21 3_MWD+IFR2+MS+Sag (2) 12,097.47 90.44 183.18 3,664.58 3,605.71 -7,731.71 35.63 6,020,159.06 533,824.54 0.42 7,715.99 3_MWD+IFR2+MS+Sag (2) 12,192.98 90.13 184.40 3,664.11 3,605.24 -7,827.01 29.32 6,020,063.75 533,818.66 1.32 7,811.49 3_MWD+IFR2+MS+Sag (2) 12,288.07 93.23 188.29 3,661.32 3,602.45 -7,921.45 18.82 6,019,969.27 533,808.59 5.23 7,906.39 3_MWD+IFR2+MS+Sag (2) 12,383.52 93.47 188.49 3,655.74 3,596.87 -8,015.71 4.92 6,019,874.95 533,795.12 0.33 8,001.31 3_MWD+IFR2+MS+Sag (2) 12,478.92 94.53 187.29 3,649.09 3,590.22 -8,109.98 -8.14 6,019,780.64 533,782.48 1.68 8,096.18 3_MWD+IFR2+MS+Sag (2) 12,574.55 92.79 183.94 3,642.98 3,584.11 -8,204.94 -17.48 6,019,685.65 533,773.58 3.94 8,191.53 3_MWD+IFR2+MS+Sag (2) 12,669.63 91.93 181.63 3,639.07 3,580.20 -8,299.82 -22.09 6,019,590.76 533,769.40 2.59 8,286.52 3_MWD+IFR2+MS+Sag (2) 10/302019 12:20:51PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -21i Project: Milne Point TVD Reference: MPU M-21 Actual RKB @ 58.87usft Site: M Pt Moose Pad MD Reference: MPU M-21 Actual RKB @ 58.87usft Well: MPU M -21i North Reference: True Wellbore: MPU M -21i Survey Calculation Method: Minimum Curvature Design: MPU M -21i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 12,765.31 89.70 181.39 3,637.70 3,578.83 -8,395.45 -24.61 6,019,495.13 533,767.31 2.34 8,382.13 3_MWD+IFR2+MS+Sag (2) 12,860.38 87.97 181.06 3,639.64 3,580.77 -8,490.47 -26.65 6,019,400.10 533,765.71 1.85 8,477.11 3_MWD+IFR2+MS+Sag (2) 12,955.78 86.92 181.37 3,643.89 3,585.02 -8,585.75 -28.67 6,019,304.82 533,764.12 1.15 8,572.34 3_MWD+IFR2+MS+Sag (2) 13,050.73 88.59 181.85 3,647.61 3,588.74 -8,680.59 -31.33 6,019,209.98 533,761.89 1.83 8,667.17 3_MWD+IFR2+MS+Sag (2) 13,146.25 88.90 183.13 3,649.70 3,590.83 -8,775.99 -35.48 6,019,114.57 533,758.17 1.38 8,762.65 3_MWD+IFR2+MS+Sag (2) 13,241.17 88.22 184.11 3,652.09 3,593.22 -8,870.69 -41.47 6,019,019.86 533,752.61 1.26 8,857.54 3_MWD+IFR2+MS+Sag (2) 13,336.17 89.52 184.49 3,653.96 3,595.09 -8,965.41 -48.59 6,018,925.12 533,745.92 1.43 8,952.51 3_MWD+IFR2+MS+Sag (2) 13,431.99 92.98 183.19 3,651.87 3,593.00 -9,060.97 -55.01 6,018,829.54 533,739.94 3.86 9,048.28 3_MWD+IFR2+MS+Sag (2) 13,526.85 93.66 182.48 3,646.38 3,587.51 -9,155.55 -59.69 6,018,734.94 533,735.68 1.04 9,142.98 3_MWD+IFR2+MS+Sag (2) 13,622.25 91.86 181.12 3,641.78 3,582.91 -9,250.79 -62.69 6,018,639.70 533,733.12 2.36 9,238.23 3_MWD+IFR2+MS+Sag (2) 13,717.23 90.19 179.88 3,640.08 3,581.21 -9,345.75 -63.51 6,018,544.75 533,732.73 2.19 9,333.06 3_MWD+IFR2+MS+Sag (2) 13,812.45 89.08 180.10 3,640.69 3,581.82 -9,440.96 -63.50 6,018,449.55 533,733.17 1.19 9,428.11 3_MWD+IFR2+MS+Sag (2) 13,907.50 88.77 182.69 3,642.47 3,583.60 -9,535.96 -65.81 6,018,354.55 533,731.29 2.74 9,523.08 3_MWD+IFR2+MS+Sag (2) 13,931.09 88.83 183.04 3,642.97 3,584.10 -9,559.52 -66.99 6,018,330.99 533,730.22 1.51 9,546.66 3_MWD+IFR2+MS+Sag (2) 14,000.00 88.83 183.04 3,644.38 3,585.51 -9,628.31 -70.64 6,018,262.18 533,726.88 0.00 9,615.56 PROJECTED to TD DiglWllysigned by Chelsea Benjamin HandDate: 0:0803.08'00' 10-30-2019 lly signed by M�Jin Hand Checked By: Chelsea Wright Might 103010,09-31 OAoo Approved By: J Date: 10/30/2019 12:20:51 PM Page 6 COMPASS 5000.15 Build 91 Lease & Well No. County TD Hilcorp Energy Company CASING & CEMENTING REPORT MP M-21 State Alaska Supv. CASING RECORD Surface t 4.924.00 Shoe Denth- 4.917.00 PRTn, Date Run 20 -Oct -19 S. Sunderland / C. Demoski Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. Hrs to Run: 12.5 Casing (Or Liner) Detail 100,000 Type of Shoe: Innovex Casing Crew: Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 X Yes_ No TXP BTC -SR Innovex 1.59 4,917.00 4,915.41 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 78.11 4,915.41 4,837.30 1 Float Collar 103/4 50.0 2,206 TXP BTC -SR Innovex 1.32 4,837.30 4,835.98 1 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 39.31 4,835.98 4,796.67 1 Baffle Adapter 103/4 50.0 144.63/147.36 TXP BTC -SR HES 1.56 4,796.67 4,795.11 65 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,568.56 4,795.11 2,226.55 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.58 2,226.55 2,207.97 1 ES Cementer 103/4 TXP BTC -SR HES 2.82 2,207.97 2,205.15 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.54 2,205.15 2,186.61 54 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,132.19 1 2,186.61 54.42 1 Cut Joint of Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 20.00 1 54.42 34.42 Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. Hrs to Run: 12.5 Csg Wt. On Slips: 100,000 Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes _ No 30 Ft. Min. 9.3 PPG Fluid Description: Spud Mud LL Displacement: Liner hanger Info (Make/Model): Liner top Packer?: _ Yes _ No Liner hanger test pressure: Type: Spud Mud Density (ppg) Floats Held X Yes_ No Centralizer Placement: Two 9-5/8"x12-1/4" Expand-o-lizers w/ 4 stop rings installed on shoe joint, one floating on joint #2, one each with two each stop rings FCP (psi): 610 Pump used for disp: Rig on joints #3 & 4. Bump press _ 6 CEMENTING REPORT Shoe @ 4917 FC @ 4,835.98 Preflush (Spacer) Type: Tuner Spacer Density (ppg) 10 Lead Slurry Type: Lead Cement Density (ppg) 12 Volume pumped (BBLs) 117 Tail Slurry Lu Type: Tail Cement (7 Top of Liner Volume pumped (BBLs) Sacks: 280 Yield: _ Mixing / Pumping Rate (bpm): Sacks: 400 Yield: 60 2.35 5 1.16 5 ,7.59 1210 Density (ppg) 15.8 Volume pumped (BBLs) 82 Mixing / Pumping Rate (bpm): N U) Post Flush (Spacer) � Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 166.15/1 FCP (psi): 610 Pump used for disp: Rig Bump Plug? X Yes No Bump press _ 6 Casing Rotated? X Yes -No Reciprocated? X Yes _ No % Returns during job 100 Cement returns to surface? X Yes -No Spacer returns? X Yes No Vol to Surf: 0.5 1.17 Cement In Place At: 14:20 Date: 10/20/2019 Estimated TOC: 2,206 5 Method Used To Determine TOC: Returns to surface ,7.59 1210 Post Job Calculations: Calculated Cmt Vol @ 0% excess: 308.03 Total Volume cmt Pumped: 707.2 Cmt returned to surface: 230.67 Calculated cement left in wellbore: 476.53 OH volume Calculated: 268 OH volume actual: 436.5 Actual % Washout: 62.87 Stage Collar @ 2205.89 Type ES Cementer Closure OK Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Penn L Sacks: 550 Yield: 4.41 Density (ppg) 1207 Volume pumped (BBLs) 452 Mixing / Pumping Rate (bpm): 6 Tail Slurry lu Type: Premium G Sacks: 270 Yield: 1.17 y Density (ppg) 15.8 Volume pumped (BBLs) 56.2 Mixing / Pumping Rate (bpm): 5 Z Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: W ur Displacement: Type: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual / calculated): 144.63/147.36 FCP (psi): 380 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1610 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes -No Spacer returns? _ Yes X No Vol to Surf: 230.17 Cement In Place At: 0:10 Date: 10/21/2019 Estimated TOC: 37 Method Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 308.03 Total Volume cmt Pumped: 707.2 Cmt returned to surface: 230.67 Calculated cement left in wellbore: 476.53 OH volume Calculated: 268 OH volume actual: 436.5 Actual % Washout: 62.87 thir.,rp Ala+kir. 1.1.0 Date: 11/20/2019 Dc�. a Oudean Hilcorp Alaska, LLC, GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 CD 1 : HALLIBURTON FINAL DATA _Log Viewers 11,/19/2119 8:57 AM File folder CGM 11/18/2019 9:5x8 AM File folder Definitive Surrey 11,1 U2019 8:59 AM File folder EMF 11 '18,/2019 8:56 AM File folder LAS 11/18./2019 8:56 AM File folder PDF 11"18./20198:57AM File folder TIFF 11/18,/2D19 S:57 AM File folder 219132 31447 ECEIVED NOV 2 0 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 THE STATE GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 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 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-21 Hilcorp Alaska, LLC Permit to Drill Number: 219-132 Surface Location: 5038' FSL, 411' FEL, SEC. 14, TI 3N, R9E, UM, AK Bottomhole Location: 638' FSL, 499' FEL, SEC. 23, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of.the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, y essiielowski Commissioner DATED this 1' day of October, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. 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 [A Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-21 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 14184' TVD: 3,573' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5038' FSL, 411' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL355023, ADL388235 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: -M FVL, 7'S'_FWL, Sec 13, T13N, R9E, UM, AK pr.4 LONS 16-004 10/17/2019 Total Depth:fr6L (i d+ % p 9. Acres in Property: 14. Distance to Nearest Property: 638' FSL, 499' FEL, Sec 23, T1 3N, R9E, UM, AK ✓ 7735 3M-fo neares unit boundary 4b. Location of Well (State Base Plane Coordinates -NAD 27): 10. KB Elevation above MSL (ft): 58.7' 1 1s nce t6 Nearest Well Open Surface: x- 533753 y- 6027889 Zone -4 GL / BF Elevation above MSL (ft): 25.0' to Same Pool: MPU M-20 760' 16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92.45 degrees Downhole: 1689 1 Surface: 1321 " 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 113' Surface Surface 113' 113' —270 ft3 Stg 1-L-517ft3/T-458ft3 12-1/4" 9-5/8" 40# L-80 TXP 4,770 Surface Surface 4,770' 3854' Stg 2 - L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 9,346' 4,620' 3842' 13,966' 3,639' Cementless Injection Liner ICDs Tieback 1 3-1/2" 9.3# L-80 EUE 8RD 4,620' 1 Surface Surface 1 4,620' 3842' Tieback 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑� 20. Attachments: Property Plat ❑� BOP Sketch Drilling Program ❑ ❑ Time v. Depth Plot ❑ Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'er1 el hilcor .com Authorized Title: Drilling Manager Contact Phone: 777-8395 _/-�Vyz Authorized Signature: 61 Date: °%' Z7- 2,�/ 9 Commission Use Only Permit to Drill Number: Permit Approval See cover letter for other Number: ' — 50- O zg a 3 y 1— QQ d Q Date: t4i I I requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: NK Other: .1( J V©� S� �� 1 - Samples req'd: Yes ❑ No[W]" Mud log req'd: Yes E] No[�K / HzS measures: Yes ❑ No [� Directional EK, svy req'd: Yes [)No ❑ 1 i� 010 �'` i v v' Spacing exception req'd: Yes El No svy req'd: Yes ❑, -NK C_C_-(J t—�c� w: A �� �� ..� Post initial injection MIT req'd: Yes LyJ No ❑ L/ by: 1L (--- APPROVED BY �( r�( Approved - /� COMMISSIONER THE COMMISSION IU Date:P Submit Form and Form 10-401 Revised 5/2017 This permit is valid for 24 m(Os( t eflInArntper 20 AAC 25.005(g) Attachments in Duplicate Hilcorp Alaska, LLC Milne Point Unit (MPU) M-21 Drilling Program Version 1 9/23/19 i� I,16f-13Z= t ACF- l�, 'NW M-11 L-39 NWA' _--- — _ ■� .fin w 02 � I M-13 \����� �� I � ��L-36 M- 4,_,, -- PESAQ tA i ,,M-16/' I � W18 LIVI i I � LIVIAN0�1 I 1 11 HIL I 1I M I ` / I x a A1�0 1 A ��.. CORP ALASKA LLC ml POINT FIELD AOR MAP M-21 Injector (Proposed) 100 0 2000 znn FEET WELL SYMBOLS ACtie9 01 o&A 94J Wall (Weler Flood) 1 PMOH SWD "actor location REMARKS We" Svmbds at top of Schrader Bluff OA Sand Black dash drde - 1320' radius from OA sand in heel and toe of proposed M-21 drill well September 25. 2019 Area of Review MPM-21 6 CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD API WELL STATUS OA (MD) OA (TVD) (MD) (TVD) status Zonal Isolation 184-033 50-029-24057-01-00 MPM-01A P&A'd 4,989' 3,676' Surface Surface Closed Well fully P&A'd with cement to surface 219-083 50-029-23636-00-00 MPM-20 SB Producer 5,126' 3,875' Surface Surface Open Open to injection support 219-111 50-029-23645-00-00 MPM-22 ✓ SB Producer 4,867' 3,833' Surface Surface Open Open to injection support 219-040 50-029-23625-00-00 MPM-14 SB Producer 4,765' 3,854' Surface Surface Open Open to injection support Schrader drilled into for a data point, but fully 218-140 50-029-23614-00-00 MPM-03 Ugnu Disposal 6,158' 3,687' Surface Surface Closed cemented during 7-5/8" cement job. 7-5/8" shoe at 5,648' MD - well full of cement below shoe. PBTD 5,563' MD / 3,886' TVD. 218-176 50-029-23619-00-00 MPM-12 SB Producer 4,523' 1 3,891' 1 Surface Surface Open Open to injection support 6 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work.........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter System................................................................................................. I 1 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................37 18.0 RDMO............................................................................................................................................38 19.0 Doyon 14 Diverter Schematic.......................................................................................................39 20.0 Doyon 14 BOP Schematic.............................................................................................................40 21.0 Wellhead Schematic......................................................................................................................41 22.0 Days Vs Depth...............................................................................................................................42 23.0 Formation Tops & Information...................................................................................................43 24.0 Anticipated Drilling Hazards.......................................................................................................44 25.0 Doyon 14 Layout............................................................................................................................47 26.0 FIT Procedure...............................................................................................................................48 27.0 Doyon 14 Choke Manifold Schematic.........................................................................................49 28.0 Casing Design................................................................................................................................50 29.0 8-1/2" Hole Section MASP............................................................................................................51 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 31.0 Surface Plat (As Built) (NAD 27).................................................................................................53 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................54 33.