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219-154
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, March 1, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-19 MILNE PT UNIT M-19 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/01/2024 M-19 50-029-23655-00-00 219-154-0 W SPT 3694 2191540 1500 695 695 690 694 4YRTST P Adam Earl 1/14/2024 MONO BORE injector. MIT-IA 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-19 Inspection Date: Tubing OA Packer Depth 75 1760 1712 1695IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE240117081242 BBL Pumped:4.2 BBL Returned:4.2 Friday, March 1, 2024 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORT 4/1/2020 Permit to Drill 2191540 Well Name/No. MILNE PT UNIT M-19 Pg 1 — Operator Hilcorp Alaska LLC API No. 50-029-23655-00-00 MD 17450 TVD 3796 Completion Date 1/6/2020 Completion Status 1WINJ Current Status 1WINJ UIC Yes REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION List of Logs Obtained: ROP,DGR,AGR,ABG,ADR,EWR MD&TVD Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data ED C 32307 Digital Data (from Master Well Data/Logs) Interval OH / Start Stop CH Received Comments 105 17450 3/25/2020 Electronic Data Set, Filename: MPU M-19 LWD Final.las 8890 17412 3/25/2020 Electronic Data Set, Filename: MPU M-19 ADR Quadrants All Curves.las 3/25/2020 Electronic File: MPU M-19 LWD Final MD.cgm 3/25/2020 Electronic File: MPU M-19 LWD Final TVD.cgm 3/25/2020 Electronic File: MPU M -19i Final Surveys.xlsx 3/25/2020 Electronic File: MPU M-19i_Definitive Survey Report.pdf 3/25/2020 Electronic File: MPU M-19i_Definitive Survey Report.txt 3/25/2020 Electronic File: MPU M-19i_GIS.txt 3/25/2020 Electronic File: MPU M-19i_Plan.pdf 3/25/2020 Electronic File: MPU M-19i_VSec.pdf 3/25/2020 Electronic File: MPU M-19 LWD Final MD.emf 3/25/2020 Electronic File: MPU M-19 LWD Final TVD.emf 3/25/2020 Electronic File: MPU_M-19_Geosteering.dlis 3/25/2020 Electronic File: MPU_M-19_Geosteering.ver 3/25/2020 Electronic File: MPU M-19 LWD Final MD.pdf 3/25/2020 Electronic File: MPU M-19 LWD Final TVD.pdf 3/25/2020 Electronic File: MPU M-19 LWD Final MD.tif 3/25/2020 Electronic File: MPU M-19 LWD Final TVD.tif AOGCC Page 1 of 3 Wednesday, April 1, 2020 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23655-00-00Well Name/No. MILNE PT UNIT M-19Completion Status1WINJCompletion Date1/6/2020Permit to Drill2191540Operator Hilcorp Alaska LLCMD17450TVD3796Current Status1WINJ4/1/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameInterval0 0 2191540 MILNE PT UNIT M-19 LOG HEADERS32307LogC3/25/2020105 14562 Electronic Data Set, Filename: MPU M-19 PB1 LWD Final.las32308EDDigital DataC3/25/20208890 14524 Electronic Data Set, Filename: MPU M-19 PB1 ADR Quadrants All Curves.las32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final MD.cgm32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final TVD.cgm32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 Final Surveys.xlsx32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1_Definitive Survey Report.pdf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1_Definitive Survey Report.txt32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1_GIS.txt32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1_Plan.pdf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1_VSec.pdf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final MD.emf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final TVD.emf32308EDDigital DataC3/25/2020 Electronic File: MPU_M-19 PB1_Geosteering.dlis32308EDDigital DataC3/25/2020 Electronic File: MPU_M-19 PB1_Geosteering.ver32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final MD.pdf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final TVD.pdf32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final MD.tif32308EDDigital DataC3/25/2020 Electronic File: MPU M-19PB1 LWD Final TVD.tif32308EDDigital Data0 0 2191540 MILNE PT UNIT M-19 PB1 LOG HEADERS32308LogWednesday, April 1, 2020AOGCCPage 2 of 3MPU M-19 PB1LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23655-00-00Well Name/No. MILNE PT UNIT M-19Completion Status1WINJCompletion Date1/6/2020Permit to Drill2191540Operator Hilcorp Alaska LLCMD17450TVD3796Current Status1WINJ4/1/2020UICYesINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:1/6/2020Release Date:11/25/2019Wednesday, April 1, 2020AOGCCPage 3 of 3M.Guhl 4/1/2020 1HHrorp :Vnxka. M.0 DATE 03/23/2020 219154 Dc_.,ra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 32 30 7 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-19 (219-154 MPU M-19 PBi Halliburton LWD FINAL 06 JAN 2020 MPU M-19 & PB1 CGM 1."H 2020 1:34 PM File folder Definitive Survey 1.20+'20201:34 PM File folder EMF 1/X/20201:34 PM File folder LAS 1;`20x`20201:34 PM File folder PDF 1/2Q/2020 1:34 PM File folder TIFF 1/2/20201:34 PM File folder Please include current contact information if different from above. RECEIVED MAR 2 5 2020 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 14 Hilrnrp Alnoka_ 1,1'C DATE 03/23/2020 219154 Debra Oudean Hilcorp Alaska, LLC 32 3 0 8 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-19 (219-154 MPU M-19 PB3 Halliburton LWD FINAL 06 JAN 2020 MPU M-19 & PB1 CGM 1;34 PM File folder Definitive Survey 1.'2&200 1:34 PM File folder EMF 1 `20/1''0210 1,34 PM File folder LAS 1/2 r, 21 201;34 PM File folder PDF 1`20 120201:34 PPA Filefclder TIFF 1). 20,,2020 1:34 PM File folder Please include current contact information if different from above. A, 0' AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim RDATE: Tuesday, February 4, 2020 P.I. Supervisor �\q� 2/cf� SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC M-19 FROM: Austin McLeod MILNE PT UNIT M-19 Petroleum Inspector Src: Inspector Reviewed By: P.1. Suprv':T:�'ly NON -CONFIDENTIAL Comm Well Name MILNE PT UNIT M-19 Insp Num: mitSAM200131161950 Rel Insp Num: API Well Number 50-029-23655-00-00 Inspector Name: Austin McLeod Permit Number: 219-154-0 Inspection Date: 1/31/2020 Packer Depth --i �YP J - — T Well M 19 Type In' W -'TVD 3694 Tubing PTD 2191540 Type Test sPT Test psi 1500 IA BBL Pumped: 4.2 BBL Returned: I 42 OA Intervall INITAL ;P/F P Notes: MIT -IA. Monobore Pretest Initial 15 Min 30 Min 45 Min 60 Min 761 761 761 - 762 ' 147 1820 1764 1749 ' Tuesday, February 4, 2020 Page 1 of 1 STATE OF ALASKA �A� AM OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND hn 1 a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 1 b. Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ Q WAG[] WDSPL ❑ No. of Completions: 1 Service Q Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Hilcorp Alaska, LLC Aband.: 1/6/2020 219-154 ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: December 16, 2019 15. API Number: 50-029-23655-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 4915' FSL, 651' FEL, Sec 14, T13N, R9E, UM, AK December 30, 2019 MPU M-19 Top of Productive Interval: 9. Ref Elevations: KB: 59.46' 17. Field / Pool(s): 2016' FNL, 1404' FWL, Sec 24, T1 3N, R9E, UM, AK f GL: 25.1' ' BF: 25.1' _ Schrader Bluff Oil Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 1623' FNL, 1974' FEL, Sec 30, T1 3N, R1 OE, UM, AK 17,448' MD / 3,796' TVD ADL025514, ADI -025515, ADL025517 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 533514 y- 6027766 Zone- 4 17,450' MD / 3,796' TVD LOINS 16-004 TPI: x- 535606 y- 6020844 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 542774 y- 6015996 Zone- 4 N/A 2,652' MD / 1,846' TVD 5. Directional or Inclination Survey: Yes (attached) No ❑ 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL 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 Logs for MPU M-19: ROP, DGR, AGR, ABG, ADR, EWR MD & TVD Logs for MPU M-19PB1 ROP, DGR, AGR, ABG, ADR, EWR MD & TVD 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 215.5# X-52 Surface 80' Surface 80' 42" 14 yards type 1 9-5/8" 40# L-80 Surface 8,907' Surface 3,706' 12-1/4" Stg 1 L - 402 bbls/T - 82 bbls 60 bbls Stg 2 L - 471 bbls Permafrost 203 bbls 4-1/2" 13.5# L-80 8,687' 17,450' 3,694' 3,796' 8-1/2" Injector Linerw/ICDs & Swell packers 24. Open to production or injection? Yes ❑✓ No ❑ 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number; Date Perfd): 3-1/2" 8,695' 8,687' MD / 3,694' TVD " Please see attached schematic for ICD and swell packer detail. "' Liner run Liner Top Packer on 1/3/2020. ;OµF'LETiON ItTE Z 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No 0 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED VI�iE� 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period —10. Flow Tubing Casinq Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate Form 10-407 Revised 5/2017 CONTINUED ON PAG 2 ubmit ORIGINIAL only 1/71 -2 ../Y Z!<,A;021�� #iBDIIiIS JAN 2 4 2020 11�*B 7-IWI24 0 28. CORE DATA Conventional Core(s): Yes ❑ No ❑✓ Sidewall Cores: Yes ❑ No ❑✓ 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 ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,652' 1,846' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 8,767' 3,700' information, including reports, per 20 AAC 25.071. SV5 1,418' - 1,304' SV1 2,747' 1,878' Ugnu LA3 6,458' 3,047' SB NA 8,083' 3,547' . SB OA 8,767' 3,700' - Formation at total depth: SB OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Casing and Cementing Reports Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger@hilcorp.com Authorized Contact Phone: 777-8389 Signature: Date: ZO Zt'7 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Schematic IIilvorp Alaska, LI.0 Milne Point Unit Well: MPU M-19 PTD: 219-154 API: 50-029-23655-00 119 v O '/ rig. KB TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16" 5M Cameron Wing Wellhead Cameron 11" 5K x sliplock bottom w/(2) 2-1/16" 5K outs TD =17,450' (MD) /TD = 3,796' (TVD) PBTD =17,448' (MD) / PBTD = 3,796(TVD) OPEN HOLE / CEMENT DETAIL 42" 14 yards Type 1 12-1/4" Stg 1 —Lead 402 bbls / Tail 82 bbls Top Stg 2 —Lead 471 bbls Permafrost 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x 34" Conductor (Insulated) 215.5 / X-52 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TXP 8.679" Surface 8,907' 0.0758 4-1/2" Liner 13.5 / L-80 / Hyd 625 3.795" 8,687' 17,450' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 1 2.867" 1 Surf 1 8,695' 1 0.0870 ��✓�S` WELL INCLINATION DETAIL 1 KOP @ 200' Hole Angle @ XN = 70° Hole Angle @ Liner Top = 85° Or Max Hole Angle = 94' JEWELRY DETAIL No Top MD Item ID Upper Completion 1 3,425' 3-1/2" X Nipple (2.813" Packing Bore) 2.813" 2 7,113' 3-1/2" XN Nipple, 2.813" Packing Bore, 2.75" No -Go, w/RHC 2.750" 3 7,820' 3-1/2" Gauge Mandrel SGM-XPQG w/ X" Wire 2.992" 4 8,685' 8.25" No Go Locater Sub (1.76' off No-go) 6.200" 5 8,686' 7.375" Tieback above the SLZXP Liner Top Packer (Btm @ 8,695') 6.200" Lower Completion 6 8,687' 7" x 9-5/8" SLZXP Liner Top Packer with 7.38" Seal Bore 6.180" 7 17,448' Shoe (bottom @ 17,450') 3.970" Depth Depth ICD/Swell Packer Detail MD TVD See Page 2 GENERAL WELL INFO API #: 50-0 2 9- 23655-00 Completed by Doyon 14: 1/6/2020 Revised By: DH 1/15/2020 Depth MD Depth ND ICD/Swell Packer Detail 8,929' 3,706' Tendeka Water Swell Packer ' 9,370' 3,708' ' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,727' 3,714' Tendeka Water Swell Packer 10,126' 1 3,715' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,654' 3,737' Tendeka Water Swell Packer 10,927' 3,749' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,287' 3,751' Tendeka Water Swell Packer 11,602' 3,754' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,914' 3,756' Tendeka Water Swell Packer 12,437' 3,766' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,921' 3,755' Tendeka Water Swell Packer 13,444' 3,742' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,841' 3,748' Tendeka Water Swell Packer 14,188' 3,760' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 14,544' 3,762' Tendeka Water Swell Packer 14,860' 3,765' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 15,009' 3,763' Tendeka Water Swell Packer 15,237' 3,762' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 15,556' 3,775' Tendeka Water Swell Packer 15,956' 3,776' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 16,231' 3,787' Tendeka Water Swell Packer 16,463' 3,799' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 16,695' 3,804' Tendeka Water Swell Packer 17,094' 3,808' . Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge MPU M-19 Schematic 1-15-2020 Page 2 of 2 DH 1/15/2020 Hilcorp Energy Company Composite Report Well Name: MP M-19 Field: Milne Point County/State: North Slope Borough, Alaska Elevation (RKB): 34.36 API #: 50-029-23655-00 Spud Date: 12/16/2019 Contractor Doyon 14 Rig Name t Activity Date Number Present Operations Ops Summary 12/14/2019 Doyon 14 Moving rig from M-23 Rig on M-23, see M-23 report for details. PJSM. Skid rig floor into moving position. Jack up rig and remove shims. Notify pad operator of rig to M-19 move. Move riq off M-23 and currently moving from the north side to the south side of the pad. 12/15/2019 Doyon 14 Clean and inspect Move rig from north side of the well row and spot on well M-19. Level and shim the rig. Skid the rig floor into drilling position. N/U diverter knife valve adapter, annular & knife valve. Begin installing diverter line. R/U rockwasher & fuel trailer. Spot service buildings, water pump house & water tanks. Install walkways and landings outside rig. Work on rig acceptance checklist. R/U accumulator lines to annular & knife valve. Install riser & turnbuckles. Continue installing diverter line. Sim -ops: C/O top drive saver sub.;Continue work on diverter line & rig acceptance checklist. Rig accepted at 00:00. Finish changing out saver sub Install 4" ball valves on conductor. Perform derrick inspection. Slip & cut drilling line. Install 90' mousehole. Load 17 jts. HWDP in the pipe shed. Sim -ops: Load 290 bbls mud & 90 bbls H2O into the mud pits. Finish diverter line. 354' total length, 345' outside of sub -structure. 181' to 45° tee (6' length), 82' to 22.5° tee (3' length), then 82' to end. 307' from sub -structure to end & 98' to ignition source (production facility) Process HWDP & load 5" drill pipe. Install the mousehole in the rotary table. P/U 17 joints of HWDP & jars and rack back in the derrick. Perform diverter function test. AOGCC inspector Matthew Herrera waived witness of the test at 17:10 on 15 Dec 2019. Knife valve open in 20 sec. & annular close in 28 sec. System pressure = 3000 PSI After closure = 1800 PSI 200 PSI recovery = 37 sec Full recovery = 162 sec 6 bottle N avg = 2012 PSI. M/U 12-1/4" Kymera KM633X bit, 8" Sperry mud motor, XO sub to 36.4'. M/U stand of HWDP & tag bottom at 114'. Sim -ops: Test PVT & flow alarms - good. Test H2S & LEL alarms - good. Pre -spud meeting with all parties involved. I.D. primary & secondary muster areas and hazards with rig on diverter. Flood stack with water to check for leaks - knife valve leaking. Function, clean and inspect knife valve. 