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50..............................................................55 1.0 Well Summary Well MPU M-21 Milne Point Unit Milne Point "M" Pad Planned Completion Tye 3-1/2" Injection Tubing M-21 SB Injector Schrader Bluff OA Sand Hilco �ra C®� Drilling Procedure 1.0 Well Summary Well MPU M-21 Pad Milne Point "M" Pad Planned Completion Tye 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 14,184' MD / 3,573' TVD PBTD, MD / TVD 14,164' MD / 3,573' TVD Surface Location (Governmental) 241' FSL, 411' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533,753.82, Y= 6,027,889.77 Top of Productive Horizon (Governmental) 363' FNL, 75' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 534,240 Y= 6,027,770 BHL (Governmental) 638' FSL, 499' FEL, Sec 23, TON, R9E, UM, AK BHL (NAD 27) X= 533,716 Y=6,018,210 AFE Number 1913623M (D,C,F) AFE Drilling Days 19 days AFE Completion Das 3 days AFE Drilling Amount $4,120,230 AFE Completion Amount $1,551,422 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1312 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1697 psig Work String 5" 19.5# 5-135 DS -50 & NC 50 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 Page 2 Hilcox Energy Company 2.0 Management of Change Information Milne Point Unit M-21 SB Injector Drilling Procedure Hilcorp Alaska, LLC Hilc Changes to Approved Permit to Drill Date: 9/2512019 Subject: Changes to Approved Permit to Drill for MPU M-21 File #: MPU M-211 Drilling and Completion Program Any modifications to MPU M-21 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance by the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 3.0 Tubular Program: Milne Point Unit M-21 SB Injector Drilling Procedure Hole Section OD (in) ID (in) Drift (in) Conn OD (in)(#/ft)(psi) Wt Grade Conn Burst Collapse si) Tension k_ - Cond 20" 19.25" - - - X-52 Weld Min _( _lbs) 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 8-1/2" 4-1/2" 3.96" 3.795" 4.714" 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2" 2.992" 2.867" 4.500" 9.3 L-80 I EUE sxD 9289 7399 163 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section in in in(#/ft) Min Max k -lbs Surface& 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyersghilcorp, jengel@hilcorp.com and cdingerghilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp,com jengel@hilcorp.co and cdinger@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilco1p.com 5.7 Hilcorp Milne Point Contact List: Title Name Milne Point Unit Cell Phone Email Drilling Manager M-21 SB Injector 907.777.8431 Hilco E-gy cam Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyersghilcorp, jengel@hilcorp.com and cdingerghilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp,com jengel@hilcorp.co and cdinger@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilco1p.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 jenPel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 c_aiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 1 509.768.8196 cdinger@hilcorp.com Page 5 6.0 Planned Wellbore Schematic Milne Point Unit M-21 SB Injector Drilling Procedure Milne Point Unit Well: MPU M-21 Proposer Schematic PTED:TP D ADI: TRD TREE & WELLHEAD Tree I Cameron 31 8 SM Wi 4- 1B SM Cameron Wing Wellhead I Cameron 11.5KX Sit lock bottom w/(2) 2 -1f16 -SK oUtS OPEN HOLE/ CEMENT DETAIL 42" SO L>}uIS 110 Yards Pilecrete dumped down bacxsidel 121j4" 5tg1—L-517 3 T-458 St92—L-1937ft3/T-314ft3 6-1/2" Cemerrtless Injection Liner in 8-112" hole ryY4-1/2 IV Top MD Item ID CASING DETAIL Upper Completion u Size Type �W Graded Corn Drift ID Tap SSM BPF 3.5 X Nipple 12.813' cking Screl 20x34 Ca urtcr Insuat 215.5/X-42 Wl A Su ace 10 NOwy 4, 9.5/3 Su to 40 L-60 TXP 8.679 Sa ate 4,776 0.0753 3 Liner 13.5 L-60 Lt 625 3.795 462 14134 076149 TUBING DETAIL 4 4 -lig' Tvting 93/L-W/EUESRD 2.667" Surf 4,620 0.0870 iMax WELL INCLINATION DETAIL 4,620 7.375' Te ata Dve the SLZXp liner Tap PacKer KCIP @ 500'Hale Angle @ XN=TBD Hale Angle @ LinerTop=TBD Hale Angle = TSD JEWELRY DETAIL 3- So LCD ,. 89/1@'1° Mow 1149 4•L'2` No Top MD Item ID Upper Completion 1 2,5CQ 3.5 X Nipple 12.813' cking Screl 2.613 11 4, 3-5v XN Wpp a 12613' Pat ng Bore; 275 ND -G7 2.7-50- 3 4,550' 3.5"' Gauge Mandrel SGN+FXPQG w/ >i' wire 2.396- 4 4,610 11.260 No Go Lix3ter wJ 7.375 Seal Assembly 2.992 5 4,620 7.375' Te ata Dve the SLZXp liner Tap PacKer 2.992 Lawer Carnp9etion 6 4,620 2XP Liner Tap Packer - 7 13,961' 1 WV (Ball on Seat/ Closed) - TD= 13,966 [Mo / TD= 3,63yM) PBTD=13,96Y (l'+Q} % PHLD= I634' jTV0 Page 6 GENERAL WELL INFO APILY. Oampi�ted 67 Doyon 14; 7.0 Drilling / Completion Summary Milne Point Unit M-21 SB Injector Drilling Procedure MPU M-21 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-21 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD injection liner will be run in the open hole section. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately October 17, 2019, pending rig schedule. Surface casing will be run to 4,770 MD / 3,854' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP. Install MPD Riser 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner. 6. Run 3-1/2" tubing. 7. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-21. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: y Hilcorp Alaska LLC does not request any variances at this time. Page 8 FOr Milne Point Unit M-21 SB Injector Hilcolrp Energy Company Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-21. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: y Hilcorp Alaska LLC does not request any variances at this time. Page 8 FOr Hilcorp Enema Company Summary of BOP Equipment & Notifications Milne Point Unit M-21 SB Injector Drilling Procedure Hole Section Equipment Test Pressure (psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/30 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: Jim.regg-(2alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartz(2alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loepp(2alaska. gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse(2alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(2alaska.gov Test/Inspection notification standardization format:.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 9 Hilcorp Energy Compvy 9.0 RX and Preparatory Work Milne Point Unit M-21 SB Injector Drilling Procedure 9.1 M-21 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 10.0 N/U 21-1/4" 2M Diverter System Milne Point Unit M-21 SB Injector Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • NIU 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 11 Hilcorp E—W Company 10.4 Rig & Diverter Orientation: • May change on location Milne Point Unit M-21 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources Diverter Line MPU M -Pad *Drawling Not To Scale Page 12 M-10 I ■ M-13 M-12 ■ ■ M -u M-20 ■ ■ M -15,.x. � 1 ■ MV6 M-21 r� ~� Milne Point Unit M-21 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources Diverter Line MPU M -Pad *Drawling Not To Scale Page 12 Milne Point Unit M-21 SB Injector Hilcorp Drilling Procedure Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/LJ 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD., -in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 Hilcorp Energy C_P_Y Milne Point Unit M-21 SB Injector Drilling Procedure • Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW and added 1-1.5ppb of Lecithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. • Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. • AC: There are no offset wells with a clearance factors <1.0 11.4 12-1/4" hole mud program summary: Page 14 • 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. J Depth Interval MW (ppg) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Hilcorp E-WC-pgy Milne Point Unit M-21 SB Injector Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pHITem 25 Surface 8.8-9.8 1 75-175 20-40 25-45 <10 8.5-9 . 0 1 <-70F 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 1 55 1 gal dm 1 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 - 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 15 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-21 SB Injector Drilling Procedure 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 PIU shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assemblv consisting of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Hilcorp Energy C..P-y 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Section 5 Page 17 "A Overall Length B Mss. ID After Deilloul C Max. Tool OD D Opening Sear 1D E Closing Seat ID Plug Set Hikorp ES41 Running Order Part No. E541 Cementer SO No - Shut OH Plug PCL„ Closing Plug OD Opening Plug Baffle Adapter OD 4 m. OD Shut-off Plug E OD Bypass Plug (if used) OD Milne Point Unit M-21 SB Injector Drilling Procedure Hikorp ES41 Running Order E541 Cementer -- Shut OH Plug PCL„ Baffle Adapter 4 m. By -Pass Plug By Pass Baffle float Collar Float shoe Hilcorp Energy Company Milne Point Unit M-21 SB Injector Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • Verify depth of lowest Ugnu water sand for isolation with Geologist Depth Interval Centralization Shoe — 1000' Above Shoe 1/jt 1000' above Shoe — 2000' above Shoe 1/ 2 its (Top of Ugnu) • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 TXPR' BTC --- 1110812018 Outside Diameter Milne Point Unit Min. Wall M-21 SB Injector Hilcorp Enema Company Drilling Procedure TXPR' BTC --- 1110812018 Outside Diameter 9.625 in. Min. Wall 87-5% Thickness I"j Grade L80 Type 1 Watl Thickness 0.395 in. Connection OD REGULAR Option COUPLING PIPE BODY Body: Red 1st San=d: Red Grade L80 Type 1' Drift Standard API Standd 1st Baru Brown 2nd curd: 2nd Band: - Brown Type Casing 3rd Bard:- 3rd Sand: - 49^ Sand: - f t ! GEOMETRY r4:vminal 00 9.625 in. Nominal VAl?ight 40 lbs?R Drift 8.679 in. ric'minal ID 5.835 in. A Thickness 0.395 s^,:. Plain End l,Veight 38.97 ib= -tit oD74rarce API PERFORMANCE Body y1eld sreng>h 916 x1000 Its rtema:, Yie3_ 5750 psi smys 80000 psi cviapae 3090 psi GEOMETRY Ccr, ectoy OD 10.625 in. Coupling terglh 10.825 ir,. Connection ID 8.823 in. 6!a:ae-up Lose. 4.831 in. Thrsaws per in 5 Connection 00 Option REGULAR PERFORMANCE Tension =_ffriencp 100.0 % :pint Y~od Streng?h 916.000 x1000 internal Pressure Capacity n 5750.000 psi Its Compression Efficiency 100 `°: Compression Stan;th 916.000 x.1000 "ax. Rllotvable Bending 3S 1100 ft lbs Ermma! •e_s re Capacity 3090.000 ps MAKE-UPTORQUES Mn=mum 18860 ft -1 Optimum 20960 Nbs Maximum 23060 u-ibs OPERATION LIMIT TORQUES Operarng Torque 35600 R -a field Torque 43400 h.-€bs Notes This connection is fully interchangeable with: TXPU BTC - 9.625 in_ - 36143.5147153.5158.4 Ibsift [1j Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5031 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sates representative. Page 19 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Milne Point Unit M-21 SB Injector Hilcorp Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-21 SB Injector Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. C5 13.7 Drop bottom plug (flexible bypassp ul g) — 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 111 Stage Total Cement Volume: Page 21 , rnD Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" j(5) (3,770'- 2500') x .0558 bpf x 1.3 = 92.05 516.8 JCasing Total Lead 92.05 516.8 12-1/4" OH x 9-5/8" (4,770'- 3,770') x .0558 bpf x 1.3 = 72.5 407 — Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 , rnD Cement Slurry Design (1st Stage Cement Job): Lead Slurry Milne Point Unit System ExtendaCEM " System SwiftCEM TM System M-21 SB Injector 11.7 Ib/gal Hilco F—W m�? Drilling Procedure Cement Slurry Design (1st Stage Cement Job): Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. r� Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 4,650' x.0758 bpf = 352.4 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cemen behind state tool & that sufficient spacer will be above the tool to exit when circulation is established. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 Lead Slurry Tail Slurry System ExtendaCEM " System SwiftCEM TM System Density 11.7 Ib/gal 15.8 Ib/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. r� Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 4,650' x.0758 bpf = 352.4 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cemen behind state tool & that sufficient spacer will be above the tool to exit when circulation is established. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 Milne Point Unit M-21 SB Injector Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II Stage tool 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Hilcorp Energy Company Second Stage Surface Cement Job: Milne Point Unit M-21 SB Injector Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM "' System (Hal Cem) 20" Cond uctor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 J 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 50, (2500'- 2000') x.0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM "' System (Hal Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk ✓ 1.16 ft3/sk ✓' Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: ✓ 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. E5. CA All- Pa 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report toje�khilcorp. com and cdinger(2hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 i/ Milne Point Unit M-21 SB Injector Hilcorp E..W C— Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: ✓ 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. E5. CA All- Pa 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report toje�khilcorp. com and cdinger(2hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 i/ 14.0 BOP NX and Test Milne Point Unit M-21 SB Injector Drilling Procedure 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5" BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD �e • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure 60 is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) Milne Point Unit M-21 SB Injector Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 6Ja . 15.4 _R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every'/4 bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. r 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. �y fti�! Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 27 Hilcorp Energy Company J Milne Point Unit M-21 SB Injector Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg F1oPro drilling fluid Properties: Interval 1 Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 1 15-25 - ALAP 1 15-30 1 4-6 <10% <8 <1 1.0 <100 System Formulation: Page 28 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 -GARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Milne Point Unit M-21 SB Injector Hilcofrp Drilling Procedure E—gy Company 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA1 & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Offset injection pressure from F-110 & L-50 has been seen on recent M -Pad wells. Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections • AC: • There are no offset wells that have a clearance factor of <1.0. • Some planned wells (M -21i P2) have clearance factor of <1.0 but does not exist yet • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 29 f Hilcorp E..W Company Milne Point Unit M-21 SB Injector Drilling Procedure • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (0 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Injection Control Devices (ICDs) are wire wrapped, and require passing PST with 250µ Coupons • Circulate and condition mud as much as needed to pass the production screen test • If not passing after first test, call Completion Engineer 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe 15.20 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary • Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise • If necessary, increase MW at shoe for any higher than expected pressure seen 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 30 V/ Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 Milne Point Unit M-21 SB Injector Hilco C-�P Drilling Procedure Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 Hilcrp F -r" C2, 16.0 Run 4-1/2" Injection Liner (Louver Completion) Milne Point Unit M-21 SB Injector Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: • With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2" and 5" test joints to 250 psi low/3000 psi high. 16.3. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.5. Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-%2" liner with PST passed mud (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.5# Hydril 625 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed I Jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Page 32 V/ Milne Point Unit M-21 SB Injector Drilling Procedure • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 33 i Hilcorp E—g• Company For the latest performance data, always visit our website. www.tenaris.com Wedge 6250 Outside Diameter 4.500 m. Wall Thickness 0.290 in. Grade LBO Type 1' GEOMETRY Min. Wall 8L5k Thickness Connection OD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-21 SB Injector Drilling Procedure , 12104f2o17 f*) Grade L80 4.500 in. Nominal weIgN 13.50 tsYt Drdt 3.795 in. Type t 1920 in. 1W Thickness 0.290 in. Plain F --.d weight 13.05 k&'ft COUPLING PIPE BODY Body Red Isl Band: Red Hsi Band: grown 2nd Band: 2nd Band: - Brown 3rd Band: - 3rd Band: - 41h Band: - Nominal OD 4.500 in. Nominal weIgN 13.50 tsYt Drdt 3.795 in. Nominal ID 1920 in. 1W Thickness 0.290 in. Plain F --.d weight 13.05 k&'ft 00 Toivwce API PERFORMANCE 3.58 Ecd;"o Y ➢add Strength 307 x',N_ 1 Ibs Internal Yield 9020 psi _11MYS 80000 PS; Colla se 8540 psi Connecinon OD 4.714 in. Connecixin 10 3.8496. Make-up Loss 4.830 a1. Threads per in 3.58 Caimmithm OD Option REGULAR PERFORMANCE Tension Eific %y 91b% Joint Yield Strength. 279.370 x1000 Internal PressureCapacity 9020.000 psi lbs Compression Eftency 94356 CompressionStrerq!h 290AISx1:300 Max_Ati:rr(ableBending 73.7'7 Wt lbs External Pressuree3pacity 8540.000 psi MAKE-UP TORQUES Minimum 8000 ft4bs optimum 9800 ftdbs Maximum 12800 ft4bs OPERATION LIMIT TORQUES Operati v Torque 12800 It -lbs Yield Torque 15000 ft -lbs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenaris.coni 16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 16.7. R/U false rotary and run 2-3/8" 6.4#/ft inner string. Page 34 Hilcorp E—gy Company Milne Point Unit M-21 SB Injector Drilling Procedure 16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U Baker SLZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.1.7. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Rig up to pump down the work string with the rig pumps. 16.19. Break circulation and begin displacing wellbore to —9.2 ppg KCl/NaCl (adjust brine weight if needed). Note the large OD on the ICDs. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the ICDs. Note all losses. Catch mud for future use if feasible. 16.21. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin pumping SAPP pill. 16.22. Mix and pump 3 tandem 40 bbl 10 ppb SAPP pills (120 bbl total SAPP pill) with 100 bbl in between. Keep circulation rate low to keep from packing off around the ICDs. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Page 35 16.23. Repeat pumping SAPP pills as needed until the wellbore is clean. Milne Point Unit M-21 SB Injector Drilling Procedure 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. Monitor the returned fluids to ensure as much mud and wall cake has been removed from the wellbore as possible so as to not impact wellbore injectivity. 16.24. Displace 1.5 OH & Liner volumes. 16.25. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.26. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.27. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.29. 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. 16.30. Displace 2-3/8" x Liner, pump 2 circulations. 16.31. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean outrun 16.32. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.33. Flush liner top at max rate while displacing out well to clean brine. 16.34. POOH LD Remaining 5" DP. Page 36 17.0 Run 3-1/2" Tubing (Upper Completion) 17.1 Noti the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivardnhilcorp.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-1/2" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while RAJ casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Milne Point Unit 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs M-21 SB Injector Hilcorp Ex(g Company Drilling Procedure 17.0 Run 3-1/2" Tubing (Upper Completion) 17.1 Noti the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivardnhilcorp.com for submission to AOGCC. 17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-1/2" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while RAJ casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-'/z" Upper Completion Running Order • 3-%2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3-1/2" "XN" nipple at TBD • 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3-%2" "X" nipple at TBD MD • 3-1/2" 9.3#/ft, L-80 EUE 8RD space out pups • 1 joint 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 37 17.5 Makeup the tubing hanger and landing joint. Milne Point Unit M-21 SB Injector Drilling Procedure 17.6 RIH. Close annular and test to 400 — 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. 17.9 Land hanger. RILDs and test hanger. 17.1,0 Continue pressurizing the annulus to-3064psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Page 3 8 Hilcorp Energy C—P.y 19.0 Doyon 14 Diverter Schematic 21.1;4' 2R1 R -ser -- 21.1;4` 2M— Uiverter "T' 21-14' A 16.314. 3M A VJ- VA USA Page 39 Milne Point Unit M-21 SB Injector Drilling Procedure –16' roll oPMN KnEe VAW 16' Dweller ltro Hilcorp Energy Company 20.0 Doyon 14 BOP Schematic Kill Line Page 40 Milne Point Unit M-21 SB Injector Drilling Procedure 2-7/81" x 5" VBR Blind Rams x 5M HCR al Gate VaNe 2-7/8" x 5" VBR Hilcorp Energy Compmy 21.0 Wellhead Schematic Milne Point Unit M-21 SB Injector Drilling Procedure Nate: Dimen-noma infonnition reflected on flus dr3W g ire a ti ited ne3zruemeatz onh. Page 41 Milne Point Unit M-21 SB Injector Hilcorp Drilling Procedure Energy Company 22.0 Days Vs Depth x MI 4000 6000 c v 8000 ad M 10000 12000 14000 •111 Page 42 MPU M-21 SB OA Injector Days vs Depth 0 5 10 15 20 25 Days Hilcorp Energy Company 23.0 Formation Tops & Information Milne Point Unit M-21 SB Injector Drilling Procedure MPU M-21 Formations (wp03) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 1993 -1799 1857 817.08 8.46 LA3 3448 -3125 3183 1400.52 8.46 Schrader Bluff NA4146 -3580 3638 1600.72 8.46 Schrader Bluff OA 4857 -3803 1 3858 1 1697.52 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) zvd- 6Z�> GENERALIZED GEOLOGICAL FORECAST,,__ SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS AEC of NOTE: See individual Well Program for ra- T.-- Gubik specific casing design, depths. sizes. weights, grades and connections. • unconsolidated coarse to medium sand and small gravel with minor s+lbtona. 1,000' IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE .401111111111 SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 1750 Base permafrost Interbods of sand, clays and siltstones with occasional 2,000' show of coal. Watch possible sidetracking while washingrroamtng, L33 & L•t S. Sagan irktok - f No hydrates encountered on L -Pad wells drilled to date. Continued imerbods of sand, clays and siltstones with occasional shows of coal. Traces of pyrite at -!• 3100 It 3,000' Interval at+t- 3400 It can be stickyand tight (L-01). Clay into bods between 3000 and 4500 It C 3472'• L A 3657' Keand-v UGNU: Series of coarsening upward sands which aro 1-Ae,C,b) ` made up of: (from tap to bottom) coarse sand, fine sand, silty shale. Beller developed Intervening shales as you UGNU progress into the L and M (deeper), Ugnu and Schrader Bluff: Possible hydrocarbons limited L-wnds to SW corner of Milne dovelopment Northem area is (AS) dowmstruetwa and wet. •3739' Wand - 4000' (NA) Schrader Bluff Sands: 4,000' ,��„ (.AB.C.b. Continuad layering coarsening upward sands as abmo .t Schrader Bluff: Possible lost circulation E.r) except more condensed and with occasional coal. zone white drilling long strings and running •4170' AS»nd- Clay rich shale Interval 4300 to 4600 ft Ugnu and Schrader Bluff: Possible hydrocarbons limited casing. Recommend deep setting surface (OA)Aar, to SW co mor of Milne development Ls7 and L•45 are casing for Kuparuk long strings. Also, the completed In the Schrader Bluff sand. Northern area of Schrader Bluff sands are a potential Schrader L -Pad is downst,ucturo and wet, differential stack pipe interval if left un -cased Bluff C surface casing point In state below for Kuparuk long strings. Sands: I Schrader Stuff OB sand for longer reach wells. Page 43 Hilcorp Energy Company 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Milne Point Unit M-21 SB Injector Drilling Procedure 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 J Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. J H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 44 Milne Point Unit M-21 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 45 Hilcorp Energy Company 8-1/2" Hole Section: Milne Point Unit M-21 SB Injector Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No 1-12S 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. There are no wells with a separation factor of <1. Specific AC risk addressed in 8.5" hole section, 15. Page 46 '/ Hilcorp Energy Company 25.0 Dovon 14 Lavout 1 Page 47 m Milne Point Unit M-21 SB Injector Drilling Procedure Milne Point Unit M-21 SB Injector Hilcorp Drilling Procedure E.e� C—PAY 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 48 L W p L U -0 N � U O CL y a - C Cy C O N y -all lll�" RIG 14 LEGEND White Handled Valves QD Normally Open Red Handled Valves IV Normally Closed Date: 08-22-14 Rev, 3 NOTES: 1) Valve A is a 3-1116" SM Remote Operated Hydraulic Choke Valve. 2) Valve S is a 3-118" SM Adjustable Choke Valve. 3) Valve I is a 2-1116" SM Manual Gate Valve, 4) Valves 2-14 are 3-118" SM Manual Gate Valves. Divert Line From BOP Divert line 1 7. To Mud/Gas Separator 28.0 Casing Design 11 Calculation & Casing Design Factors HilMT DATE: 9/25/2019 WELL: MPU M-21 DESIGN BY: Joe Engel Criteria: Hole Size 12-1/4" Mud Density: 9.2 ppg Hole Size 8-1/2" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1312 psi (see attached MASP detennination & calculation) MASP: Production Mode MASP: 1312 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 I tr3Lia�w Milne Point Unit Calculation/Specification 1 2 a. 3 4 M-21 SB Injector 9-5/8" Hilcorp Enema Compmy Drilling Procedure 28.0 Casing Design 11 Calculation & Casing Design Factors HilMT DATE: 9/25/2019 WELL: MPU M-21 DESIGN BY: Joe Engel Criteria: Hole Size 12-1/4" Mud Density: 9.2 ppg Hole Size 8-1/2" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1312 psi (see attached MASP detennination & calculation) MASP: Production Mode MASP: 1312 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 I tr3Lia�w Page 50 Casing Section Calculation/Specification 1 2 a. 3 4 Casing OD 9-5/8" ..6-w Top (MD) 0 4,769 Top (TVD) 0 3,884 Bottom (MD) 4,769 13,966 Bottom (TVD) 3,884 3,638 Length 4,769 9,197 Weight (ppf) 40 3.i Grade L-80 L-80 Connection TXP HW2 (, i Weight w/o Bouyancy Factor (lbs) 190,760 Z3 94V- Writ- _ Tension at Top of Section (lbs) 190,7601&3;946 Min strength Tension (1000 lbs) 916 093,1 3,; Worst Case Safety Factor (Tension) 4.80 2-W i/ Collapse Pressure at bottom (Psi) 1,919 1,797 Collapse Resistance w/o tension (Psi) 3,090 3;475 ys- Worst Case Safety Factor (Collapse) 1.61 i W V 11,71 MASP (psi) 1,312 1,312 Minimum Yield (psi) 5,750 tot Worst case safety factor (Burst) 4.38 .4** T & - Page 50 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 1 8-1/2" Hole Section Hit ""' MPU M-21 Milne Point Unit MD TVD Planned Top: 4770 3854 Planned TD: 13966 3638 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sandi 3,858 1698 1 Oil 1 8.46 1 0.440 Offset Well Mud Densities Well MW ranee Too (TVD) Bottom (TVD) Date L-50 8.8-9.1 Milne Point Unit 4125 2015 L-49 M-21 SB Injector Surface Hilcorp Energy Company Drilling Procedure 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 1 8-1/2" Hole Section Hit ""' MPU M-21 Milne Point Unit MD TVD Planned Top: 4770 3854 Planned TD: 13966 3638 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sandi 3,858 1698 1 Oil 1 8.46 1 0.440 Offset Well Mud Densities Well MW ranee Too (TVD) Bottom (TVD) Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore togas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,858 (ft) x 0.78(psi/ft)= 3009 3009(psi) - [0.1(psi/ft)*3858(ft)]= 2623 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 3858 (ft) x 0.44(psi/ft)= 1698 psi 1698(psi) - 0.1(psi/ft)*3858(ft) 1312 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation i of entire wellbore to gas at 0.1 psi/ft. Page 51 Hilcorp E..W Company 30.0 Spider Plot (NAD 27) (Governmental Sections) Sec. 15 .a7.p�. i Sec. 22 Milne Point Unit M-21 SB Injector Drilling Procedure Fes, V ? ADL355023 Sec �7 ADL388235 Se :,12- ` Y C 628; 11 &Up❑d 5+ 19 Page 52 Milne Point Unit MPU M-21 Well wp_ 3 Alaska State Piane Zone 4 NAD 1927 0 1.000 2,000 Feet A�-41 r �,i EAU, •_ e r ♦ "'•�``.,Sf-'li TPE3 v.