12/16/2019 Doyon 14 Drilling 12-1/4" surface Change out Knife valve due to leaking seal. Perform diverter function test over. 13 sec open and 26 sec annular closure time. Flood stack. hole at 2250' Good. Test lines to 3500 psi. Good. Drill 12-1/4"" surface hole f/ 114't/ 220', 106' drilled, 106'/hr AROP. Drill 1 st 10' w/ fresh water then displace to 8.8 ppg spud mud. 430 GPM, 660 PSI, 40 RPM, 3K TQ, 4K WOB 53K PU / 53K SO / 53K ROT. BROOH f/ 220't/ 127'430 GPM, 500 psi, 40 RPM. Pull out on elevators from 127' to top of mud motor at 36'. M/U Remaining BHA #1 - Directional, EWR-M5 Collar (PWD, AGR, EWR, HCIM DDS2) & TM - to 70'. Plug in, confidence test and initialize tools. RIH with three NMDC to 167'. M/U stand of HWDP, RIH t/ 220'. Drill 12-1/4" surface hole f/ 220't/ 631', (628' TVD) 411' drilled, 102.8'/hr AROP. 500 GPM, 1420 PSI, 50 RPM, 3K TO. 15K WOB MW 9.1 in / 9.1 out, vis 296 in / 300 out, 9.7 ECD. 76K PU / 76K SO / 75K ROT Kick off @ 260', target 3° BUR, increasing to 4° BUR at 550'. Drill 12-1/4" surface hole f/ 631't /1392', (1285' TVD) 761' drilled, 126.8'/hr AROP. 550 GPM, 1560 PSI, 60 RPM, 5K TQ, 15K WOB. MW 9.2 in / 9.3 out, vis 132 in / 300 out, 10.3 ECD, max gas 36u. 88K PU / 86K SO / 87K ROT Increase to 5° BUR at 750' then back to 4° at 1000'. Drill 12-1/4" surface hole f/ 1392't/ 2250', (1711' TVD) 838' drilled, 143'/hr AROP. 550 GPM, 1970 PSI, 70 RPM, 6K TO, 7- 12K WOB. MW 9.45 in / 9.5 our, vis 280 in / 300+ out, 10.54 ECD, max gas 29u. 96U PU / 76K SO / 86K ROT End of build at 2200', begin 71 ° tangent. Last survey at 2212.65' MD / 1700.09' TVD, 71.09° inc, 167.07° azm, 1.46' from plan, 1.36' low and 0.53' left. 12/17/2019 Doyon 14 Drilling 12.25" surface Drill 12-1/4" surface hole f/ 2250' U 3397' (2072' TVD), 1146drilled, 191'/hr AROP. 556 GPM, 1810 PSI, 80 RPM, 8K TQ, 15K WOB. MW hole at 5396' in/out 9.3/9.5, vis in/out 110/200, 10.45 ECD, max gas 147u. PU/SO/ROT 102k/76k/90k Hold 71° tangent. Base of permafrost logged at 2622' MD / 1836' TVD. Pump 30 bbl hi vis @ 2929', back on time with no increase. Drill 12-1/4" surface hole f/ 3397't/ 3926' (2245' TVD), 529' drilled, 88.2'/hr AROP. 550 GPM, 1730PSI, 80 RPM, 7K TQ, 10-15K WOB. MW in/out 9.3 / 9.4, vis in/out 131/ 246, 10.4 ECD, max gas 98u. PUISO/ROT 116k/71 k/94k Hold 71* tangent. Pump 30 bbl hi vis sweep @ 3491'& 3871, back on time with no increase. Top of Ugnu logged at 3494' MD / 2101' TVD. Drill 12-1/4" surface hole f/ 3926't/ 4442' (2416' TVD), 516' drilled, 86'/hr AROP. 590 GPM, 2000 PSI, 80 RPM, 9K TQ, 5-15K WOB. MW in/out 9.3 / 9.3, vis in/out 113 / 217, 10.3 ECD, max gas 105u. PU/SO/ROT 132k/70k/96k. Hold 71° tangent. Backream full stands to clean up the hole when ECD spiked above 11.5. Added 70 BPH H2O to lower viscosity from 130 to 90 to help reduce ECD. Drill 12-1/4" surface hole f/ 4442't/ 5396'(271 O'TVD), 954' drilled, 1597hr AROP. 590 GPM, 2340 PSI, 80 RPM, 12-14K TO, 10-12K WOB. MW in/out 9.3 / 9.4, vis in/out 88 / 130, 10.48 ECD, max gas 58u. PU/SO/ROT 141k/70k/98k. Hold 71° tangent. Pump 30 bbl hi vis sweep @ 5016', not seen at shakers. Backream full stands to clean up the hole when ECD spiked above 11.5. Last survey @ 5262.07' MD / 2669.21' TVD, 71.35° inc, 165.87°, 12.47' from plan, 8.58' high and 9.05' left. 12/18/2019 Doyon 14 Drilling 12-1/4" surface Drill 12-1/4" surface hole f/ 5396't/ 6348' (3008' TVD), 952' drilled, 158.6'/hrAROP. 593 GPM, 2570 PSI, 80 RPM, 15K TQ, 10-12K WOB. hole at 7534' MW in/out 9.2+/ 9.3, vis in/out 89 / 220, 10.4 ECD, max gas 95u. PU/SO/ROT 170k/65k/105k. Hold 71° tangent. Backream full stands to clean up the hole when ECD spiked above 11.5. Pump 30 bbl hi vis sweep @ 6062', on time w/ 10% increase;Drill 12-1/4" surface hole f/ 6348' t/ 7014 (3243' TVD), 666' drilled, 111'/hr AROP. 590 GPM, 2450 PSI, 80 RPM, 18K TQ, 5-15K WOB. MW in/out 9.3 / 9.5, vis in/out 88 1145, 10.3 ECD, max gas 81 u. PU/SO/ROT 182k/72k 112k. Hold 71' tangent. 6750' add 5 drums of screen kleen pre -treating the mud to .5% for Ugnu MB sand. Drill 12-1/4" surface hole f/ 7014't/ 7402' (3362' TVD), 388' drilled, 129.37hr AROP. 550 GPM, 2070 PSI, 80 RPM, 19K TQ, 5-15K WOB. MW in/out 9.3 / 9.4, vis in/out 86 / 178, 10.3 ECD, max gas 1032u. PU/SO/ROT 200k/75k 116k. Hold 71' tangent. Observe heavy oil & sand across the shakers from Ugnu MB sand. Slow to 450 GPM & shakers still running over. Blinding shaker screen resulted in low pit volume & full rock washer. Ugnu MB at 7116' MD / 3259' TVD. MC at 7401' MD / 3361' TVD. Rack back stand & blow down top drive. Clean shaker screens & transfer mud from the rock washer to the mud pit over the shakers. Attempt 350 GPM then slow to 275 GPM, screens still running over. Shut down, blow down top drive & change screens to 100 & 120 mesh. Pump mud from rock washer to pit again;Stage pumps up to 315 GPM, shakers running over slightly. Circulate a bottoms up. Rack back pipe to above the Ugnu MB at -7180'& reciprocate to 7100'. Build 180 bbls of new mud in pit #5. Circ 0.75 bottoms up. TIH f/ 71 00' t/ 7402'. PU 205 / SO 65 / ROT 125 (Gain 5K PU, lost 10K SO & gained 4K TQ);Ddll 12-1/4" surface hole f/ 7402' U 7534' (3404' TVD), 132' drilled, 377/hr AROP. 600 GPM, 2420 PSI, 80 RPM, 20-23K TQ, 10-24K WOB. MW in/out 9.1/ 9.15, vis in/out 63 / 82, 9.75 ECD, max gas 289u. PU/SO/ROT 200k/65k 116k. Began adding 0.5% LoTorq lube at 7485'. Last survey @ 7452.82' MD / 3878.42' TVD, 70.76° inc, 168.5° azm, 2.13' from plan, 2.09' high, 0.39' left. Currently in Ugnu MC sand. Began 4°/100' build & turn at 7492'. 12/19/2019 Doyon 14 BROOH at 6732' Drill 12-1/4" surface hole f/ 7534't/ 8061' (3536' TVD), 527' drilled, 87.8'/hr AROP. 565 GPM, 2370 PSI, 80 RPM, 19K TO, 15-18K WOB. MW in/out 9.2/ 9.3, vis in/out 66 / 188, 10 ECD, max gas 272u. PU/SO/ROT 185k/74k 115k.;At 7681' shakers blinding off due to heavy oil and sand, work pipe while C/O back screens f/ 100# to 80# mesh, stop adding lubes @.5% Encounter fault #1 @ 7748' md, 3462' tvd wl 75' throw DTE. Turn 4 deg1100'. Drill 12-1/4" surface hole f/ 8061' tt 8633' (3683' TVD), 572' drilled, 95.3'/hr AROP. 580 GPM, 2570 PSI, 80 RPM, 20K TO, 5-15K WOB. MW in/out 9.4/ 9.4, vis in/out 74 / 158, 10.2 ECD, max gas 252u. PU/SO/ROT 195k/75k 115k. Continue to turn 4 deg/100' to 8606', maintain 72 deg inc to 8347', build 4 deg /100'. Pump 30 bbl hi vis sweep @ 8340', back on time with no increase;Drill 12-1/4" surface hole f/ 8633't/ TO of well at 8914' (3707' TVD), 281' drilled, 70.37hr AROP. 580 GPM, 2660 PSI, 80 RPM, 20K TO, 20K WOB. MW in/out 9.3/ 9.35, vis in/out 64 / 126, 10.1 ECD, max gas 61 u. PU/SO/ROT 195k175k 115k. Schrader Bluff OA -1 logged at 8775' MD / 3701'TVD. Last survey @ 8873.82' MD / 3706.14' TVD, 88.52° inc, 124.75° azm, 54.54' from plan, 53.22' low & 11.92' right. Obtain final survey. Pump 30 bbl hi vis sweep w/ nut plug. Nut plug observed early & sweep on time w/ 5% increase in cuttings. Circulated 2x total bottoms up while racking back a stand every BU to 8722'. 600 GPM, 2550 PSI, 80 RPM, 18-20K TO. Perform flow check - static. TIH to 8914', 210 PU / 75K SO;BROOH f/ 8914't/ 6732'@ 5-15 min/stand. Slow for pressure or torque increases. 600 GPM, 2320 PSI, 80 RPM, 18K TO. MW in / out: 9.35 / 9.4, vis in / out: 71 / 152, ECD 10.26. 12/20/2019 Doyon 14 Reading MWD tools BROOH f/ 6732't/ 4730'@ 5-10 min/stand. Slow down for pressure or torque increases. 600 GPM, 1900 PSI, 80 RPM, 14K TO. MW in I out: 9.3 / 9.6, vis in / out: 68 / 161, ECD 10.25.;BROOH f/ 4730' t/ 2827'@ 5-10 min/stand. Slow down for pressure or torque increases. 600 GPM, 1800 PSI, 80 RPM, 12.5K TO. MW in / out: 9.2 / 9.3, vis in / out: 51 / 70, ECD 10.2. Pump 30 bbl hi vis sweep just below the BPF 600 GPM, 1680 psi, 80 RPM, 10-11 k TO pulling 3 fpm f/ 2827' U 2732'. Sweep not observed at surface. BROOH f/ 2732' t/727',@ 5-10 min/stand. Slow down for pressure or torque increases. 450 GPM, 970 PSI, 60 RPM, 5-15K TO. ECD climbed from 10.3 to 11.1 at 2035'. Pull slow f/ 2035't/ 1942' and allow to clean up. MW in 9.25, out 9.5, Vis in 38, out 51. PU 88K / SO 92K / ROT 87K. Pull last stand slow f/ 830't/ 727' to get a bottoms up - sand w/ fine silt cleaned up to background after bottoms up. Flow check well - static. Pull first stand of HWDP on elevators f/ 727't/ 634'- no problems. Blow down top drive. POOH f/ 634't/ 436', began to see 25-50K over pull. BROOH f/ 436' t/ 169'. 450 GPM, 680 PSI, 40 RPM, 2-1 OK TO. Observe heavy sand across the shakers. Pulled last stand slow until sand cleaned up to background. Flow check well - static. Blow down top drive. PJSM for laying down BHA. UD XO & 3 NMDC from 169' to 79'. Plug in and read MWD tools. 12/21/2019 Doyon 14 Running 9.625" casing Finish reading MWD, UD remaining BHA, Note: mud motor had excessive bearing play and was dry. 1/4" bit grade= 1 -1 -CT -A -E -1 -NO -TD, at 6837' Clear and clean rig floor. Bring up 9 5/8 Casing equipment to rig floor. R/U Volant, Strap tongs, Spiders, M/U XO on FOSV, Monitor well, static. PJSM, Baker lock and M/U Shoe Track T/ 162'. Install Bypass Baffle above float collar, ensure proper float operation, baker lock and M/U BA jt. Use strap tongs for back ups. Run 9-5/8" 40# L-80 TXP-BTC casing F/ 162'T/ 2841'. TO to 20,960 ft/lbs w/ the Volant tool. Install one 9-5/8" x 12-1/4" Expand-O-Lizer every joint to #25, then every other jt f/ #27 t/ #65. Fill pipe on the fly & top off every 10 joints. Stage up pumps to 6 BPM, 130 PSI. Reciprocate 35'f/ 2841't./ 2806'. Circulate 2 bottoms up, observe moderate amounts of sand back over the shakers. Shakers cleaned up to background cuttings load at 1.8 bottoms up. Run 9-5/8" 40# L-80 TXP-BTC casing F/ 2841'T/ 4651'. TO to 20,960 ft/lbs w/ the Volant tool. Fill pipe on the fly & top off every 10 joints. 205K PU / 75K SO. Run 9-5/8" 40# L-80 TXP-BTC casing F/ 4651' T/ 6837'. TO to 20,960 ft/lbs w/ the Volant tool. Install one 9-5/8" x 12-1/4" Expand-O-Lizer every joint from #147 to 9156, then every other jt f/ #158 t/ #172;ES cementer installed between ioints #151 & 152, w/ one 9-5/8" x 12-1/4" centrailizer & stop ring on the pump joint above & below. Fill pipe on the fly & top off every 10 joints. 305K PU / 60K SO. No losses for casing run to this point. 12/22/2019 Doyon 14 Displacing 1 st stage Run 9-5/8" 40# L-80 T) -BTC 'w/ hard tag @ 7288'. setting down up to 25k trying to work past. Install one 9-5/8" x 12-1/4" cement Expand-O-Lizer every joint V#147 to #156, then every otherjt f/#158 t/ #184. TO to 20,960 ft/lbs w/ the Volant tool. No losses to this point. PU/SO 305K/60K. Stage pump to 6 bpm slowly 360 psi, establish rotation 2/3 rpm, 20k tq, work pipe from 7288' to 7270' seeing 25k overpull, shut off rotary, work pipe and CBU, seeing a lot of sand at shakers, MW in/out 9.2, / 9.6, vis in/out 37/82, after BU increase to 7 bpm, 200 psi. Notify Hilcorp town team. Circulate another BU, Rotate 3-5 rpm, 20k tq, working pipe f/ 7288' up to 7245' with no overpull seeing smaller amounts of sand @ shakers, attempt to rotate past 7288', with rotary off stack 5k pumping 7 bpm w/ 50 psi pressure increase attempting to wash past tight spot. Attempt to wash past tight spot., set slips, break out volant, clean dies, re -dope cup and M/U same. continue circulate attempting to wash past tight spot making a few inches an hr, finally work past tight spot 5 bpm, 200 psi, rotating while working pipe. Run 9-5/8" 40# L-80 TXP-BTC casing F/ 7290'T/ 8264' pumping 3 1/2 bpm, 220 psi rotating w/ tq set at 21,000 ft/lbs to get down, pump 40 bbl lube pill w/ 6% lubes while RIH. Continue installing centralizers on every other jt. Galled pin on jt. #210 and collar on #209. No losses. UD joint #210. Circulate and work pipe to prevent freezing and casing sticking while sourcing replacement collar. Replace collar on joint #209. Run 9-5/8" 40# L-80 TXP-BTC casing F/ 8264 T/ 8910', pumping 3.5 BPM, 170 PSI, rotating w/ TO set at 21 K ft/lbs - pipe turning 1-2 RPM. Cotinue installing centralizers on every other jt. No losses. Total ran: 225 joints, 91 each 9-5/8" x 12-1/4" centralizers and 8 stop rings.;Stage pumps up to 7 BPM, 230 PSI, rotating w/ TO set at 21 K ft/lbs - pipe turning 1-2 RPM when reciprocating. Reciprocate f/ 8910' t/ 8880'. 325K PU / 75K SO with rotation. PJSM for cement job w/ all parties. Circulated 1.9 bottoms up. Blow down top drive & rig up cement lines. Pump 6 BPM, 330 PSI, rotating w/ TO set at 21 K ft/lbs - pipe turning 1-2 RPM when reciprocating. Halliburton troubleshoot aux motor & Steady -Flow Uni-valve. Started motor & will manually send product this stage. Will repair Steady -Flow between t1 stages. Pump 5 bbls H2O @ 2 BPM, 75 PSI. Pressure test lines to 1300/4000 PSI. Mix & pump 60 bbls 10 ppg Tuned Spacer @ 2 BPM, 71 b 140 PSI. Drop by-pass plug. Mix & pump 401.6 bbls (960 sks (07 2.349 ftA3/sk yield) 12.0 ppg Premium G lead cement @ 5 BPM, 405 PSI D ICP, 330 PSI FCP. Rotate & reciprocate, became sticky at end of lead, 400K PU / no SO. Park casing at 8907' in upstroke. Mix & pump 82 bbls (400 sks @ 1.156 ftA3/sk yield) 15.8 ppg Premium G lead cement @ 2.5 BPM, 170 PSI ICP, 275 PSI FCP. Drop shut-off plug. Pump P✓7 20 bbls H2O @ 5 BPM, 240 PSI. 6,5 -C 12/23/2019 Doyon 14 N/D diverter tee & Displace 1st stage HES pump 20 bbl H'O. Line up to rig and displace with 4098 stks 9.4 ppg mud. (412.7 BBLS) 6.5 BPM, 440 psi, with diverter adapter HES pump 80 bbis 9.4 ppg tuned prime spacer @ 3bpm, 311 psi, swap back to rig pump. Continue to displace w/ 9.4 mud @ 5.5 bpm, 690 psi, slow to 3 bpm @ 10 bbls away, FCP 550 psi, total 5680 stks ( 572 BBLS) plug bumped 61 stks over calculated, pressure to 1080 psi and hold for 5 min.;Bleed off pressure, floats held, CIP @ 08:07, Pressure up to 3040 psi shifting cementer tool open. Note: 493 bbls into disp start seeing poly flake @ surface, No losses pumping and displacing 1 st stage. Circulate thru ESC @ 2946' Pumping 6 bpm, 240 psi, seeing tuned spacer @ 2800 stks, dump to rock washer @ 3000 stks, 3450 stks seeing interface, 3800 stks seeing cement, 4400 stks mud at surface, 4750 stks divert clean mud to pits. Dump 60 bbis cement, 70 bbls spacer and 45 bbis contaminated mud. After 3 BU seeing thick mud, slow to 2.5 bpm, 200 psi, dump thick returns as needed. Submit 24 hr BOP test notification to AOGCC @ 09:39. Shut down, flush out BOPS and surface equipment with black water. Continue to circulate through the ESC tool at 2-3 bpm at 140-220 psi while WOC to reach 