�.:12Ps� 0 M-21 i_SHL Other Surface Holes (SHL) RUK RIVE# �UNIT M-21 i_TPH Other Bottom Holes {BHI,t~e Sec. 31 - - - OtherWeh Paths Sec. 25 (636) J + M-21i_BHL Coastline (US�GS 1:63k) t QOil and Gas Unit Boundary a+,` Sec.. 16 sec. 14 r, r SeZ. 13 `� �! r 1530i r r -W,19 �A% ! r \♦ r � •. �' .:r y E tl V� a� MILNE=POINT UNiT ,r U013NO10E xr ."Ual3N009E f " 1Y ! .+� r r �L-13 f t i'r � tr 4 L1 rW Gni !i sE � L.'i LZD r ' I L-ssl 4 4 rt Ste. 23 1 tl f31.;Sec'24 Set:. 19 � r L — S-STc't -_..' PSI + vx 11 &Up❑d 5+ 19 Page 52 Milne Point Unit MPU M-21 Well wp_ 3 Alaska State Piane Zone 4 NAD 1927 0 1.000 2,000 Feet a Legend EAU, •_ F- FNT,rA..C., 0 M-21 i_SHL Other Surface Holes (SHL) RUK RIVE# �UNIT M-21 i_TPH Other Bottom Holes {BHI,t~e Sec. 31 - - - OtherWeh Paths Sec. 25 (636) J + M-21i_BHL Coastline (US�GS 1:63k) t QOil and Gas Unit Boundary t r Fad Fooipe'n1 r r -W,19 11 &Up❑d 5+ 19 Page 52 Milne Point Unit MPU M-21 Well wp_ 3 Alaska State Piane Zone 4 NAD 1927 0 1.000 2,000 Feet H Hilcorp Energy Company 31.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-21 SB Injector Drilling Procedure Page 53 12 —c'm z TFIS PROJECT MOOSE FAD SEC 12 it SEC. 13 sic 14 r -I a J:�M PAD A� 0 M-13 0 IA -I* 23 a M -is m-18 ACINITY MAP I NTS M-22 M-17 M-18 Kcr M-19 ..... . ......... . ? ..... GRAPHIC SCALE[ htO 7 PAS110200 C Im 2W ACC IN FEET 1 Inch 200 fl. SJRV�- DBL5-LERDFJ.ATE LEGF NIM NOTES: - t HERESY CERTIFY THA' I AN AS-,BUL'r CCNDUCTCft I A"A, STATE RAW 0ODRCNA1E5 ARE. MAD;7. 204E 4. PRCPFRLY RFC157ERED AND IJCENMD 70 PRAC-.IQE LkNI3 SLFFVEY"GLy 2 CE00EPC POS"S ARE RAJ27. HE STATE CF ALASKA AND T, -,A7 CC"D.tICRTHIS .5 BASIS 7 HMIZCNAL AND %ERT'124 CONTRIA. IS AS -BUILT RV;RESENTIS A SUWVEY WADE 8'y WE OR UNDER WY DIRECT %rALCAP Sm NE. SjdfRMSCN AND THAT ALL 4NPU MDOSE AL1ERQ4E PAO SCALE FACTOR I, 0. 1911. DfAINSIONS AND OWER DETALS AW CORRECT AS OF WAf 1, 20',9. a DATES OF SLR*Y. WAY I & 16, NIB. 6. RU RDD HELD BOOK HV9-03 POO 14-14. 22-24 LOCATED WTHIN PROTRACTEO SEC, 14, T, 1.3 N, R. 9 E-, UMIAT MERIDIAN, ALASKA IAELL A,S.P, PLANTCOORDINATES OETIC GE% GEODETIC SECTION PAD CEIJ - AR COORDINATES POSH N PCSITI0N(DA/D) OFFSETS ELEVATION BOX EL , M-17 _(GMS) Y= 6,027.765.65 N- 1,168-00 70-29-12.792- 70,4968866- 4,914' FSL 24.87 24.9' X= 533,63187 E= 1,635-03 !49'43'30-357" 149-7250993' 531' FEL M -Ts Y= 6,027.76&611 N- 1,11 67. 96 70'29'12.793' 70.4-568865' 4,915' FSL 24, 9' 24.7' X= 533,150327 E= 1,605.02 14543'31.240" 749.7253445* .561' FEL Y= 6,027.76 -S5 N- 1,167.90 7079'12.795' 70.4,86a878' 4,915' F,% 24.9 251, M-19 X= 5,33,511132 Z= 1,514-96 ',49'43'33.890" 149,726,3805" 651' FEL Y- 6,027 1589.77 N- 1.292,14 7029*14,007' 70.4872242' 5038: FSL 2-.9' 25.0' M-21 X= $33:753.82 E- 1,754.99 149'4,3'26-811-1 149,7241143- 411 FEL Y- 6,027,15139M N= 1,292.2 70'29'14,012' t,4943'29,456"l 70.4872255' 5.039: FSL 2S.0 M-22 X= 533,66195 E- 1.665.11 149,7248489' 500 FEL .24� I I mmemorsal Mw 014'ER B.IMHART Del I RMWOMNOM we Hficorp Alaska - 4-- — MPIJ MOOSE PAD AS -BUILT CONDUCTORS WELLS 17.16,19,21,22 -------------------- Page 53 Milne Point Unit M-21 SB Injector Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, ppb 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.910.110.310.5 0 1 11111 N m 1500 _ori 2500 3000 3500 = 4500 Page 54 MPU L-46 (2015) MPU L-47 (2015) MPU L-48 (2015) MPU L-49 (2015) MPU L-50 (2015) MPU F-106 (2017) MPU F-107 (2017) MPU F-108 (2017) MPU F-109 (2017) MPU F-110 (2017) Milne Point Unit M-21 SB Injector Hilco Drilling Procedure En.w C-� 33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD to 5.Do Pipe Body Wall Thickness tit; 0.362 Pipe Body Grads S-135 Drill Pipe Length Range2 Connection GPDS50 Tool Joint OD 6.625 Toot Joint ID In: 3-25D Pin Tong 19 Box Tong In 12 80 % Inspection Class Best Estimates I Nominal V&-ight Designation 19.510 Drill Pipe Approximate Length > 31.5 SmootttEotge Height cmi 3132 Raised Tool Joint SMYS p ; 120.000 Upset Type IIEU Max upset OD {DTE} r. 5.125 Friction Factor 1.0 46.500 NclTorp Space may Include har=drg. Drill Pipe Performance Drill -Pipe Length ftange2 Performance of Drill Pipe with Pipe Body at n Best Estimates I Nominal 80 % 1ns ectlon Class ¢A"=d.O.wUVI I twnftcoallrp1 -- (Law aI trrlet AXE fdale P Operational flax Ter, ar, Tool Joint Tomo nal Strength (o-1tS) Drill Pipe Adjusted Weight Obs�nt 24.11 2329 0.36 T ams, Torque m-m.t na., 46.500 Fluid DisDiacement (I-.810.37 Fluid Displacement ;Rhl-nt+ Shoulder Information Tension ono, 0 560.800 0.0085 �ruT 43,10Q ,, LoaCnII 39,600 410.500 {w 15.672 Fluid Ca trent+ 0.70 Elevator Capacity rl 1,658,000 1,440, 0.72 0 O472 tool 5.000 M •d C eua 0 0169 0 0167 4.855 ul .pool:}+ 36,140 Tension only 0 MEN 3.125 fnrwntan nrur Drift Size SInI } L�edlaII 32 100 46? 400 - - yJ Notes Op tkla 6an.1 equals 42 US gallcra . \\ tW te, Doll ppre a..'erndy YalUeS arr• it >. rlrna7e.. antl naaY va'y dti to Ftp. t' cdy m11 toYzrah_e, them I I,I z- s9ati,g. arty. aide: faCYrS. Connection Performance GPDS50 ( 6.625 on) OD X 3.250 eta ID ) 120,000 Ow) FAIIPB.d tww. P ITarY.an al.shaulaer IT -1- 0 - Mr, Too[ Jatnt Dimensions..- Belanced OD - OI,I 6.435 +.arvn,um Toa Jaid on gar API 5.930 Prarnkem Class {Inl fgrxtnt�rl Toa t� co ur 5.93 Caunterbom Iln' To+qut lS.P ratan In-Dsl Maximum Make-up Torque 143,,100 Tens4le bled -_ _ _ lvfsnimum Make-uo Torque 136,100 11.202,500 Nc;e The r.'.a,tmam makr,. 7<argI a sh"Id he a"Oed atm P-5be Nc{e: Te maaknC. cannectan aaera"enal Inst.. a FV rr 114 - 37 Slip;NbN'� Should be applSed 58.100 Tool Joint Tomo nal Strength (o-1tS) 71.800 1.24 1.24 Tool Joint Tensile Strength f0s) 1250:D00 46.500 Elevator Shoulder Information tpvi 17.105 5moothEdge Height Nomi 156,38 3+32 Raised {w 15.672 Box OD dlr, 6.812 6.625 Elevator Capacity rl 1,658,000 1,440, Pipe OD Elevator OD 3132 Raised 6.812 au Tooi Joint Wom to Bevel Worn to Min TJ OD for OD I Diameter I API Premium Class 5219 Nolo Ekva a csasc ty 4astd sn aswmcd Ekvaly fore, na uear fade ,and contact sews at t iO,tOCpsl. Assumed Elevator Bore Diameter 4n' NVI A raised c:evator OD Ir•.tteasr elevator c�-Ity +•`thcul. off--1mg -ke-op torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration ( 5 - OD 0.362 (m) Wan S-135) Nominal 1 80 %Inspection Class I API Premium Class ISlip Crushinq Capacity t,.. 498,3DD 1396500 13965DO . N,te, SAP C,-1 tg SIG.:sting Wd Is calcllated-A ah tx "-�pt l cr "d MLZ6-from V.er,' Cots 0:91 pAe YY AssumedSliRLength (P*16.5 Fal �T.SOA 47 MM Ct. leceVthe SOle"I+aruuatrnrl-•ekdrauxSt-mngtrremtence Transverse Load Factor fKY 14.2 g�Yj ar,� sea°"x"eInt"etiGx c a dcacaun,=oro ten«roc n wmrec-:1211-T, GS. p®e DD rad NN aan�;rt. sd other ixtnes. Ca cJl wIM the s!P ms+,ra!Ym by ad[f9aul r(a+m9bn.. Pipe Body Performance Pipe Body Configuration t 5 00 OD 0.362 - Wall S-135) Nominal 180 % Inspection Class I API Premium Class ZA K Y Grant Page 55 Pipe Tensile Strength o-tr 712,100 560,800 560,800 Pipe Torsional Strength ('R-1-1 74.100 58.100 58.100 TJIPipeBody Torsional Ratio 0.97 1.24 1.24 80% Pipe Torsional Strength of-Ibst 59,300 46.500 46,5D0 Burst tpvi 17.105 15,638 156,38 Collapse {w 15.672 10.029 10.029 Pipe OD tool 5.000 4-855 4.855 Wall Thickness tml 0.362 0.290 0.290 Nominal Pipe 1D (mi 4.276 4.276 4276 Cross Sectional Area of Pipe Body an -1 5.275 4.154 4.154 Gross Sectional Area of OD Q1^21 19.635 1&514 18.514 Cross Sectional Area of ID "21436O 14.360 14.360 Section Modulus nn•at 5:708 4.476 4.476 Polar Section Modulus 01'31 111.415 8.953 8.953 Not.: N -A-1 aur¢ cW-lated .1 07.5% R81A1 Per API. I/ Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-21 i MPU M-21 i Plan: MPU M-21 i wp03 Standard Proposal Report 26 September, 2019 HALLIBURTON Sperry Drilling Services Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-21 i Wellbore: MPUM-21i Design: MPU M -21i wp03 Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -21i, True North Vertical (TVD) Reference: MPU M-21 Planned RKB @ 58.70usft Measured Depth Reference: MPU M-21 Planned RKB @ 58.70usft Calculation Method: Minimum Curvature FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1314.70 1256.00 1 34 1.68 SV5 1657.70 1799.00 1993.12 BPRF 2801.70 2743.00 3046.35 UG COAL1 3183.7n 3125.00 3448.49 LA3 3638.70 3580.00 4051.11 BHL OA (Toe) 3690.70 3632.00 4146.98 SB NA CASING DETAILS TVD TVDSS MD Size Name 114.00 55.30 114.00 20 20" 3854.12 3795.42 4770.00 9-5/8 9-5/8" X 12-1/4" 3573.70 3515.00 14184.38 4-1/2 4-1/2" X 8-1/2" f- HALUBURTON $pvmY Owl llln[3 �� -800 0 C 800 to 0 0 (o 1600 Q a> C0 2400 3200 4000 JCUI IVIV -1M 0 Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 - _ __ _ _ _ _ - - _-. _ - _ - Start Dir 3°/100' : 500' MD, 5007VD 3 1723.17 36.70 18.09 1641.25 359.77 117.55 3.00 18.09 -366.11 L477 End Dir : 1723.17' MD, 1641.25' TVD 4 2260.19 36.70 18.09 2071.84 664.80 217.21 0.00 0.00 -676.51 - - - - - Start Dir 50/100': 2260.19' MD, 2071.841TVD 5 4707.42 87.00 183.40 3850.85 -228.42 480.40 5.00 162.55 199.53 End Dir : 4707.42' MD, 3850.85' TVD 6 4857.42 87.00 183.40 3858.70 -377.95 471.52 0.00 0.00 349.32 M -21i Heel wp03 Start Dir 4°/100' : 4857.42' MD, 3858.71TVD 7 4993.82 92.45 183.52 3859.35 -514.05 463.29 4.00 1.21 485.67 0 0 cn Ln CD End Dir : 4993.82' MD, 3859.35' TVD 8 10819.80 92.45 183.52 3609.80 -6323.74 106.40 0.00 0.00 6306.29 M-21 wp03 CP1 Start Dir 40/100': 10819.8' MD, 3609.8'TVD 9 10906.18 89.00 183.52 3608.70 -6409.93 101.10 4.00 179.92 6392.65 M-21 wp03 CP1 10 11028.05 84.14 183.15 3615.99 -6531.34 94.03 4.00 -175.65 6514.26 End Dir : 11028.05' MD, 3615.99' TVD 11 11250.36 84.14 183.15 3638.69 -6752.16 81.88 0.00 0.00 6735.41 Start Dir 4°/100' : 11250.36' MD, 3638.697VD 12 11434.38 91.50 183.18 3645.69 -6935.63 71.74 4.00 0.25 6919.17 End Dir : 11434.38' MD, 3645.69' TVD 13 14184.38 91.50 183.18 3573.70 -9680.46 -80.76 0.00 0.00 9668.21 M-21 Toe wp03 Total Depth : 14184.38' MD, 3573.7' TVD A - Start Dir 3°/100' :500' MD, 500'TVD 500 WELL DETAILS: Plan: MPU M -21i SURVEY PROGRAM Date: 2016-08-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 33.70 4770.00 MPU M -21i wp03 (MPU M-21 i) 2 MWD+IFR2+MS+Sag 4770.00 14184.38 MPU M -21i wp03 (MPU M-21 i) 2_MWD+IFR2+MS+Sag WELL DETAILS: Plan: MPU M -21i -1600 -800 0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 Vertical Section at 183.40° (1600 usft/in) Ground Level: 25.00 +N/-S +E/ -W Northing Easting Latittude Longitude 6027889.77 nd Dir : 1723.17' MD, 1641.25' TVD 0.00 0.00 533753.82 70° 29' 14.007 N 149° 43'26.812 SV5"rt Dir 5°/100' : 2260.19' MD, 2071.84'TVD BPRF - _ __ _ _ _ _ - - _-. _ - _ - _ _ - - _ - _ - - - - _ _--_. _ - _ _- _ - - - _ _ _ _ -Start Dir 4°/100' : 10819.8' MD, 3609.8'TVD Start Dir 4°/100' : 11250.36' MD, 3638.69'TVDr L477 :4707.42' MD, 3850.85' TVD End Dir :11028.05' MD, 3615.99' TVD uGcoAL1 - - - _ - - -- - - - - - - - - - - - - - - - - End Dir : 11434.38'MD, 3645.69'TVD - - - - - - - - - - Start Dir 4°/100'; 4857.42'MD, 3858.7'TVD oTotal " Depth : 14184.38' MD, 3573.7'TVD LA3 OA , - End Dir : 4993.82'MD, 3859.35'TVDBHL (Toe) SBNA _ - a �+ O O1 0 00 O 0 0 cn Ln CD o cn o cn o 4-1/2" X 8-1/2" O SB OA (- heel) C\ 0 0 00 p O O o O o o O O o 9-5/8" X 12-1/4" 1 M-211 Heel wp03 M-21 wp03 CP1 M-21 Toe w 03 p P MPU M -21i w 03 -1600 -800 0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 Vertical Section at 183.40° (1600 usft/in) WELL DETAILS: Plan: MPU i Ground Level: 25.00 +N/ -S +E/ -W Northing Easting Latittude 0.00 0.00 6027889.77 533753.82 70° 29' 14.007 N TVD TVDSS MD Size Name 114.00 55.30 114.00 20 20" 3854.12 3795.42 4770.00 9-5/8 9-5/8" X 12-1/4" 3573.70 3515.00 14184.38 4-1/2 4-1/2" X 8-1/2" REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -21i, True North Vertical (TVD) Reference: MPU M-21 Planned RKB @ 58.70usft Measured Depth Reference: MPU M-21 Planned RKB @ 58.70usft Calculation Method: Minimum Curvature Start Dir 5°/100' : 2260.19' MD, 2071.841TVD 750 - - End Dir : 1723.17' MD, 1641.25' TVD 0 - - - - - -- Start Dir 3°/100': 500'MD, 500'TVD- -750 -1500 -2250 w a 0 -3000 o -3750 rn -4500 -5250 -6000 -6750 -7500 -8250 -10500 HALLIBIJllf 31Y Project: Milne Point Site: M Pt Moose Pad Longitude Spor.V Drilling Well: Plan: MPU M -21i 149° 43'26.812 W Wellbore: MPU M -21i Plan: MPU M -21i wp03 M -21i Heel wp0 End Dir : 4707.42' MD, 3850.85' TVD Start Dir 4'/100': 4857.42' MD, 3858.7'TVD End Dir : 4993.82' MD, 385935' TVD Start Dir 41/100': 10819.8' MD, 3609.8'TVD End Dir : 11028.05' MD, 3615.99' TVD - - Start Dir 40/100': 11250.36' MD, 3638.69TVD End Dir : 11434.38' MD, 3645.69' TVD M-21 Toe wp(ij - - Total Depth : 14184.38' MD, 3573.7' TVD i i MPU M-21 i wp03 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 West( -)/East(+) (1500 usft/in) ]Zr.!l IR 14 1 =IEJ _ w TI Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -21i Wellbore: MPU M -21i Design: MPU M -21i wp03 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-21 i TVD Reference: MPU M-21 Planned RKB @ 58.70usft MD Reference: MPU M-21 Planned RKB @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Usinq Well Reference Point Map Zone: Alaska Zone 04 Usinq qeodetic scale factor Design MPU M -21i wp03 Site M Pt Moose