500 psi compressive strength for 2nd stage, seeing very thick mud returns, having to shutdown pump, flush and clear flow line w/ black water & dump as needed. Used all mud in pits, then 270 bbis contingency mud f/ vac truck, 430 bbsl thick mud dumped at this point, build another 200 bbls mud in pit 5, stage pump to 3 bpm, 20 psi dumping an additional 70 bbis thick mud, divert returns to pits. Break out volant- inspect, clean and re -dope, M/U same, continue to circ 6 BPM, 160 PSI while prep for 2nd stage, hauling hot water, stock hopper room, build 2 batches black water, cleanout rock washer. PJSM for cement job. Begin batching spacer. Pump 5 bbis H2O. Pressure test lines to 1200 PSI low / 4300 PSI high. Mix & pump 60 bbis 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbis at 2.4 BPM, 75 PSI. Mix & pump 471 bbls 10.7 ppg (600 sks (ED 4.407 ftA3/sk yield) Permafrost L lead cement at 5.0 BPM, 380 PSI.;Saw red dye, but no Pol-E-Flake at 438 bbls of Ieadpumped. Observed spacer back at 455 bbis of lead pumped. Mix & pump 56.2 bbis 15.8 ppg (270 sks @ 1.169 ftA3/sk yield) Premium G tail cement @ 2.8 BPM, 210 PSI. Drop closing plug. Pump 20 bbis H2O at 5.25 BPM, 260 PSI. Observed spacer/cmt interface back for 76.2 bbls. Displace w/ 9.4 ppg spud mud at 6 BPM, 260 PSI ICP, 570 PSI FCP. Slow to 3 BPM, 480 PSI for last 10 bbls. Bumped plug (d 2008 stks, 1 bbl early. Pressure up & ES cementer closed (a_) 1420 PSI. CIP @ 23:18.;Bleed off w/ no flow back - confirmed cementer closed. 202�s of cement back to surface. Blow down cement lines. Disconnect accumulator lines to knife valve. Flush diverter stack with black water, functioning annular diverter 3 times. Back out Volant tool from casing. Vacuum out mud from joint prior to cut. Clean casing equipment & R/D spiders. Disconnect knife valve & diverter line. N/D diverter from adapter & hoist stack. Sim - ops: N/D diverter line. Install 9-5/8" casing slips as per well representative. Set casing slips w/ 11 OK on slips (155K hook load - 45K top drive & Volant). Rough cut 9-5/8" casing & UD pup & cut joint (18.28'). Set diverter back down on adapter & M/U 4 bolts. N/D flow nipple, riser & diverter annular. UD both mouse holes. Sim -ops: clean pits 12/24/2019 Doyon 14 RIH with 8.5" Cleanout N/D flow nipple & riser. N/D diverter & diverter adapter. SimOps: Cleaning pits, work on drag chain. Install Cameron T-103 nipple and test assembly at 141' to 500 PSI for 5 min & 2475 PSI for 10 min. Install T-103 tubing head and test to 500 PSI for 5 min. & 5000 PSI for 15 min. N/U BOP stack, turnbuckles and kill line. Install trip nipple, load shed with 3 1/2" and 5" test joints, mobilize test plug, wear bushing and split bushings to rig floor. Continue to work on drag chain roller bearing, spot MPD shack. Crew change, PJSM. Install trip nipple, remove 4" conductor valves and install caps. R/U to test BOP equipment: install test plug and 3-1/2" test joint. Grease choke manifold. Fill stack, choke and all lines with fresh water. Change out HCR choke 4 -Way valve on accumulator unit. Rig on Hi -Line Power @ 18:10.Fill lines, shell test BOPE to 3000 psi. Test BOP equipment as per PTD & AOGCC requirements. All tests performed to 250 PSI low 13000 PSI high. All tests held for 5 min. each. All tests performed w/ fresh water against test plug. Rig electrician test rig gas alarms. AOGCC rep Adam Earl witnessed BOP test. #1: Annular on 3.5" test joint, choke valves 12,13,14, 3" kill Demco. #2: Upper 2-7/8"x5" VBR on 3.5" test joint, choke valves 1, 9,11, HCR kill & upper IBOP. #3: Choke valves 5,8,10, manual kill & upper IBOP . #4: Choke valves 4,6,7 & 5" TIW #1. #5: Choke valve 2 & 5" TIW #2.;#6: HCR choke, dart valve. #7: Lower 3-1/2"x6" VBR on 3.5" test joint. #8: Hyd choke "A" & Man choke "B". #9: Upper 2-7/8"x5" VBR on 5" test joint & manual choke. #10: Lower 3-1/2"x6" VBR on 5" test joint. #11: Blind rams, choke valve #3. Accum test: 3000 PSI system pressure, 1650 PSI after closure. 39 sec for 200 PSI recharge, 183 sec full PSI recharge. 1925 PSI six nitrogen bottle average. R/D test equipment and blow down lines. Install 10" I.D. wear bushing. Mobilize BHA components to the rig floor. Blow down choke and kill, Install mouse holes. PJSM, M/U 8-1/2" cleanout BHA. Used 8-1/2" Smith XR+ bit, 6-3/4" mud motor w/ float installed, and 5" HWDP't/ 141'. 12/25/2019 Doyon 14 POOH on elevators at Continue to TIH with 8 1/2" cleanout BHA 2 f/ 141' with 5 stds 5" HWDP and jar std to 589', RIH w/ 5" stds DP to 2780', M/U TD, wash 6281' down tagging ESC on depth @ 2946'. DTII ES cmt tool on depth at 2946', pump 425 gpm, 890 psi, 50 rpm, 5-7k tq. Work through 3 times cleaning up same, cleanup cement string @ 2966', pass thru ESC w/ pump off, good. BD TD. PU/SO/ROT 110K/70K/87K. TIH f/ 2971't/ 8684' @ 10' above BA, Fill pipe every 2000' ran. Note @ 7200' M/U top drive on ea. stand and rotate 20 rpm, 13k torque to get down due to no S/O weight, wash down f/ 8734' to 8775'2 bpm, 440 psi. CBU @ 8785' pumping 6 bpm, 670 psi reciprocating pipe 80', 30 RPM - 27k Tq. Start bringing 776 lube up to 0.5. UD single, R/U test equipment, close UPR, purge air from lines, PT 9 5/8" casing to 2500 psi for 30 min, good test, bleed off pressure, open UPR. 6.6 bbls pumped, 6.6 bbls bled back. M/U single, Tag cement @ 8791', drill cement and F/E from 8791' to 8907'& Clean out rathole t/ 8914' at 450 GPM, 1680 psi, 40 RPM = 25K torque, 4-11 K WOB. D6II 20' of new formation to 8934'. Continue to bring lube up to 0.5%. PU 250K, SO 50K, ROT 118K, Max Gas- 123u. Pull into 9 5/8 casing @ 8907', circulate and condition mud for FIT, 450 GPM, 1300 PSI, 20 RPM, 20K torque, reciprocate pipe 8877'-8782', until good 9.45 MW in/out. Parked @ 8877', R/U test equipment, close UPR, purge air from lines, Perform FIT to 12 ppg with existing 9.45 ppg MW, apply 500 psi, bleed off pressure, open UPR, R/D test equipment. Good test. 1.5 BBLS pumped, 1.5 bbis bled back. Flow check well, static. POOH f/ 8877' tl 8770'. P/U 250k, no slack off with 0.5% lube. Establish circulation at 450 GPM -1450 psi, increase lube to 0.75%. Rotate and reciprocate pipe, 30 RPM 21-24k Tq, Regain S/O wt. of 50k. P/U 250k, S/O 50k, ROT 120k. Monitor well, static. Blow down TopDrive and POOH from 8770't/ 6942'. Correct hole fill observed. Pump dry job and continue to POOH on elevators to 6281'. 12/26/2019 Doyon 14 Blow down lines in Continue to TOOH pulling on elevators with cleanout BHA f/ 6942' to HWDP @ 589', flow check the well, static. Lay down 15 jts 5" HWDP, prep to cut & slip Drig Rack jar stand in Derrick, Drain motor, UD remaining BHA. 8-1/2 tri -cone bit grade= 1 -1 -WT -A -E -1 -NO -BHA. 13 bbl losses on TOOK Clear line and clean the rig floor, Mobilize RSS BHA components to the rig floor. R/U Geo -span lines. Install BOP drip pan. PJSM. M/U 8-1/2" production drilling BHA #3 to 87': NOV SK616MJ1 D bit, NRP sleeve, Geo -Pilot, MWD (ADR/ILS/DGR/PWD/DM/TM) initialize tools. M/U 2 float subs, TIH w/ 3 NM flex collars, HWDP & jars t/ 279'. Pulse test MWD, 500 gpm, 1050 psi, BD top drive. Swap to Rig gen power @ 14:00. PT Geo-span,TIH f/ 279't/ 2000'. Fill pipe and break in Geo -Pilot seals, Blow down top drive. Continue to TIH f/ 2000' t/ 8878' with stands f/ Derrick. Fill pipe every 2000'. No losses. P/U= 225k, S/O = 50k. Monitor well- Static, PJSM, PT MPD lines, 25011500 psi. Remove trip nipple, install RCD bearing as per MPD rep. PJSM, Pick up single from shed. Pump 30 bbl hi vis spacer, Displace w/ 654 bbls 8.8 ppg flow pro NT mud 300 gpm, 850 psi. Slack off U 8933' when spacer near bit. With mud out bit, P/U into 9 5/8" casing rotate 30 rpm, 27k tq working pipe at start, 12k tq final,;Dump all spud mud returns to rock washer. Shut down, close MPD and monitor pressure, No increase. Obtain new SPRs. Blow down MPD lines. Rig up to Slip and Cut drilling line. 12/27/2019 Doyon 14 Trouble shoot Parked @ 8849' held PJSM, M/U FOSV and 5' pup, Slip and cut 79' ddg line, UD FOSV/pup, recalibrate block height. Monitor well with TopDrive faults MPD. Service top drive and draworks, inspect saver sub, clean and inspect grabber dies. Finish cleaning under shakers and pit 4. M/U stand of drillpipe in mousehole. RIH f/ 8849" t/ 8934'. Tag bottom on depth. PU/SO/ROT 155K/80K/115K. Drill 8-1/2" lateral f/ 8934' t/ 9136' (3703' TVD), 202' drilled, 67.3/hrAROP. Drill in the OA-1, 550 GPM, 1800 PSI, 100 RPM, 1OKTQ, 10-12K WOB. MW 8.9, vis 50, ECD 10.5, max gas 220u. PU/SO/ROT 135k/88k/l 10. MPD monitor for pressure build during connections w/ 40 psi line pressure, fully open while drilling. Drill 8-1/2" lateral f/ 9136' t/ 9849' (3708' TVD), 713' drilled, 118.8 ft/hr AROP. Drill in the OA-1, target 89.5 deg. 550 GPM, 1870 PSI, 100 RPM, 13K TQ, 6-15K WOB. MW 8.9, vis 49, ECD 10.63, max gas 189u. PU/SO/ROT 145k177k/l 11 k. MPD monitor for pressure build during connections w/ 40 psi line pressure, fully open while drilling. Pump 30 bbl hi vis sweep @ 9518', back on time w/ no increase. Note: at 9520' MWD computer crashed during survey, swap to backup computer and get up and running. Drill 8-1/2" production lateral f/ 9849" t/ 10538' (3731' TVD), 689' drilled, 1157h AROP. 550 GPM, 1980 PSI, 130 RPM, 12-13k TO, 10-11 k WOB. 8.8 ppg MW, 44 vis, 10.88 ECD, 243u max gas. 140k PU / 75k SO / 109k ROT. Undulate f/ OA-1 t/ OA-3 @ 10090'. Top of OA-2 @ 10498'. MPD monitor for pressure build during connections w/ 40 psi line pressure, fully open while drilling. Pump 30 bbl hi vis sweep @ 9995', back on time w/ 40% increase. Drill 8-1/2" production lateral f/ 10538' t/ 11 089'(3748' TVD), 551' ddlled,1107hr AROP. 550 GPM, 2200PSI, 120 RPM, 12k TQ, 10k WOB. 140k PU / 78k SO / 110xk ROT. 8.85 ppg MW, 46 vis, 11.15 ECD, 246u max gas. MPD monitor for pressure build during connections w/ 40 psi line pressure, fully open while drilling. Pump 30 bbl hi vis sweep @ 10562', back on time w/ 40% increase. Pump hi vis sweep @ 11040', on time w/ 40% increase. Top of OA-3 @ 10742'. Troubleshoot Geo-Span/Geo-Pilot communications. Change out Geo Span choke nozzle. SimOps: Troubleshoot TopDrive low oil indicator and inability to rotate TopDrive. Drilled 12 concretions for a total thickness of 61'(2.8% of the lateral). Last survey @ 10967.38' MD / 3749.46' TVD, 89.39° inc, 127.30' azm, 12.76' from plan, 10.6' low and 7.1' right. 12/28/2019 Doyon 14 Drilling 8.5" lateral @ Work pipe f/ 11080; troubleshoot Geo-Span/Geo-Pilot communications. C/O Geo Span choke nozzle. Troubleshoot inability to rotate TD, 13704 Turn offTD VFD house for 15 min, turn VFD back on, regain TD rotation. Rack 1 stand back to 11050';M/U TD, circulate 550 gpm, Geo- Span/Geo-pilot communication working as it should, with TO at rig floor, check gear oil level- good, suspect cold gear oil due to TO above wind wall while troubleshooting tool signal loss, TO functioning properly, no other issues at this time, M/U std DP. Drill 8-1/2" lateral f/ 11089' t/ 1161 0'(3754' TVD), 521' drilled, 115.7/hr AROP. Drill in OA-3, Target 90 deg inc. 550 GPM, 2150PSI, 130 RPM, 18k TO, 10k WOB. MW 8.9 ppg, vis 46. ECD 11.1, max gas 296u. PU/SO/ROT 147k / 65k / 104k. MPD monitor for pressure build during connections w/ 40-60 psi line pressure, fully open while drilling. Pump 30 bbl hi vis sweep @ 11610', Sweep back on time, 25% increase. Drill 8-1/2" lateral f/ 11610' t/ 12386' (3766' TVD), 776drilled, 1297hrAROP. Drilling in OA-1. 520 GPM, 2080PSI, 120 RPM, 14k TQ, 10-11k WOB. MW 8.8 ppg, vis 44. ECD 11.48, max gas 270u. PU/SO/ROT 146k / 60k / 104k MPD monitor psi during connections, building to 240 psi at 12270' , fully open while drilling. Encountered Fault #1 @ 11,810' and 18' DTSW. Faulted from bottom OA-2 to top OA-1. Exited OA sand at 11,844' md, back in the sand @ 11,968' and for a total of 124' in shale above the OA sand package. Note: when crossing fault 1 seen 32 bbl losses in 15 min, then stabilizing. Pump 30 bbl hi vis sweep @ 12182', on time w/ 50% increase. Drill 8-1/2" lateral f/ 12386' U 12944' (3753' TVD), 558' drilled, 93'/hr AROP. Drilling in OA-3. 530 GPM, 2130PSI, 120 RPM, 15k TQ, 9-11 k WOB. MW 8.9 ppg, vis 42. ECD 11.25, max gas 223u. PU/SO/ROT 150k / 60k / 105k. MPD holding 200 psi during connections, fully open while drilling. Pump 30 bbl hi vis sweep @ 12661', back 100 stk late w/ 20% increase. Encountered Fault #2 @ 11,968' and 23' DTNE. Faulted from shale above the OA-1 into top of OA-3. Encountered Fault #3 @ 12427' and 7' DTNE. Faulted from the upper OA-3 to the base of OA-3. Drill 8-1/2" lateral f/ 12944' t/ 13704' (3736' ND), 760' drilled, 127'/hr AROP. Drilling in OA-1. 500 GPM, 2080 PSI, 120 RPM, 14k TQ, 6k WOB. MW 9 ppg, vis 45 ECD 11.40, max gas 230u. PU/SO/ROT 150k / 50k / 104k. MPD holding 200 psi during connections, fully open while drilling. Pump 30 bbl hi vis sweep @ 13229', back 100 stk early w/ 50% increase. Pump 30 bbl hi vis sweep @ 13514, back 100 stk early w/ 25% increase. Drilled 21 concretions for a total thickness of 107' (2.3% of the lateral). Last survey @ 13628.97 MD / 3740.380' TVD, 88.95° inc, 122.88' azm, 27.23' from plan, 4.04' high and 26.93' left. 12/29/2019 Doyon 14 Drilling 8-1/2" Drill 8-1/2" lateral f/ 13704' t/ 14276' (3739' TVD), 572' drilled 95.3'/hr AROP. Enter OA-3 @ 13904'. 500 GPM, 2100 PSI, 120 RPM, 14-15k production hole at TQ, 8k WOB. MW 9.1 ppg, vis 45 ECD 11.17, max gas 229u. PU/SO/ROT 155k / 50k / 102k. MPD holding 145 psi during connections, fully 15514' open while drilling. Pump 30 bbl hi vis sweep @ 14273', back on time w/ 50 % increase. Drill 8-1/2" lateral f/ 14276' t/ 14564' (3735' TVD), 285' drilled. Enter OA-3 @ 13904'. 500 GPM, 2200 PSI, 120 RPM, 16k TQ, 16k WOB. MW 9 ppg, vis 45, ECD 11.6, max gas 271 u. PU/SO/ROT 150k / 50k / 104k. Continue in OA-3, encounter fault #4 @ 14045'w/ 13' DTSW throw putting us f/ top OA-4 to bottm of the OA- 2, point up crossing into OA-1 @ 14238' and out the top @ 14510' into shale, decision made to side track. MPD holding 120-145 psi during connections, fully open while drilling. Obtain SPRs, BROOH f/ 14561' to 13950' racking back 6 stds DP pumping 500 gpm, 2150 psi, 100 rpm, 11-13K torque. Trough 20'f/ 13960' to 13980' Control drill @ 50'/hr acquiring 1.5 deg separation, Sidetrack low side and drill f/ 13980' t/ 14040'w/ 2.5 deg separation from old wellbore pumping 500 GPM, 2020 PSI, 120 RPM, 12K TQ. drill to 14087'. Drop into OA-4 @ 14010', Fault #4 @ 14045' put wellbore into OA-3. BROOH f/ 14087't/ 13896', 500 GPM - 2020 PSI. 100 RPM - 13k Tq. Trip back through sidetrack point and verify good hole. Continue sidetrack 8-1/2" lateral f/ 14087' t/14564' (3761' TVD), 477' drilled. Maintain OA-3. 