Pad Audit Notes: Site Position: Northing: 6,027,877.65 usft Latitude: 70° 29' 13.905 N From: Map Eastinq: 533,363.92 usft Longitude: 149° 43'38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M -21i 33.70 Well Position +N/ -S 0.00 usft Northing: 6,027,889.77 usft Latitude: 70° 29' 14.007 N +N/ -S +E/ -W 0.00 usft Eastinq: 533,753.82 usft Longitude: 149° 43' 26.812 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 25.00 usft Wellbore MPU M -21i Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (I (°) (nT) BGGM2018 12/31/2014 19.11 81.07 57,594.94033021 Design MPU M -21i wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 l Vertical Section: Depth From (TVD) +N/ -S +El -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 183.40 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclinatio Azimut Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) n h (usft) usft (usft) (usft) (°/100usft) (°/100usft (°/100usft (°) 33.70 0.00 0.00 33.70 -25.00 0.00 0.00 0.00 0.00 0.00 0.00 500.00 0.00 0.00 500.00 441.30 0.00 0.00 0.00 0.00 0.00 0.00 1,723.17 36.70 18.09 1,641.25 1,582.55 359.77 117.55 3.00 3.00 0.00 18.09 2,260.19 36.70 18.09 2,071.84 2,013.14 664.80 217.21 0.00 0.00 0.00 0.00 4,707.42 87.00 183.40 3,850.85 3,792.15 -228.42 480.40 5.00 2.06 6.75 162.55 4,857.42 87.00 183.40 3,858.70 3,800.00 -377.95 471.52 0.00 0.00 0.00 0.00 4,993.82 92.45 183.52 3,859.35 3,800.65 -514.05 463.29 4.00 4.00 0.08 1.21 10,819.80 92.45 183.52 3,609.80 3,551.10 -6,323.74 106.40 0.00 0.00 0.00 0.00 10,906.18 89.00 183.52 3,608.70 3,550.00 -6,409.93 101.10 4.00 -4.00 0.01 179.92 11,028.05 84.14 183.15 3,615.99 3,557.29 -6,531.34 94.03 4.00 -3.99 -0.30 -175.65 11,250.36 84.14 183.15 3,638.69 3,579.99 -6,752.16 81.88 0.00 0.00 0.00 0.00 11,434.38 91.50 183.18 3,645.69 3,586.99 -6,935.63 71.74 4.00 4.00 0.02 0.25 14,184.38 91.50 183.18 3,573.70 3,515.00 -9,680.46 -80.76 0.00 0.00 0.00 0.00 9/26/2019 8:45:49PM Paae 2 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-21 i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-21 Planned RKB @ 58.70usft Project: Milne Point MD Reference: MPU M-21 Planned RKB @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-21 i Survev Calculation Method: Minimum Curvature Wellbore: MPU M -21i (°) Desiqn: MPU M -21i wp03 (usft) (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +El -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -25.00 Section 33.70 0.00 0.00 33.70 -25.00 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 100.00 0.00 0.00 100.00 41.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 114.00 0.00 0.00 114.00 55.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 20" 200.00 0.00 0.00 200.00 141.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 300.00 0.00 0.00 300.00 241.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 400.00 0.00 0.00 400.00 341.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 500.00 0.00 0.00 500.00 441.30 0.00 0.00 6,027,889.77 533,753.82 0.00 0.00 Start Dir 31/100': 500' MD, 500TVD 600.00 3.00 18.09 599.95 541.25 2.49 0.81 6,027,892.26 533,754.62 3.00 -2.53 700.00 6.00 18.09 699.63 640.93 9.95 3.25 6,027,899.73 533,757.02 3.00 -10.12 800.00 9.00 18.09 798.77 740.07 22.35 7.30 6,027,912.15 533,761.02 3.00 -22.74 900.00 12.00 18.09 897.08 838.38 39.67 12.96 6,027,929.50 533,766.60 3.00 -40.37 1 1,000.00 15.00 18.09 994.31 935.61 61.86 20.21 6,027,951.71 533,773.75 3.00 -62.95 1,100.00 18.00 18.09 1,090.18 1,031.48 88.85 29.03 6,027,978.74 533,782.45 3.00 -90.42 1,200.00 21.00 18.09 1,184.43 1,125.73 120.58 39.40 6,028,010.51 533,792.67 3.00 -122.70 1,300.00 24.00 18.09 1,276.81 1,218.11 156.95 51.28 6,028,046.94 533,804.38 3.00 -159.72 1,341.68 25.25 18.09 1,314.70 1,256.00 173.46 56.68 6,028,063.47 533,809.70 3.00 -176.52 SVff 1,400.00 27.00 18.09 1,367.06 1,308.36 197.87 64.65 6,028,087.91 533,817.57 3.00 -201.35 1,500.00 30.00 18.09 1,454.93 1,396.23 243.22 79.47 6,028,133.32 533,832.18 3.00 -247.50 1,600.00 33.00 18.09 1,540.18 1,481.48 292.88 95.69 6,028,183.05 533,848.18 3.00 -298.04 1,700.00 36.00 18.09 1,622.59 1,563.89 346.71 113.28 6,028,236.96 533,865.52 3.00 -352.82 1,723.17 36.70 18.09 1,641.25 1,582.55 359.77 117.55 6,028,250.03 533,869.72 3.00 -366.11 End Dir : 1723.17' MD, 1641.25' TVD 1,800.00 36.70 18.09 1,702.85 1,644.15 403.41 131.81 6,028,293.73 533,883.78 0.00 -410.51 1,900.00 36.70 18.09 1,783.04 1,724.34 460.21 150.37 6,028,350.61 533,902.08 0.00 -468.31 1,993.12 36.70 18.09 1,857.70 1,799.00 513.10 167.65 6,028,403.57 533,919.12 0.00 -522.14 BPRF 2,000.00 36.70 18.09 1,863.22 1,804.52 517.01 168.93 6,028,407.49 533,920.38 0.00 -526.12 2,100.00 36.70 18.09 1,943.40 1,884.70 573.81 187.48 6,028,464.37 533,938.68 0.00 -583.92 2,200.00 36.70 18.09 2,023.58 1,964.88 630.61 206.04 6,028,521.25 533,956.98 0.00 -641.72 2,260.19 36.70 18.09 2,071.84 2,013.14 664.80 217.21 6,028,555.48 533,967.99 0.00 -676.51 Start Dir 5°/100' : 2260.19' MD, 2071.84'TVD 2,300.00 34.80 19.14 2,104.15 2,045.45 686.84 224.63 6,028,577.55 533,975.31 5.00 -698.95 2,400.00 30.09 22.27 2,188.53 2,129.83 737.03 243.50 6,028,627.82 533,993.95 5.00 -750.17 2,500.00 25.48 26.42 2,276.98 2,218.28 779.51 262.58 6,028,670.39 534,012.84 5.00 -793.71 2,600.00 21.03 32.23 2,368.85 2,310.15 813.97 281.73 6,028,704.93 534,031.83 5.00 -829.25 2,700.00 16.87 40.85 2,463.43 2,404.73 840.14 300.81 6,028,731.19 534,050.78 5.00 -856.50 2,800.00 13.29 54.39 2,560.00 2,501.30 857.82 319.66 6,028,748.95 534,069.55 5.00 -875.27 2,900.00 10.87 75.50 2,657.82 2,599.12 866.88 338.15 6,028,758.09 534,088.00 5.00 -885.41 3,000.00 10.44 102.70 2,756.16 2,697.46 867.25 356.13 6,028,758.54 534,105.97 5.00 -886.85 3,046.35 11.03 114.76 2,801.70 2,743.00 864.47 364.25 6,028,755.80 534,114.11 5.00 -884.55 UG -COAL1 3,100.00 12.22 126.71 2,854.26 2,795.56 858.93 373.46 6,028,750.30 534,123.35 5.00 -879.56 9/26/2019 8:45:49PM Pape 3 COMPASS 5000.15 Build 91 Database: Company: Proiect: Site: Well: Wellbore: Desiqn: Planned Survey NORTH US + CANADA Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -21i MPU M -21i MPU M-21 i wp03 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -21i TVD Reference: MPU M-21 Planned RKB @ 58.70usft MD Reference: MPU M-21 Planned RKB @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (usft) (1) (usft) usft (usft) 3,200.00 15.47 142.78 2,951.38 2,892.68 841.97 3,300.00 19.45 152.90 3,046.77 2,988.07 816.51 3,400.00 23.82 159.57 3,139.72 3,081.02 782.75 3,448.49 26.01 162.03 3,183.70 3,125.00 763.46 LA3 534,196.75 5.00 -716.62 457.06 6,028,526.25 3,500.00 28.38 164.24 3,229.51 3,170.81 740.93 3,600.00 33.06 167.69 3,315.46 3,256.76 691.38 3,700.00 37.81 170.37 3,396.92 3,338.22 634.48 3,800.00 42.61 172.53 3,473.27 3,414.57 570.65 3,900.00 47.45 174.32 3,543.92 3,485.22 500.38 4,000.00 52.31 175.86 3,608.34 3,549.64 424.22 4,051.11 54.80 176.57 3,638.70 3,580.00 383.19 BHL OA (Toe) 490.92 6,027,964.69 534,244.36 5.00 -101.69 4,100.00 57.19 177.20 3,666.04 3,607.34 342.73 4,146.98 59.49 177.78 3,690.70 3,632.00 302.78 SEI -NA 5.00 192.12 480.40 6,027,663.55 534,235.20 4,200.00 62.08 178.41 3,716.58 3,657.88 256.54 4,300.00 66.98 179.51 3,759.57 3,700.87 166.30 4,400.00 71.89 180.53 3,794.68 3,735.98 72.70 4,500.00 76.80 181.50 3,821.66 3,762.96 -23.54 4,600.00 81.72 182.43 3,840.29 3,781.59 -121.70 4,700.00 86.64 183.33 3,850.44 3,791.74 -221.03 4,707.42 87.00 183.40 3,850.85 3,792.15 -228.42 End Dir : 4707.42' MD, 3850.85' TVD 534,202.03 0.00 791.57 4,770.00 87.00 183.40 3,854.12 3,795.42 -290.81 9-5/8" X 12-1/4" 534,190.68 0.00 991.39 426.16 4,800.00 87.00 183.40 3,855.70 3,797.00 -320.71 4,857.42 87.00 183.40 3,858.70 3,800.00 -377.95 Start Dir 4°/100' : 4857.42' MD, 3858.7'TVD - M-21 i Heel wp03 6,026,474.08 4,900.00 88.70 183.44 3,860.30 3,801.60 -420.43 4,993.82 92.45 183.52 3,859.35 3,800.65 -514.05 End Dir : 4993.82' MD, 3859.35' TVD 6,026,174.87 534,150.97 0.00 5,000.00 92.45 183.52 3,859.08 3,800.38 -520.22 5,100.00 92.45 183.52 3,854.80 3,796.10 -619.94 5,200.00 92.45 183.52 3,850.52 3,791.82 -719.66 5,300.00 92.45 183.52 3,846.23 3,787.53 -819.38 5,400.00 92.45 183.52 3,841.95 3,783.25 -919.10 5,500.00 92.45 183.52 3,837.67 3,778.97 -1,018.82 5,600.00 92.45 183.52 3,833.38 3,774.68 -1,118.54 5,700.00 92.45 183.52 3,829.10 3,770.40 -1,218.26 5,800.00 92.45 183.52 3,824.82 3,766.12 -1,317.98 5,900.00 92.45 183.52 3,820.53 3,761.83 -1,417.70 6,000.00 92.45 183.52 3,816.25 3,757.55 -1,517.42 6,100.00 92.45 183.52 3,811.97 3,753.27 -1,617.14 6,200.00 92.45 183.52 3,807.68 3,748.98 -1,716.86 9/26/2019 8:45:49PM Paw 4 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert (usft) (usft) (usft) 2,892.68 Section 390.03 6,028,733.42 534,139.98 5.00 -863.62 405.69 6,028,708.04 534,155.76 5.00 -839.14 420.33 6,028,674.34 534,170.55 5.00 -806.30 427.03 6,028,655.08 534,177.34 5.00 -787.44 433.84 6,028,632.59 534,184.25 5.00 -765.36 446.11 6,028,583.10 534,196.75 5.00 -716.62 457.06 6,028,526.25 534,207.95 5.00 -660.47 466.59 6,028,462.47 534,217.77 5.00 -597.32 474.65 6,028,392.25 534,226.14 5.00 -527.65 481.15 6,028,316.12 534,232.99 5.00 -452.01 483.86 6,028,275.12 534,235.89 5.00 -411.22 486.06 6,028,234.67 534,238.28 5.00 -370.95 487.81 6,028,194.73 534,240.20 5.00 -331.18 489.34 6,028,148.50 534,241.95 5.00 -285.11 490.97 6,028,058.28 534,243.98 5.00 -195.12 490.92 6,027,964.69 534,244.36 5.00 -101.69 489.21 6,027,868.45 534,243.08 5.00 -5.51 485.84 6,027,770.29 534,240.16 5.00 92.67 480.83 6,027,670.95 534,235.61 5.00 192.12 480.40 6,027,663.55 534,235.20 5.00 199.53 476.69 6,027,601.16 534,231.78 0.00 262.02 474.92 6,027,571.25 534,230.14 0.00 291.98 471.52 6,027,514.00 534,227.00 0.00 349.32 468.98 6,027,471.52 534,224.66 4.00 391.87 463.29 6,027,377.87 534,219.40 4.00 485.67 462.91 6,027,371.71 534,219.04 0.00 491.85 456.79 6,027,271.97 534,213.37 0.00 591.75 450.66 6,027,172.24 534,207.70 0.00 691.66 444.54 6,027,072.50 534,202.03 0.00 791.57 438.41 6,026,972.76 534,196.35 0.00 891.48 432.28 6,026,873.03 534,190.68 0.00 991.39 426.16 6,026,773.29 534,185.01 0.00 1,091.29 420.03 6,026,673.55 534,179.34 0.00 1,191.20 413.91 6,026,573.81 534,173.66 0.00 1,291.11 407.78 6,026,474.08 534,167.99 0.00 1,391.02 401.66 6,026,374.34 534,162.32 0.00 1,490.93 395.53 6,026,274.60 534,156.65 0.00 1,590.83 389.40 6,026,174.87 534,150.97 0.00 1,690.74 9/26/2019 8:45:49PM Paw 4 COMPASS 5000.15 Build 91 Halliburton HALLI BU RTO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-21 i Companv: Hilcorp Alaska, LLC TVD Reference: MPU M-21 Planned RKB @ 58.70usft Project: Milne Point MD Reference: MPU M-21 Planned RKB @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -21i Survev Calculation Method: Minimum Curvature Wellbore: MPU M -21i Depth Inclination Desiqn: MPU M-211 wp03 TVDss +N/ -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,744.70 Section 6,300.00 92.45 183.52 3,803.40 3,744.70 -1,816.58 383.28 6,026,075.13 534,145.30 0.00 1,790.65 6,400.00 92.45 183.52 3,799.12 3,740.42 -1,916.30 377.15 6,025,975.39 534,139.63 0.00 1,890.56 6,500.00 92.45 183.52 3,794.83 3,736.13 -2,016.02 371.03 6,025,875.65 534,133.95 0.00 1,990.47 6,600.00 92.45 183.52 3,790.55 3,731.85 -2,115.74 364.90 6,025,775.92 534,128.28 0.00 2,090.37 6,700.00 92.45 183.52 3,786.27 3,727.57 -2,215.46 358.77 6,025,676.18 534,122.61 0.00 2,190.28 6,800.00 92.45 183.52 3,781.98 3,723.28 -2,315.18 352.65 6,025,576.44 534,116.94 0.00 2,290.19 6,900.00 92.45 183.52 3,777.70 3,719.00 -2,414.90 346.52 6,025,476.71 534,111.26 0.00 2,390.10 7,000.00 92.45 183.52 3,773.42 3,714.72 -2,514.62 340.40 6,025,376.97 534,105.59 0.00 2,490.01 7,100.00 92.45 183.52 3,769.13 3,710.43 -2,614.34 334.27 6,025,277.23 534,099.92 0.00 2,589.91 7,200.00 92.45 183.52 3,764.85 3,706.15 -2,714.06 328.14 6,025,177.49 534,094.25 0.00 2,689.82 7,300.00 92.45 183.52 3,760.56 3,701.86 -2,813.78 322.02 6,025,077.76 534,088.57 0.00 2,789.73 7,400.00 92.45 183.52 3,756.28 3,697.58 -2,913.50 315.89 6,024,978.02 534,082.90 0.00 2,889.64 7,500.00 92.45 183.52 3,752.00 3,693.30 -3,013.22 309.77 6,024,878.28 534,077.23 0.00 2,989.55 7,600.00 92.45 183.52 3,747.71 3,689.01 -3,112.94 303.64 6,024,778.55 534,071.56 0.00 3,089.45 7,700.00 92.45 183.52 3,743.43 3,684.73 -3,212.66 297.52 6,024,678.81 534,065.88 0.00 3,189.36 7,800.00 92.45 183.52 3,739.15 3,680.45 -3,312.38 291.39 6,024,579.07 534,060.21 0.00 3,289.27 7,900.00 92.45 183.52 3,734.86 3,676.16 -3,412.10 285.26 6,024,479.33 534,054.54 0.00 3,389.18 8,000.00 92.45 183.52 3,730.58 3,671.88 -3,511.82 279.14 6,024,379.60 534,048.86 0.00 3,489.09 8,100.00 92.45 183.52 3,726.30 3,667.60 -3,611.54 273.01 6,024,279.86 534,043.19 0.00 3,588.99 8,200.00 92.45 183.52 3,722.01 3,663.31 -3,711.26 266.89 6,024,180.12 534,037.52 0.00 3,688.90 8,300.00 92.45 183.52 3,717.73 3,659.03 -3,810.98 260.76 6,024,080.39 534,031.85 0.00 3,788.81 8,400.00 92.45 183.52 3,713.45 3,654.75 -3,910.70 254.63 6,023,980.65 534,026.17 0.00 3,888.72 8,500.00 92.45 183.52 3,709.16 3,650.46 -4,010.42 248.51 6,023,880.91 534,020.50 0.00 3,988.63 8,600.00 92.45 183.52 3,704.88 3,646.18 -4,110.14 242.38 6,023,781.17 534,014.83 0.00 4,088.53 8,700.00 92.45 183.52 3,700.60 3,641.90 -4,209.86 236.26 6,023,681.44 534,009.16 0.00 4,188.44 8,800.00 92.45 183.52 3,696.31 3,637.61 -4,309.58 230.13 6,023,581.70 534,003.48 0.00 4,288.35 8,900.00 92.45 183.52 3,692.03 3,633.33 -4,409.30 224.00 6,023,481.96 533,997.81 0.00 4,388.26 9,000.00 92.45 183.52 3,687.75 3,629.05 -4,509.02 217.88 6,023,382.23 533,992.14 0.00 4,488.17 9,100.00 92.45 183.52 3,683.46 3,624.76 -4,608.75 211.75 6,023,282.49 533,986.47 0.00 4,588.07 9,200.00 92.45 183.52 3,679.18 3,620.48 -4,708.47 205.63 6,023,182.75 533,980.79 0.00 4,687.98 9,300.00 92.45 183.52 3,674.90 3,616.20 -4,808.19 199.50 6,023,083.01 533,975.12 0.00 4,787.89 9,400.00 92.45 183.52 3,670.61 3,611.91 -4,907.91 193.38 6,022,983.28 533,969.45 0.00 4,887.80 9,500.00 92.45 183.52 3,666.33 3,607.63 -5,007.63 187.25 6,022,883.54 533,963.77 0.00 4,987.71 9,600.00 92.45 183.52 3,662.05 3,603.35 -5,107.35 181.12 6,022,783.80 533,958.10 0.00 5,087.61 9,700.00 92.45 183.52 3,657.76 3,599.06 -5,207.07 175.00 6,022,684.07 533,952.43 0.00 5,187.52 9,800.00 92.45 183.52 3,653.48 3,594.78 -5,306.79 168.87 6,022,584.33 533,946.76 0.00 5,287.43 9,900.00 92.45 183.52 3,649.20 