510 GPM, 1940 PSI, 120 RPM, 13k TQ, 1 Ok WOB. MW 8.8 ppg, vis 40, ECD 10.98, max gas 193u. PU/SO/ROT 161 k / 58k / 107k. MBT >6, Dump and dilute 290 bbls whole mud @ 14500'. 8-1/2" lateral f/ 14564' U 14752' (3763' TVD), 188' drilled. Maintain OA-3. 510 GPM, 1940 PSI, 120 RPM, 13k TQ, 10k WOB. MW 8.8 ppg, vis 40, ECD 10.98, max gas 193u. PU/SO/ROT 161 k / 58k / 107k. MPD holding 145-165 psi during connections, fully open while drilling. Pump 30 bbl hi vis sweep @ @ 14752'. 100 stks late w/ 40% increase. 8-1/2" lateral f/ 14752' t/ 15514' (3775' TVD), 762' drilled. 500 GPM, 2140 PSI, 110 RPM, 14k TO, 8k WOB. MW 8.9 ppg, vis 41, ECD 11.45, max gas 348u. PU/SO/ROT 170k / 40k / 105k. Start undulate up to OA-1 @ 14850. Top of OA-3 @ 14960', Top of OA-2 @ 15027'. MPD holding 145-165 psi during conn. fully open while drilling. Drilled 23 concretions for a total thickness of 111' (1.7% of the lateral). Last survey @ 15540.56' MD / 3770.84' TVD, /87.° inc, 12' azm, 12.73' from plan, 12.72' high and 0.7' left. 12/30/2019 Doyon 14 Circulating hole clean Drill 8-1/2" lateral f/ 15514' t/ 16084' (3777' TVD), 570' drilled. Avg ROP 957hr. 500 GPM, 2100 PSI, 120 RPM, 16k TQ, 8k WOB. MW 8.9 at TD ppg, vis 44, ECD 11.54, max gas 299u. PU/SO/ROT 175k / 40k / 105k. MPD holding 145-165 psi during connections, fully open while drilling. Pump 30 bbl hi vis sweep @ @ 15990', back 100 stks late w/ 10% increase. Drill in the OA-1, undulate to OA-3 @ 16000'. Drill 8- 1/2" lateral f/ 16084' t/ 16752' (3804' TVD), 668' drilled. Avg ROP 111.3'/hr. 500 GPM, 2260 PSI, 120 RPM, 17k TQ, 7-8k WOB. MW 8.9 ppg, vis 49, ECD 11.7, max gas 313u. PU/SO/ROT 176k / 40k / 102k. MPD holding 145-165 psi during connections, fully open while drilling. Note @ 16365'- 30 minutes to troubleshoot MWD computer issues, program locking up. Pump 30 bbl hi vis sweep @ 16560', 200 stks late, 50% increase. Enter the OA-2 @ 161 10'and OA-3 @ 16350'. Drill 8-1/2" lateral f/ 16752' V 17322' (3808' TVD), 570' drilled. Avg ROP 95'/hr. 450 GPM, 1900 PSI, 95 RPM, 17k TO, 8k WOB. MW 88 ppg, vis 40, ECD 11.13, max gas 268u. PU/SO/ROT 186k/40k/ 102k. MPD holding 145-165 psi during connections, fully open while drilling. Performed 290 bbl whole mud dilution at 17150'. Maintaining the OA-3. Dril18-1/2"" production lateral f/ 17322't/ 17450', (3795' TVD) 128' drilled, 102'/hr AROP. TO of well called by geologist. 500 GPM, 2050 PSI, 120 RPM, 17K TQ, 10K WOB. 8.9 ppg MW, 41 vis, 11.5 ECD, max gas 243u. PU/SO/ROT 190k / 40k / 105k. Encounter fault #5 @ 17040'w/3' DTNE throw. Entered the OA-4 @ 17150' and regained the OA-3 @ 17282'. Fault #6 @ 17370'w/ 6' DTSW throw moved the wellbore from the OA-3 into the OA-2 where trajectory stayed until TD @ 17450'. Obtain final survey and pump 30 bbl high vis sweep, back on time w/ no increase. Pump 540 GPM, 2450 PSI, 95-130 RPM, 15K TQ. Rack back a stand every bottoms up f/ 17450' t/17128'. Pump 3.5 total bottoms up. Drilled 36 concretions were drilled in the lateral, for a total thickness of 170' (2.0%). Last survey @ 14375.92' MD / 3801.16' TVD, 94.28° inc, 123.10' azm, 55.05' from plan, 50.56' low and 21.77' left. 12/31/2019 Doyon 14 BROOH @ 12885' Continue to Pump 515 GPM, 2130 PSI, 120 RPM, 15K TO. Racking back a stand every bottoms up f/ 17128'V 16816'. SimOps: Prep uprights and fill with 8.45 ppg 4% lube brine. Clean pits and build SAPP Pills. RIH f/ 16816't/ 17419'. Wash and ream 250 GPM, 700 psi. 30 40 RPM, 12k Tq. Tag bottom @ 17450'. Continue circulate while prep mud pits for displacement. 500 GPM, 2120 psi. 100 RPM, 16k Tq. Pump 30 bbls high vis spacer, 40 bbls seawater, 30 bbls SAPP pill #1, 40 bbls seawater, 30 bbls SAPP pill #2, 40 bbls seawater, 30 bbls SAPP pill #3, then 280 bbls seawater. Pump 30 bbls high vis spacer, then displace to 8.45 ppg 2% KCI brine w/ 4% lube (2% LoTorq & 2% 776). Total of 1190 bbls 4% lube brine pumped, 13 bbls loss during displacement. 185K PU / 55K SO / 115K ROT. 15K available down weight after lubed brine displacement. Obtain slow pump rates. Monitor well on MPD; shut in 3 times with pressure building to 65, 55, & 45 psi, respectively. Production Screen Test: New brine: 15.04, 15.02 & 15.05 sec. Returned brine at flow line: 14.68, 14.79, 14.85 sec. BROOH f/ 17450' V 15421' @ 5 min/stand. Lay down stands in the mousehole. 500 GPM, 1570 PSI, 100 RPM, 17k Tq. MPD full open choke while reaming (10.15 ECD), hold 100 PSI on connections (8.95 ppg EMW). Max gas 70u. 2-14 BPH losses. BROOH f/ 15421' V 12885'@ -5 min/stand. Lay down stands in the mousehole. 450 GPM, 1340 PSI, 100 RPM, 15k Tq. MPD full open choke while reaming (10.00 ECD), hold 100 PSI on connections (8.95 ppg EMW). Total 91 bbl losses while BROOK Max gas 33u. 1/1/2020 Doyon 14 Laying down RSS BROOH F/ 13185' T/ 11168'. 450 GPM, 100 RPM, 13k Tq, 1150 PSI. UD stands in the mousehole while backreaming. Service TopDive, BHA Drawworks and Iron Roughneck. Change out failed hydraulic line on iron roughneck. BROOH F/ 11 168' T/ 8853'. 450 GPM, 100 RPM, 7k Tq, 780 PSI. UD stands in the mousehole while backreaming. Circ high vis sweep around at 550 GPM, 80 RPM, 7 K TO. Brought back 10% Increase in cutings. (Sand). UP/DN 160k/90k. Shut in and monitor pressure. built to 45 PSI in 5 min. Bled down to 0 and shut in and built to 35 PSI in 5 min. Decided to bring wt to 9.0. Bring up weight in pits to 9.0 ppg. Pump 8.3 BPM, 60 RPM, 7K TQ. Circulate 9.0 ppg viscosified brine around. 9.0 in and 8.95 out. Monitor well. Static. UP/DN 160k/1 05k. Monitor well while removing RCD head and install trip nipple. Slight losses at 0.5 BPH. Slip & cut drilling line. Monitor well on TT - 2 BPH losses. Inspect saver sub. Drop 2.32" drift w/ 1 00'tail & POOH on elevators UD 5" drillpipe singles f/ 8853' V 6948'. Hole taking 6-8 BPH. POOH f/ 6948't/ 279'. racking stands in Derrick for liner run. Pumped 18 bbl 9.4 ppg dry job at 2715'. 5-8 BPH losses. Hold PJSM for laying down BHA. 1/2/2020 Doyon 14 RIH with 4.5" injection UD jars, HWDP & drill collars to 87'. Read MWD tools, UD remainder of BHA f/ 87'. Bit graded 2 -2 -CT -A -X -1 -NO -TD. 37 bbis total loss on liner on 5" drillpipe @ trip out from shoe. Clear rig floor. Mobilize 4-1/2" casing equipment to the rig floor. R/U elevators, slips and Doyon casing double stack 11066' Aongs. Place safety joint in mousehole 2 BPH static loss rate. PJSM. M/U 4-1/2" shoe joint: Closed shoe, tubing joint wl 2 each 7.1" centralizers & run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 41'V 3039'. Torque to 9600 f 1lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 1.6 BPH avg. losses. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 3039' V 6801'. Torque to 9600 fVlbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. Fill pipe every 15 jts. 1.6 BPH avg. losses. PU/SO - 90k/70k. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 6801't/ 8737'. Torque to 9600 fVlbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. Fill pipe every 15 jts. 1.6 BPH avg. losses. PU/SO - 100k/75k. 