3,590.50 -5,406.51 162.75 6,022,484.59 533,941.08 0.00 5,387.34 10,000.00 92.45 183.52 3,644.91 3,586.21 -5,506.23 156.62 6,022,384.85 533,935.41 0.00 5,487.25 10,100.00 92.45 183.52 3,640.63 3,581.93 -5,605.95 150.49 6,022,285.12 533,929.74 0.00 5,587.15 10,200.00 92.45 183.52 3,636.35 3,577.65 -5,705.67 144.37 6,022,185.38 533,924.07 0.00 5,687.06 10,300.00 92.45 183.52 3,632.06 3,573.36 -5,805.39 138.24 6,022,085.64 533,918.39 0.00 5,786.97 10,400.00 92.45 183.52 3,627.78 3,569.08 -5,905.11 132.12 6,021,985.91 533,912.72 0.00 5,886.88 10,500.00 92.45 183.52 3,623.50 3,564.80 -6,004.83 125.99 6,021,886.17 533,907.05 0.00 5,986.79 10,600.00 92.45 183.52 3,619.21 3,560.51 -6,104.55 119.86 6,021,786.43 533,901.38 0.00 6,086.69 10,700.00 92.45 183.52 3,614.93 3,556.23 -6,204.27 113.74 6,021,686.69 533,895.70 0.00 6,186.60 9/26/2019 8:45:49PM Pape 5 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-21 i Companv: Hilcorp Alaska, LLC TVD Reference: MPU M-21 Planned RKB @ 58.70usft Project: Milne Point MD Reference: MPU M-21 Planned RKB @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -21i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -21i (usft) (1) Desiqn: MPU M -21i wp03 usft (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,551.94 Section 10,800.00 92.45 183.52 3,610.64 3,551.94 -6,303.99 107.61 6,021,586.96 533,890.03 0.00 6,286.51 10,819.80 92.45 183.52 3,609.80 3,551.10 -6,323.74 106.40 6,021,567.21 533,888.91 0.00 6,306.29 Start Dir '4°/100' : 10819.8' MD, 3609.8'ND 10,900.00 89.25 183.52 3,608.61 3,549.91 -6,403.76 101.48 6,021,487.17 533,884.35 4.00 6,386.47 10,906.18 89.00 183.52 3,608.70 3,550.00 -6,409.93 101.10 6,021,481.00 533,884.00 4.00 6,392.65 M-21 wp03 CP1 11,000.00 85.26 183.23 3,613.40 3,554.70 -6,503.45 95.58 6,021,387.46 533,878.91 4.00 6,486.34 11,028.05 84.14 183.15 3,615.99 3,557.29 -6,531.34 94.03 6,021,359.57 533,877.48 4.00 6,514.27 End Dir : 11028.05' MD, 3615.99' ND 11,100.00 84.14 183.15 3,623.34 3,564.64 -6,602.81 90.10 6,021,288.09 533,873.87 0.00 6,585.84 11,200.00 84.14 183.15 3,633.55 3,574.85 -6,702.13 84.63 6,021,188.75 533,868.86 0.00 6,685.32 11,250.36 84.14 183.15 3,638.69 3,579.99 -6,752.15 81.88 6,021,138.72 533,866.33 0.00 6,735.41 Start Dir 4°/100' : 11250.36' MD, 3638.69'TVD 11,300.00 86.12 183.16 3,642.90 3,584.20 -6,801.54 79.16 6,021,089.33 533,863.84 4.00 6,784.87 11,400.00 90.12 183.17 3,646.17 3,587.47 -6,901.31 73.64 6,020,989.55 533,858.77 4.00 6,884.80 11,434.38 91.50 183.18 3,645.69 3,586.99 -6,935.63 71.74 6,020,955.22 533,857.03 4.00 6,919.17 End Dir : 11434.38' MD, 3645.69' ND 11,500.00 91.50 183.18 3,643.97 3,585.27 -7,001.13 68.10 6,020,889.71 533,853.68 0.00 6,984.77 11,600.00 91.50 183.18 3,641.35 3,582.65 -7,100.94 62.55 6,020,789.89 533,848.59 0.00 7,084.73 11,700.00 91.50 183.18 3,638.73 3,580.03 -7,200.75 57.01 6,020,690.06 533,843.50 0.00 7,184.70 11,800.00 91.50 183.18 3,636.12 3,577.42 -7,300.57 51.46 6,020,590.23 533,838.41 0.00 7,284.66 11,900.00 91.50 183.18 3,633.50 3,574.80 -7,400.38 45.92 6,020,490.41 533,833.32 0.00 7,384.63 12,000.00 91.50 183.18 3,630.88 3,572.18 -7,500.19 40.37 6,020,390.58 533,828.22 0.00 7,484.59 12,100.00 91.50 183.18 3,628.26 3,569.56 -7,600.00 34.83 6,020,290.75 533,823.13 0.00 7,584.56 12,200.00 91.50 183.18 3,625.65 3,566.95 -7,699.81 29.28 6,020,190.93 533,818.04 0.00 7,684.52 12,300.00 91.50 183.18 3,623.03 3,564.33 -7,799.63 23.74 6,020,091.10 533,812.95 0.00 7,784.49 12,400.00 91.50 183.18 3,620.41 3,561.71 -7,899.44 18.19 6,019,991.28 533,807.86 0.00 7,884.45 12,500.00 91.50 183.18 3,617.79 3,559.09 -7,999.25 12.64 6,019,891.45 533,802.77 0.00 7,984.42 12,600.00 91.50 183.18 3,615.17 3,556.47 -8,099.06 7.10 6,019,791.62 533,797.67 0.00 8,084.38 12,700.00 91.50 183.18 3,612.56 3,553.86 -8,198.87 1.55 6,019,691.80 533,792.58 0.00 8,184.35 12,800.00 91.50 183.18 3,609.94 3,551.24 -8,298.68 -3.99 6,019,591.97 533,787.49 0.00 8,284.31 12,900.00 91.50 183.18 3,607.32 3,548.62 -8,398.50 -9.54 6,019,492.15 533,782.40 0.00 8,384.28 13,000.00 91.50 183.18 3,604.70 3,546.00 -8,498.31 -15.08 6,019,392.32 533,777.31 0.00 8,484.24 13,100.00 91.50 183.18 3,602.09 3,543.39 -8,598.12 -20.63 6,019,292.49 533,772.21 0.00 8,584.21 13,200.00 91.50 183.18 3,599.47 3,540.77 -8,697.93 -26.17 6,019,192.67 533,767.12 0.00 8,684.17 13,300.00 91.50 183.18 3,596.85 3,538.15 -8,797.74 -31.72 6,019,092.84 533,762.03 0.00 8,784.14 13,400.00 91.50 183.18 3,594.23 3,535.53 -8,897.56 -37.26 6,018,993.02 533,756.94 0.00 8,884.10 13,500.00 91.50 183.18 3,591.61 3,532.91 -8,997.37 -42.81 6,018,893.19 533,751.85 0.00 8,984.07 13,600.00 91.50 183.18 3,589.00 3,530.30 -9,097.18 -48.35 6,018,793.36 533,746.76 0.00 9,084.03 13,700.00 91.50 183.18 3,586.38 3,527.68 -9,196.99 -53.90 6,018,693.54 533,741.66 0.00 9,184.00 13,800.00 91.50 183.18 3,583.76 3,525.06 -9,296.80 -59.45 6,018,593.71 533,736.57 0.00 9,283.96 13,900.00 91.50 183.18 3,581.14 3,522.44 -9,396.61 -64.99 6,018,493.89 533,731.48 0.00 9,383.93 14,000.00 91.50 183.18 3,578.53 3,519.83 -9,496.43 -70.54 6,018,394.06 533,726.39 0.00 9,483.89 14,100.00 91.50 183.18 3,575.91 3,517.21 -9,596.24 -76.08 6,018,294.23 533,721.30 0.00 9,583.86 912612019 8:45:49PM Page 6 COMPASS 5000.15 Build 91 9/26/2019 8:45:49PM Paoe 7 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-21 i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-21 Planned RKB @ 58.70usft Project: Milne Point MD Reference: MPU M-21 Planned RKB @ 58.70usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -21i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -21i Design: MPU M-21iwp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,515.00 Section 14,184.38 91.50 183.18 3,573.70 3,515.00 -9,680.45 -80.76 6,018,210.00 533,717.00 0.00 9,668.21 Total Depth : 14184.38' MD, 3573.7' TVD - 4-1/2" X 8-1/2" - M-21 Toe wp03 Targets Target Name - hitimiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) M-21 Toe wp03 0.00 0.00 3,573.70 -9,680.46 -80.76 6,018,210.00 533,717.00 plan hits target center Point M-21 wp03 CP1 0.00 0.00 3,608.70 -6,409.93 101.10 6,021,481.00 533,884.00 plan hits target center Point M-21 i Heel wp03 -1.53 183.40 3,858.70 -377.95 471.52 6,027,514.00 534,227.00 plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 4,770.00 3,854.12 9-5/8" X 12-1/4" 9-5/8 12-1/4 14,184.38 3,573.70 4-1/2" X 8-1/2" 4-1/2 8-1/2 114.00 114.00 20" 20 26 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology V) (°) 1,341.68 1,314.70 SV5 3,448.49 3,183.70 LA3 4,146.98 3,690.70 SB_NA 1,993.12 1,857.70 BPRF 4,051.11 3,638.70 BHL OA (Toe) 3,046.35 2,801.70 UG_COAL1 — - -- — - 9/26/2019 8:45:49PM Paoe 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -21i Wellbore: MPU M -21i Desiqn: MPUM-21iwp03 Plan Annotations 217.21 Measured Vertical -228.42 Depth Depth End Dir : 4707.42' MD, 3850.85' TVD (usft) (usft) 471.52 500.00 500.00 -514.05 1,723.17 1,641.25 End Dir : 4993.82' MD, 3859.35' TVD 2,260.19 2,071.84 106.40 4,707.42 3,850.85 -6,531.34 4,857.42 3,858.70 End Dir : 11028.05' MD, 3615.99' TVD 4,993.82 3,859.35 81.88 10,819.80 3,609.80 -6,935.63 11,028.05 3,615.99 End Dir : 11434.38' MD, 3645.69' TVD 11,250.36 3,638.69 -80.76 11,434.38 3,645.69 14,184.38 3,573.70 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -21i TVD Reference: MPU M-21 Planned RKB @ 58.70usft MD Reference: MPU M-21 Planned RKB @ 58.70usft North Reference: True Survev Calculation Method: Minimum Curvature Local Coordinates +N/ -S +E/ -W (usft) (usft) Comment 0.00 0.00 Start Dir 31/100' : 500' MD, 500'TVD 359.77 117.55 End Dir : 1723.17' MD, 1641.25' TVD 664.80 217.21 Start Dir 5°/100' : 2260.19' MD, 2071.847VD -228.42 480.40 End Dir : 4707.42' MD, 3850.85' TVD -377.95 471.52 Start Dir 41/100': 4857.42' MD, 3858.7'TVD -514.05 463.29 End Dir : 4993.82' MD, 3859.35' TVD -6,323.74 106.40 Start Dir 41/100': 10819.8' MD, 3609.8'TVD -6,531.34 94.03 End Dir : 11028.05' MD, 3615.99' TVD -6,752.15 81.88 Start Dir 41/100': 11250.36' MD, 3638.69'TVD -6,935.63 71.74 End Dir : 11434.38' MD, 3645.69' TVD -9,680.46 -80.76 Total Depth : 14184.38' MD, 3573.7' TVD 9/26/2019 8:45:49PM Paw 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-21 i MPU M -21i MPU M-21 i wp03 Sperry Drilling Services Clearance Summary Anticollision Report 26 September, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-21 i - MPU M-21 i - MPU M-21 i wp03 Well Coordinates: 6,027,889.77 N, 533,753.82 E (70° 29' 14.01" N, 149° 43'26.81" W) Datum Height: MPU M-21 Planned RKB P 58.70usft Scan Range: 33.70 to 4,770.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: NO GLOBAL Scan Type: 25.00 HALLIBURTON Sperry Grilling Services HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -21i - MPU M -21i - MPU M -21i wp03 Scan Range: 33.70 to 4,770.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measure Minimum @Measure Site Name d Distance d Comparison Well Name - Wellbore Name - Design Denth lusftl Denth M Pt Moose Pad MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12PB1 - MPU M-12PB1 MPU M-12 - MPU M -12P61 - MPU M-12PB1 MPU M-12 - MPU M -12P61 - MPU M-12PB1 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-14 - MPU M-14 - MPU M-14 MPU M-14 - MPU M-14 - MPU M-14 MPU M-14 - MPU M-14 - MPU M-14 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M -18P131 - MPU M-18PB1 MPU M-18 - MPU M -18P62 - MPU M -18P82 MPU M-18 - MPU M -18P132 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-20 - MPU M-20 - MPU M-20 Ellipse @Measure Clearance Summary Based Separation d Factor on Minimum lusftl Denth Hilcorp Alaska, LLC Milne Point Separation Warning 595.88 377.49 595.88 372.84 602.20 81.176 Centre Distance Pass - 608.70 377.52 608.70 372.78 614.58 79.643 Ellipse Separation Pass - 1,108.70 459.01 1,108.70 450.82 1,031.35 56.011 Clearance Factor Pass - 406.01 177.47 406.01 173.43 406.58 43.932 Centre Distance Pass - 433.70 177.62 433.70 173.35 432.40 41.560 Ellipse Separation Pass - 3,958.70 726.94 3,958.70 692.45 3,390.68 21.076 Clearance Factor Pass - 406.01 177.47 406.01 173.43 406.58 43.932 Centre Distance Pass - 433.70 177.62 433.70 173.35 432.40 41.560 Ellipse Separation Pass - 3,958.70 726.94 3,958.70 692.45 3,390.68 21.076 Clearance Factor Pass - 406.01 177.47 406.01 173.43 406.58 43.932 Centre Distance Pass - 433.70 177.62 433.70 173.35 432.40 41.560 Ellipse Separation Pass - 3,958.70 726.94 3,958.70 692.45 3,390.68 21.076 Clearance Factor Pass - 33.70 194.69 33.70 193.20 34.07 131.121 Centre Distance Pass - 108.70 194.71 108.70 192.83 108.62 103.203 Ellipse Separation Pass - 4,770.00 1,233.40 4,770.00 1,204.78 3,488.94 43.098 Clearance Factor Pass - 33.70 127.91 33.70 126.43 34.18 86.150 Centre Distance Pass - 83.70 128.07 83.70 126.31 83.29 73.076 Ellipse Separation Pass - 683.70 151.91 683.70 146.77 667.31 29.556 Clearance Factor Pass - 33.70 194.70 33.70 193.22 34.42 131.132 Centre Distance Pass - 108.70 194.93 108.70 193.05 107.91 103.391 Ellipse Separation Pass - 808.70 237.25 808.70 231.10 788.27 38.535 Clearance Factor Pass - 33.70 194.70 33.70 193.22 34.42 131.132 Centre Distance Pass - 108.70 194.93 108.70 193.05 107.91 103.391 Ellipse Separation Pass - 808.70 237.25 808.70 231.10 788.27 38.535 Clearance Factor Pass - 33.70 194.70 33.70 193.22 34.42 131.132 Centre Distance Pass - 108.70 194.93 108.70 193.05 107.91 103.391 Ellipse Separation Pass - 808.70 237.25 808.70 231.10 788.27 38.535 Clearance Factor Pass - 33.70 89.85 33.70 88.36 34.23 60.514 Centre Distance Pass - 26 September, 2019 - 20:35 Page 2 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -21i - MPU M -21i - MPU M -21i wp03 Scan Range: 33.70 to 4,770.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Comparison Well Name - Wellbore Name - Design Denth Insft1 Denth lusftl Denth MPU M-20 - MPU M-20 - MPU M-20 408.70 90.22 408.70 86.98 408.46 27.847 Ellipse Separation MPU M-20 - MPU M-20 - MPU M-20 1,033.70 112.36 1,033.70 104.77 1,011.62 14.804 Clearance Factor MPU M-20 - MPU M-20PB1 - MPU M-20PB1 33.70 89.85 33.70 88.36 34.23 60.514 Centre Distance MPU M-20 - MPU M-20PB1 - MPU M-20PB1 408.70 90.22 408.70 86.98 408.46 27.847 Ellipse Separation MPU M-20 - MPU M-20PB1 - MPU M-20PB1 1,033.70 112.36 1,033.70 104.77 1,011.62 14.804 Clearance Factor MPU M-20 - MPU M-20PB2 - MPU M-20PB2 33.70 89.85 33.70 88.36 34.23 60.514 Centre Distance MPU M-20 - MPU M-20PB2 - MPU M-20PB2 408.70 90.22 408.70 86.98 408.46 27.847 Ellipse Separation MPU M-20 - MPU M-20PB2 - MPU M-20PB2 1,033.70 112.36 1,033.70 104.77 1,011.62 14.804 Clearance Factor MPU M-22 - MPU M-22 - MPU M-22 223.75 89.85 223.75 87.89 223.90 45.817 Centre Distance MPU M-22 - MPU M-22 - MPU M-22 358.70 90.19 358.70 87.27 358.09 30.845 Ellipse Separation MPU M-22 - MPU M-22 - MPU M-22 4,770.00 762.02 4,770.00 711.02 4,770.11 14.941 Clearance Factor MPU M-22 - MPU M-22PB1 - MPU M-22PB1 223.75 89.85 223.75 87.89 223.90 45.817 Centre Distance MPU M-22 - MPU M-22PB1 - MPU M-22PB1 358.70 90.19 358.70 87.27 358.09 30.845 Ellipse Separation MPU M-22 - MPU M-22PB1 - MPU M-22PB1 4,770.00 762.02 4,770.00 711.01 4,770.11 14.938 Clearance Factor Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup S 483.70 243.63 483.70 239.49 483.70 58.880 Centre Distance Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup S 508.70 243.64 508.70 239.33 508.70 56.441 Ellipse Separation Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup S 958.70 292.59 958.70 285.17 935.38 39.429 Clearance Factor Plan: Kup S3 - Slot 13 - 60deq Sail Doesnt Reach - Ku 261.42 296.88 261.42 294.36 261.42 117.623 Centre Distance Plan: Kup S3 - Slot 13 - 60deq Sail Doesnt Reach - Ku 333.70 297.11 333.70 294.05 331.18 97.034 Ellipse Separation Plan: Kup S3 - Slot 13 - 60deq Sail Doesnt Reach - Ku 858.70 362.48 858.70 352.77 800.00 37.296 Clearance Factor Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 333.70 210.20 333.70 206.71 333.70 60.151 Centre Distance Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 358.70 210.24 358.70 206.57 357.73 57.287 Ellipse Separation Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 4,683.70 1,129.04 4,683.70 1,093.16 3,553.90 31.464 Clearance Factor Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 261.42 218.62 261.42 215.64 261.42 73.451 Centre Distance Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 308.70 218.76 308.70 215.45 306.56 66.235 Ellipse Separation Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 733.70 264.06 733.70 257.93 682.12 43.120 Clearance Factor Plan: MPU M -15i - MPU M -15i - M -15i wp04 483.70 137.86 483.70 133.45 483.40 31.273 Centre Distance Plan: MPU M -15i - MPU M -15i - M -15i wp04 508.70 137.89 508.70 133.29 507.83 29.974 Ellipse Separation Plan: MPU M -15i - MPU M-151- M -15i wp04 733.70 161.60 733.70 155.30 715.17 25.654 Clearance Factor Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 361.42 153.15 361.42 149.46 361.42 41.468 Centre Distance Hileorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 26 September, 2019 - 20:35 Page 3 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) 120.18 504.67 115.46 504.53 25.465 Centre Distance Reference Design: M Pt Moose Pad - Plan: MPU M -21i - MPU M -21i - MPU M -21i wp03 583.70 120.51 583.70 115.24 581.16 22.858 Scan Range: 33.70 to 4,770.00 usft. Measured Depth. Pass - 4,770.00 689.53 4,770.00 640.33 4,759.96 14.017 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited 29.75 508.70 25.00 508.75 6.267 Centre Distance Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Comparison Well Name - Wellbore Name - Design Denth (usft) Denth (nsftl Denth 335.92 34.135 Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 383.70 153.16 383.70 149.31 383.43 39.765 Ellipse Separation Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 683.70 180.18 683.70 174.32 658.74 30.741 Clearance Factor Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 385.92 123.78 385.92 119.91 385.92 31.994 Centre Distance Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 408.70 123.80 408.70 119.77 408.22 30.723 Ellipse Separation Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 633.70 140.83 633.70 135.27 617.85 25.335 Clearance Factor Plan: MPU M-1 7i P2 - M112 Phase 2 - M -1 7i P2 wp02 261.42 152.94 261.42 149.97 261.42 51.386 Centre Distance Plan: MPU M-1 7i P2 - M 112 Phase 2 - M -1 7i P2 wp02 308.70 153.06 308.70 149.75 307.47 46.296 Ellipse Separation Plan: MPU M -1 7i P2 - M112 Phase 2 - M -1 7i P2 wp02 658.70 182.15 658.70 176.43 635.45 31.827 Clearance Factor Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 283.70 218.32 283.70 215.63 279.70 81.176 Centre Distance Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 308.70 218.38 308.70 215.52 303.59 76.348 Ellipse Separation Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 783.70 270.71 783.70 264.58 737.39 44.154 Clearance Factor Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-19 w 435.84 270.27 435.84 266.47 435.94 71.218 Centre Distance Plan: MPU M -19i - MPU M-1 9i - Jeb Stuart - MPU M-19 w 508.70 270.50 508.70 266.20 506.82 62.919 Ellipse Separation Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-19 w 908.70 326.04 908.70 319.03 868.88 46.486 Clearance Factor Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wp0 283.70 137.48 283.70 134.79 279.70 51.118 Centre Distance Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wp0 308.70 137.59 308.70 134.73 303.52 48.099 Ellipse Separation Plan: MPU M -19i P2 - Slot 27 - M-1 9i P2 - M-1 9i P2 wp0 633.70 164.83 633.70 159.74 607.83 32.357 Clearance Factor Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 Plan: MPU M-21 i P2 - M-21 i Phase 2- M-21 i P2 wp02 Plan: MPU M-21 i P2 - M-21 i Phase 2- M-21 i P2 wp02 Plan: MPU M-21 i P2 - M-21 i Phase 2- M-21 i P2 wp02 Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i P2 Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 504.67 120.18 504.67 115.46 504.53 25.465 Centre Distance Pass - 583.70 120.51 583.70 115.24 581.16 22.858 Ellipse Separation Pass - 4,770.00 689.53 4,770.00 640.33 4,759.96 14.017 Clearance Factor Pass - 508.70 29.75 508.70 25.00 508.75 6.267 Centre Distance Pass - 558.70 29.99 558.70 24.88 558.69 5.879 Ellipse Separation Pass - 733.70 34.12 733.70 27.79 733.06 5.389 Clearance Factor Pass - 335.92 119.83 335.92 116.32 335.92 34.135 Centre Distance Pass - 383.70 119.93 383.70 116.08 382.98 31.151 Ellipse Separation Pass - 783.70 146.19 783.70 139.55 767.31 22.043 Clearance Factor Pass - 483.70 149.96 483.70 146.04 483.70 38.209 Centre Distance Pass - 533.70 150.06 533.70 145.77 533.70 35.041 Ellipse Separation Pass - 833.70 168.62 833.70 162.30 819.33 26.687 Clearance Factor Pass - 435.92 179.84 435.92 175.61 435.92 42.541 Centre Distance Pass - 26 September, 2019 - 20:35 Page 4 of 8 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -21i - MPU M -21i - MPU M -21i wp03 Scan Range: 33.70 to 4,770.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design Denth lusftl Denth fusftl Denth Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M-231 P2 508.70 180.08 508.70 175.34 507.26 37.968 Ellipse Separation Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i P2 858.70 212.43 858.70 205.32 829.15 29.865 Clearance Factor Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 361.42 239.94 361.42 236.70 361.42 73.904 Centre Distance Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 408.70 240.05 408.70 236.44 406.99 66.546 Ellipse Separation Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 2,408.70 954.23 2,408.70 931.58 2,090.75 42.134 Clearance Factor Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 483.70 209.84 483.70 205.70 483.70 50.714 Centre Distance Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 533.70 209.96 533.70 205.47 532.76 46.747 Ellipse Separation Pass - Plan: MPU M -25i - Slot 18 - M-251- M -25i wp03 833.70 240.83 833.70 234.35 800.00 37.149 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU M 764.68 57.14 764.68 51.01 756.73 9.315 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU M 783.70 57.21 783.70 50.94 775.56 9.125 Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU M 858.70 59.45 858.70 52.64 848.78 8.741 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-58 483.70 60.08 483.70 55.94 483.70 14.514 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-58 533.70 60.17 533.70 55.67 533.70 13.381 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-58 783.70 69.52 783.70 63.24 782.66 11.075 Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 f 420.16 29.74 420.16 26.06 420.29 8.084 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 f 458.70 29.91 458.70 25.96 458.66 7.564 Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 f 583.70 33.71 583.70 28.86 582.11 6.949 Clearance Factor Pass - Rig: MPU M -17i - MPU M -17i - MPU M -17i 86.00 172.63 86.00 170.74 85.90 91.309 Ellipse Separation Pass - Rig: MPU M -17i - MPU M -17i - MPU M -17i 258.70 234.42 258.70 230.27 100.00 56.408 Clearance Factor Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 386.00 172.63 386.00 168.98 385.90 47.300 Centre Distance Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 433.70 172.73 433.70 168.71 432.56 43.004 Ellipse Separation Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 758.70 204.27 758.70 197.78 737.66 31.479 Clearance Factor Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 483.70 127.41 483.70 123.27 446.00 30.795 Centre Distance Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 508.70 127.43 508.70 123.11 471.00 29.520 Ellipse Separation Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 858.70 157.02 858.70 150.19 818.89 22.984 Clearance Factor Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 483.70 172.53 483.70 168.40 446.00 41.702 Centre Distance Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 533.70 172.67 533.70 168.18 496.00 38.412 Ellipse Separation Pass - Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 1,033.70 217.40 1,033.70 209.32 989.08 26.922 Clearance Factor Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 915.20 143.28 915.20 136.08 874.24 19.887 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 933.70 143.34 933.70 136.00 892.28 19.532 Ellipse Separation Pass - 26 September, 2019 - 20:35 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Ellipse Reference Design: M Pt Moose Pad -Plan: MPU M-21 i -MPU M -21i -MPU M-21 i wp03 d Scan Range: 33.70 to 4,770.00 usft. Measured Depth. d Dpnth Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited 140.16 Measure Minimum Site Name d Distance Comparison Well Name - Wellbore Name - Design Dpnth (usftl Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 1,058.70 148.35 Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 1,032.61 228.59 Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 1,033.70 228.59 Slot 48 - Placeholder - Slot 48- Placeholder - Slot 48 - 1,058.70 229.08 Survey fool program From To (usft) (usft) 33.70 500.00 MPU M-21 i wp03 4,769.70 14,184.38 MPU M -21i wp03 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. @Measure Ellipse @Measure d Separation d Dpnth (usftl Dpnth 1,058.70 140.16 1,000.00 1,032.61 220.54 988.03 1,033.70 220.53 989.08 1,058.70 220.89 1,000.00 Survey/Plan Clearance Summary Based Factor on Minimum 18.115 Clearance Factor 28.377 Centre Distance 28.349 Ellipse Separation 27.957 Clearance Factor Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - 26 September, 2019 - 20:35 Page 6 of 8 COMPASS 1-lALLtBtJRTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:PIan: MPU M -21i NAD 1927 (NADCON CONUS) Alaska Zone 04 Co -ordinate (N/E) Reference: Well Plan: MPU M -21i, True North Vertical (TVD) Reference: MPU M-21 Planned RKB @ 58.70usft Measured Depth Reference: MPU M-21 Planned RKB @ 58.70usft Calculation Method: Minimum Curvauret Sperry Drilling Site: M Pt Moose Pad Well: Plan: MPU M-21 i Wellbore: MPU M-21 i Ground Level: 25.00 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027889.77 533753.82 70° 29' 14.007 N149° 43' 26.812 W Plan: MPU M-21 i wp03 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria EMDate: 2016-08-03T00:00:00 Validated: Yes Version: 33.70 To 4770.00 1 ...J..I....IC C X1..4.+ Depth From Depth To Survey/Plan Tool 33.70 4770.00 MPU M -21i wp03 (MPU M -21i) 2_MWD+IFR2+MS+Sag CASING DETAILS TVD TVDSS MD Size Name SH (1 of 2) 4770.00 14184.38 MPUM-21iwp03(MPUM-21i) 2_MWD+IFR2+MS+Sag 114.00 55.30 114.00 20 20" 3854.12 3795.42 4770.00 9-5/8 9-5/8" X 12-1/4" 3573.70 3515.00 14184.38 4-1/2 4-1/2" X 8-1/2" :E1 50.00 U M-57 SN GO wp04 o p 120.00 co r' I - - -- - c O MPU M 2PB1 MP ---` M-22cc M-2'1 P2 wp02 - - - 90.00 OL O MPU M-58 IRA wpD - - O 60.00 MPU -M-57 SM wp - O U Kup N1 rom Slot 3 - CID 30.00 Y 3 . - _ c IJ 0.00-7-r7-7- I 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225 Measured Depth (550 usft/in) 4.00- .00 0 O .00 i� 3.00- LL LL C 22.00- Collision - Risk Procedures Req. CL CID Collision Avoidance Req. - U) No -Go Zone - Stop Drilling 1.00 - NOERRORS 0.00 -r-r--J 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225 Measured Depth (550 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-21 i MPU M-21 i MPU M-21 i wp03 Sperry Drilling Services Clearance Summary Anticollision Report 26 September, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-21 i -MPU M-21 i - MPU M-21 i wp03 Well Coordinates: 6,027,889.77 N, 533,753.82E (70° 29' 14.01" N, 149° 43' 26.81" W) Datum Height: MPU M-21 Planned RKB @ 58.70usft Scan Range: 4,770.00 to 14,184.38 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: NO GLOBAL Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-21 i - MPU M-21 i - MPU M-21 i wp03 Scan Range: 4,770.00 to 14,184.38 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Milne Point MPU M-18 - MPU M-18PB2 - MPU M-18PB2 Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Pass - Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design npnth IlIsftl Dpnrh ll,sftl Denrh 6.818 Clearance Factor Pass - M Pt Moose Pad 6,875.06 761.25 6,875.06 677.47 7,512.89 9.086 Centre Distance Pass - MPU M-03 - MPU M-03 - MPU M-03 8,870.07 562.38 8,870.07 442.61 6,198.62 4.696 Ellipse Separation Pass - MPU M-03 - MPU M-03 - MPU M-03 8,895.00 562.77 8,895.00 442.87 6,212.06 4.694 Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12 4,770.00 1,032.22 4,770.00 991.89 3,612.78 25.595 Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 4,770.00 1,032.22 4,770.00 991.89 3,612.78 25.595 Clearance Factor Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 4,770.00 1,032.22 4,770.00 991.89 3,612.78 25.595 Clearance Factor Pass - MPU M-14 - MPU M-14 - MPU M-14 5,812.03 766.98 5,812.03 718.94 3,805.41 15.965 Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14 5,845.00 767.73 5,845.00 718.33 3,827.56 15.541 Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14 6,145.00 826.39 6,145.00 769.31 3,921.85 14.480 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 7,257.30 1,124.63 7,257.30 1,047.27 4,587.61 14.537 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 7,395.00 1,128.24 7,395.00 1,044.00 4,694.80 13.394 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 8,345.00 1,332.39 8,345.00 1,208.91 5,451.78 10.791 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 8,810.06 996.89 8,810.06 882.46 5,885.53 8.712 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 9,045.00 1,001.91 9,045.00 873.60 6,095.36 7.808 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 9,820.00 1,126.93 9,820.00 961.64 6,765.53 6.818 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 8,810.06 996.89 8,810.06 882.44 5,885.53 8.711 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,045.00 1,001.91 9,045.00 873.58 6,095.36 7.807 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,820.00 1,126.93 9,820.00 961.61 6,765.53 6.817 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 8,810.06 996.89 8,810.06 882.46 5,885.53 8.712 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 9,045.00 1,001.91 9,045.00 873.60 6,095.36 7.808 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 9,820.00 1,126.93 9,820.00 961.63 6,765.53 6.818 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 6,875.06 761.25 6,875.06 677.47 7,512.89 9.086 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 14,184.38 788.25 14,184.38 522.91 14,787.54 2.971 Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 6,875.06 761.25 6,875.06 677.47 7,512.89 9.087 Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 12,570.00 790.02 12,570.00 537.48 13,188.00 3.128 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 6,875.06 761.25 6,875.06 677.47 7,512.89 9.086 Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 13,295.00 787.17 13,295.00 529.46 13,926.00 3.055 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 13,320.00 787.83 13,320.00 529.81 13,926.00 3.053 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 4,770.00 762.02 4,770.00 711.02 4,770.11 14.941 Centre Distance Pass - 26 September, 2019 - 21:19 Page 2 of 6 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-211 - MPU M-211 - MPU M-21 i wp03 Scan Range: 4,770.00 to 14,184.38 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Hileorp Alaska, LLC Milne Point Plan: MPU M -19i - MPU M-1 9i - Jeb Stuart - MPU M-19 w Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Pass - Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design Death (usft! Deoth (usft) Death 5.320 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 14,145.00 856.32 14,145.00 577.86 14,117.33 3.075 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 4,770.00 762.02 4,770.00 711.01 4,770.11 14.938 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 12,920.00 838.81 12,920.00 580.38 12,932.00 3.246 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 9,968.48 409.38 9,968.48 243.80 6,889.55 2.472 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deq Sail Doesnt Reach - Ku 9,970.00 409.38 9,970.00 243.78 6,890.88 2.472 Ellipse Separation Pass - Plan: Kup S3 - Slot 13 - 60deq Sail Doesnt Reach - Ku 9,995.00 409.58 9,995.00 243.82 6,912.82 2.471 Clearance Factor Pass - Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02 4,770.00 1,161.58 4,770.00 1,124.94 3,559.09 31.704 Clearance Factor Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 6,002.34 1,083.79 6,002.34 1,027.64 3,900.00 19.300 Centre Distance Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 6,020.00 1,083.94 6,020.00 1,027.32 3,900.00 19.146 Ellipse Separation Pass - Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02 6,370.00 1,139.60 6,370.00 1,073.54 4,000.00 17.251 Clearance Factor Pass - Plan: MPU M -15i - MPU M -15i - M -15i wp04 6,671.21 973.39 6,671.21 903.76 4,296.37 13.979 Centre Distance Pass - Plan: MPU M -15i - MPU M -15i - M -15i wp04 6,745.00 975.15 6,745.00 902.16 4,341.22 13.360 Ellipse Separation Pass - Plan: MPU M -15i - MPU M -15i - M -15i wp04 7,120.00 1,038.02 7,120.00 951.69 4,534.80 12.023 Clearance Factor Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 6,749.52 1,153.42 6,749.52 1,080.34 4,257.70 15.784 Centre Distance Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 6,820.00 1,154.79 6,820.00 1,078.60 4,300.14 15.156 Ellipse Separation Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 7,370.00 1,255.31 7,370.00 1,158.86 4,631.28 13.015 Clearance Factor Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 7,373.57 1,207.29 7,373.57 1,123.03 4,643.38 14.328 Centre Distance Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 7,520.00 1,211.24 7,520.00 1,119.62 4,752.40 13.220 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 wp 8,370.00 1,378.45 8,370.00 1,251.33 5,385.21 10.843 Clearance Factor Pass - Plan: MPU M-1 7i P2 - M112 Phase 2 - M -1 7i P2 wp02 8,080.45 1,243.82 8,080.45 1,142.69 5,136.94 12.300 Centre Distance Pass - Plan: MPU M -17i P2 - M112 Phase 2 - MAT P2 wp02 8,270.00 1,249.04 8,270.00 1,137.66 5,288.32 11.214 Ellipse Separation Pass - Plan: MPU M -17i P2 - M112 Phase 2 - M -17i P2 wp02 9,320.00 1,450.37 9,320.00 1,292.99 6,126.89 9.216 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 8,792.64 1,207.06 8,792.64 1,093.27 5,719.37 10.607 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 9,045.00 1,214.35 9,045.00 1,085.83 5,933.92 9.449 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 10,220.00 1,421.85 10,220.00 1,237.48 6,932.91 7.712 Clearance Factor Pass - Plan: MPU M -19i - MPU M-1 9i - Jeb Stuart - MPU M-19 w 9,590.90 893.51 9,590.90 763.82 6,604.45 6.890 Centre Distance Pass - Plan: MPU M-1 9i - MPU M-1 9i - Jeb Stuart - MPU M-19 w 9,895.00 902.64 9,895.00 753.87 6,880.25 6.067 Ellipse Separation Pass - Plan: MPU M -19i - MPU M-1 9i - Jeb Stuart - MPU M-19 w 10,720.00 1,012.23 10,720.00 821.94 7,628.47 5.320 Clearance Factor Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wp0 9,541.10 1,189.26 9,541.10 1,048.94 6,408.69 8.475 Centre Distance Pass - Plan: MPU M -19i P2 - Slot 27 - M-191 P2 - M -19i P2 wp0 9,870.00 1,198.22 9,870.00 1,039.66 6,703.30 7.557 Ellipse Separation Pass - Plan: MPU M -19i P2 - Slot 27 - M-1 9i P2 - M -19i P2 wp0 10,870.00 1,328.12 10,870.00 1,123.60 7,599.32 6.494 Clearance Factor Pass - 26 September, 2019 - 21:19 Page 3 of 6 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-21 i - MPU M-21 i wp03 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-21 i - MPU M-21 i - MPU M-21 i wp03 Scan Range: 4,770.00 to 14,184.38 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Milne Point Survey foo/ pro_q m From Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design Denth fusftl Denth fusftl Denth Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 4,770.00 689.53 4,770.00 640.33 4,759.96 14.017 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 13,445.00 841.79 13,445.00 555.84 13,410.71 2.944 Clearance Factor Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 14,184.38 863.36 14,184.38 551.68 14,071.06 2.770 Clearance Factor Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 6,695.00 1,582.49 6,695.00 1,499.97 6,469.84 19.176 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 13,495.00 1,642.39 13,495.00 1,391.36 13,256.21 6.542 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 13,545.00 1,644.07 13,545.00 1,392.46 13,256.21 6.534 Clearance Factor Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i P2 14,184.38 1,734.22 14,184.38 1,440.23 14,240.29 5.899 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU M 4,770.00 848.95 4,770.00 816.84 3,753.59 26.437 Clearance Factor Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 7,989.80 1,080.61 7,989.80 987.42 5,167.27 11.595 Centre Distance Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 8,170.00 1,085.71 8,170.00 982.83 5,313.63 10.552 Ellipse Separation Pass - Rig: MPU M -17i - MPU M -17i - MPU M-17 wp07 9,070.00 1,250.92 9,070.00 1,108.99 6,044.63 8.814 Clearance Factor Pass - Survey foo/ pro_q m From To fusftl fusftl 33.70 4,770.00 MPU M -21i wp03 4,770.00 14,184.38 MPU M -21i wp03 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey/Plan Survey Tool 2_M W D+I FR2+M S+Sag 2_M W D+I FR2+M S+Sag 26 September, 2019 - 2 1: 19 Page 4 of 6 COMPASS MALL.iBUgTC1N Project: Milne Point REFERENCE INFORMATION WELL DETAILS:Plan:MPUM-21i NAD1927(NADCONCONUS) Alaska Zone 04 Co-ordinate (N/E) Reference: Well Plan: MPU M-21 i, True North Vertical (TVD) Reference: MPU M-21 Planned RKB @ 58.70usft Measured Depth Reference: MPU M-21 Planned RKB @ 58.70usft Calculation Method: Minimum Curvature Site: M Pt Moose Pad Sperry Drilling Well: Plan: MPU M-21 i Wellbore: MPU M-21 i Ground Level: 25.00 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027889.77 533753.82 70° 29' 14.007 N 149° 43'26.812 W Plan: MPU M-21 i wp03 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria Date: 2016-08-03T00:00:00 Validated: Yes Version: M 4770.00 To 14184.38 Ladder/S.F. Plots PH (2 of 2) Depth From Depth To Survey/Plan Tool 33.70 4770.00 MPU M -21i wp03 (MPU M-21 i) 2_MWD+IFR2+MS+Sag 4770.00 14184.38 MPU M -21i wp03 (MPU M -21i) 2_MWD+IFR2+MS+Sag CASING DETAILS TVD TVDSS MD Size Name 114.00 55.30 114.00 20 20" 3854.12 3795.42 4770.00 9-5/8 9-5/8" X 12-1/4" 3573.70 3515.00 14184.38 4-1/2 4-1/2" X 8-1/2" 5150.00 - U) C) C5120.00- - - --.. - - - _ ----. -. M-21 i-_ 2 Wp02 O 90.00 co N III I 0.00 60.00- o 0 - 30.00- 0.00 0.00 0.00 I 7 500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16500 Measured Depth (1000 usft/in) 4.00 0 v 3.00- .00 LL LL / •r-Collision 2.00 - Risk Procedures Req.- -- -- . -_ 2 CL Q) Collision Avoidance R q. - No -Go Zone - Stop Drilling 1.00 - NOERRORS 0.00 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 Measured Depth (1000 usft/in) Boyer, David L (CED) From: Joseph Engel <jengel@hilcorp.com> Sent: Monday, September 30, 2019 2:13 PM To: Boyer, David L (CED) Cc: Davies, Stephen F (CED); Cody Dinger Subject: RE: [EXTERNAL] Review of MPU M-21 Injector David — Upon review we filled out the boxes in question with information for a directional plan that was not final. Please see the updated information below. Distance to nearest unit was planned to be >500'. Box 14 — 565' to nearest unit boundary Box 4a TPH - 562' FNL, 64' FWL, Sec 13, T13N, R9E, UM, AK Box 4a BHL - 638' FSL, 499' FEL, Sec 23, T13N, R9E, UM, AK Thank you for your time. Let me know if you have any more questions. -Joe Joe Engel I Drilling Engineer ( Hilco.rp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 ( Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Joseph Engel Sent: Monday, September 30, 2019 1:30 PM To: 'Boyer, David L (CED)' <david.boyer2@alaska.gov> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] Review of MPU M-21 Injector Thanks, David. I'll review the directional and get back to you. Joe Engel I Drilling Engineer ( Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Boyer, David L (CED) [mailto:david.boyer a(aska�] Sent: Monday, September 30, 2019 11:23 AM To: Joseph Engel <jenyel@hilcorp.corn> Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] Review of MPU M-21 Injector Hi Joe, I just began the geologic portion of the review for the M-21 injector. In Section 15 of the PTD application, the distance to the nearest unit boundary (Kuparuk Unit) is 371'. In the Location section (4a) at TD, the BHL is 638' from the southern unit boundary with ConocoPhillips. If the distance from the Kuparuk Unit is less than 500', a spacing exception will be required including legal notification to all owners especially including ConocoPhillips. Please advise on this concern. Thank you, Dave Boyer AOGCC The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Boyer, David L (CED) From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, October 1, 2019 9:55 AM To: Boyer, David L (CED) Subject: RE: [EXTERNAL] RE: MPU F-116 Directional Plan David, We will not pre -produce MPU M-21. Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 From: Boyer, David L (CED) [mailto:david.boyer2@alaska.gov] Sent: Tuesday, October 1, 2019 9:51 AM To: Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] RE: MPU F-116 Directional Plan Thanks Cody. On the PTD for MPU M-21, do you know if this injector will be pre -produced? If pre produced, we need to know for how long? I am working on that one right now. Thanks, Dave B. AOGCC From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, September 30, 2019 3:44 PM To: Boyer, David L (CED) <david. boyer2@alaslca.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: MPU F-116 Directional Plan Steve/David, I have attached the directional plan for MPU F-116 and will be delivering the permit by COB today. Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, Transform Points 09 Source coordinate system Target coordinate system State Plane 1927 - Aaska Zone 4 M�(k M—XI Albers Equal Area (-1-50) Datum: E�Datum: NAD 1927 - North America Datum of 1927 (Mean) NAD 1927 - North America Datum of 1527 (Mean} U --j A Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to copy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. < Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: M. P PTD: C25-,, 11 t ZCt�!, Development L,Service _ Exploratory Stratigraphic Test Non -Conventional FIELD:�" C 1 h �O 1 POOL: JG �n Vct rev' 8 I u D c C Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 - Well Name: MILNE PT UNIT M-21 Program SER -_ Well bore seg ❑ PTD#: 2191320 Company Hilcorp Alaska LLC - Initial Class/Type __SER / PEND GeoArea _8.90_ Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes 3 Unique well name and number Yes 4 Well located in a defined pool Yes 5 Well located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit _ - - - Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order_ - Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15 -day wait - Yes DLB 9/30/2019 I14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For Yes Area Injection Order No. 10-B. 15 All wells within 1/4 mile area of review identified (For service well only) - Yes I16 Pre -produced injector: duration of pre production less than 3 months (Forservicewell only) No M-21 will not be pre -produced, peroperator e-mail note. - 17 Nonconven. gas conforms to AS31.05.030(j.1_.A),0.2.A-D) NA I18 Conductor string_ provided Yes 20" conductor set at 113 ft Engineering 19 Surface casing protects all known USDWs NA No groundwater 20 CMT vol adequate to circ ul_ate _on conductor & surf csg Yes 9 5/8" surface casing will be fully cemented... ES tool at 2500 ft. 21 CMT -vol_ adequate to tie-in long string to surf csg Yes 22 CMT will cover all known productive horizons Yes Horizontal lateral will have swell packers and ICD's 23 Casing designs adequate for C, T, B &_permafrost_ Yes BTC supplied 24 Adequate tankage or reserve pit Yes Doyon 14 has steel pits .. 25 If a re -drill, has a 10-403 for abandonment been approved _ NA_ grassroots well. 26 Adequate wellbore separation proposed Yes No issues with close crossing. 27 If diverter required, does it _meet regulations_ Yes Diverter will be used._ 16" Appr Date 28 Drilling fluid program schematic &_ equip list adequate Yes Max form_ pressure = 1689 psi (8.5 ppg EMW) Will drill well with 8.8-9.5 _ppg mud (MPD possible ) GLS 10/2/2019 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to _(put psig in comments) No MASP= 1321 psi Will test BOPE to 3000 psi 31 Choke -manifold complies w/API_ RP -53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No H2S not expected. _Rig has -sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 MILE REVIEW Completed. All wells in area pass mechanical integrity and zonal isolation_ criteria. 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms. Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismicanalysisof shallow gas zones NA DLB 10/1/2019 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly -progress reports_ [exploratory only] NA Geologic Engineering Date Public Date SB injector for Moose Pad. Commissioner: Date: Com�sioner: l � Commissioner J