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" Drillpipe to 8860', Obtain parameters: Pump 3 BPM - 800 psi, 1 BPM - 100 psi, 20 RPM - 5K TQ. P/U 103K S/O 76K ,ROT 85K. RIH w/ 4-1/2" injection liner on 5" DP stands f/ 8860't/ 11066'. Fill pipe on the fly and top off every 5 stands. P/U 125k, S/O 75k 4 BPH loss rate. 1/3/2020 Doyon 14 Swapped to RIH w/ 4-1/2" injection liner on 5" DP stands F/ 11066'T/ 14406'. Had one set down at 13920' and worked through with minimal effort. Set completions AFE I down hard at 14406'. Stand back stand and P/U working single of HWDP. Worked pipe with full set downs and no over pulls. Rot at 20 report RPM and free rot at 8K. Stall out at 1 OK on set downs. Took 1.5 hrs to get through then clean. RIH w/ 4-1/2" injection liner on 5" DP stands F/ 14406'T/ 17450. Tag on depth. Set liner in tension with LT at 8687.37 Fill pipe on the fly. P/U 200k, S/O 106k. Drop ball and pump down at 3 bpm 1000 psi for 80 bbl then slow to 2 bpm. Ball on seat at 1120 strokes. Pressure up and set hanger at 2850. Saw slight indication. Pressure up to 3300 psi & slack off. Hanger set. Set down 50K. Pressure up to 4050 psi & shear out. Pressure Dropped off. P/U 5' & UD single. Blow down TD. R/U to test backside. Test annulus to 1500 psi for 10 min. Good. Blow down lines and Prep for Trip out.;POOH f/ 8657't/ surface. UD 1 std 5" DP & std of 5" HWDP, racking remaining 5" DP & HWDP in Derrick. Inspect & UD running tool. 27 bbl loss on trip out of hole. Swap to completions report. Hilcorp Enerqv Companv Composite Report Well Name: MP M-19 Field: Milne Point County/State: North Slope Borough, Alaska Elevation (RKB): API #: 50-029-23655-00 Spud Date: 12/16/2019 Job Name: 1915812C MP M-19 Completion Contractor Activity Present Date Operations Ops Summary 1/3/2020 Displace to Please see drilling report for complete details. M/U 3-1/2" wash joint & 8.25" O.D. no-go to 15.72'. TIH w/ 69 stands of 5" drill pipe, 22 clean 9 ppg stands HWDP U 8684' 170K PU / 135K SO Wash down w/ 260 GPM, 400 PSI & tag liner top w/ no-go on depth w/ 5K. 6 bbls loss on trip in brine hole. Pump 30 bbl high vis sweep and circulate the 9-5/8" casing clean above the liner top w/ 520 GPM, 740 PSI, 40 RPM, 9K TQ. 75% increase of sand with sweep back. Continue circulating another bottom up until clean. PJSM for displacement. 2 bbls loss while circulate clean. Pump 30 bbl high vis spacer. Perform displacement to 9.0 ppg 2% KCI/NaCl brine. Spacer back on strokes & fluid cleaned up after 100 bbls of interface. 1/4/2020 Running 3- Finish displacing to clean 9.0 ppg 2% KCI/NaCl brine. Pumped a total of 727 bbls of brine. No losses observed. Perform 5 min. flow check - 1/2" tubing at static. Obtain new slow pump rates. Blow down TopDrive. POOH laying down 5" drill pipe & 5" HWDP f/ 8687't/ surface. UD NO-GO and 6249' wash tool. 21 bbl losses on TOOK Submit 24 hr notification to AOGCC for upcoming MIT. Drain Stack, pull wear bushing, M/U XO on 5" drill pipe landing joint, perform tubing hanger dummy run. Mobilize 3-1/2" completion equipment to the rig floor: casing tongs, Cannon clamps, TEC spool. R/U TEC spool & sheave, Doyon double stack tongs, slips & elevators. PJSM for running tubing. Review well control plan w/ TEC wire across BOPs. M/U Baker 7.38" ported bullet seal assy to 16'. Run 27 joints of 3.5" 9.3# EUE L-80 tubing to 864'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. M/U Baker gauge carrier assy to 885'. Install Zenith gauge (S/N P5538) w/ gauge retaining clamp & connect to TEC wire. Test gauge - good.,Run 3.5" 9.3# EUE L-80 tubing from 885't/ 2720'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. Install Cannon clamps on TEC wire first 5 connections, then every other joint. Also above & below XN nipple. Check Zenith gauge every 2000'. Run 3.5" 9.3# EUE L-80 tubing from 2720' t/ 6249'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. Install Cannon clamps on TEC wire first 10 connections, then every other joint. Also above & below X nipple. Check Zenith gauge every 2000'. 1.5 BPH loss rate. 1/5/2020 Rig up to test Run 3.5" 9.3# EUE L-80 tubing from 6249'. T/ 6942'. Torque to 3,100 ft/lbs w/ Doyon double stack tongs. Install Cannon clamps on TEC tree wire first 10 connections, then every other joint. Also above & below X nipple. Check Zenith gauge every 2000'. Skate buggy shut down. Troubleshoot and had to cut out bad line off the spool. Run 3.5" 9.3# EUE L-80 tubing F/ 6942' T/ 8610 . Space out with joitns 276 & 277. Saw good indication of seals and No go. UD three joints & Make up 4 pups under last joint ran. # 275. Pups, 6.07, 6.07, 6.09, & 4.07. M/U Landing Joint & M/U Hanger. Terminate Tec wire in hanger. Baker Make final check before Cutting. Land hanger & R/U Circ lines to reverce. UP/DN 80/65K. PJSM with all hands for the displacment. -40 Bellow outside. Notified AOGCC of upcoming diverter test on M-34 at 15:25 on 05 Jan 2020. Pressure up to 400 PSI & P/U on string until Ports open and pressure bleeds off. Circ 343 bbls at 6 bpm, 630 psi, down the annulus with 1 % Concor in 9.0 ppg Brine for corrosion inhibitor. Blow down lines and pumps. Found washout in manifold bleeder line under rig floor. Replace hardline section with 2" high pressure hose. Reverse circulate 195 bbls diesel from vac truck 6 bpm, 540 psi freeze protecting 9 5/8" x 3 1/2" annulus to 3050'. S/0 closing ports, drain stack to cellar, blow down pump, lines and stack. Attempt to land hanger. Insufficient S/0 weight to overcome differential pressure. Close bag and apply 350 psi to IA, slack off and land w/ 15k on hanger, EOP @ 8695.28'( 1.3' off NO GO ). Bleed off pressure and B/D lines. RILDS. R/U test equipment, pre -infection MIT 3 1/2" x 9 5/8 annulus with diesel to 2500 psi for 30 charted min. Good test. bleed off pressure and blow down lines. AOGCC representative Matthew Herrera waived witness for MIT on 01/04/20 @ 08:43. Disconnect test equipment, blow down lines, back out and UD landing jt, WH rep install BPV. Nipple down BOP stack and rack on moving stump. Set adapter flange and terminate tech wire, take final readings, ( tubing pressure 1578 psi, IA pressure 1400 psi, temp 69.0° in/out ) N/U adapter flange and tree. Test hanger void to 500 PSI low for 5 min & 5000 PSI high for 10 min. 1/6/2020 RDMO, Move Pull BPV and install TWC, R/U test equipment. Test tree with diesel to 250/5000 PSI 5 min. Pull TWC and install BPV. R/D test equipment. rig to M-34 R/U to freeze protect 3-1/2" tubing. Bullhead 38 bbls diesel down the tubing through BPV @ 2 BPM, 390 PSI ICP, 1200 PSI FCP. Freeze protect to 4368' MD. Warm front wheel wells with heaters in preparation for move. Clean and prep rig for move. Prep for rig move. Wait on peak trucks from dead horse to move rock washer and bulk tank. Milne point winch trucks broke down in -40°F and shut down. Release rig f/ M-19 @ 12:00. RDMO. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M -19i 500292365500 Sperry Grilling Definitive Survey Report 31 December, 2019 Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -19i Project: Milne Point TVD Reference: MPU M-19 Actual RKB @ 59.46usft Site: M Pt Moose Pad MD Reference: MPU M-19 Actual RKB @ 59.46usft Well: MPU M -19i North Reference: True Wellbore: MPU M -19i Survey Calculation Method: Minimum Curvature Design: MPU M -19i Database: NORTH US + CANADA 'roject Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level 'eo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M -19i Well Position +N/ -S +E/ -W Position Uncertainty Wellbore MPU M -19i 0.00 usft Northing: 6,027,765.55 usf Latitude: 70° 29' 12.796 N 0.00 usft Easting: 533,513.82 usf Longitude: 149° 43' 33.890 W 0.50 usft Wellhead Elevation: usf Ground Level: 25.10 usft Magnetics Model Name Sample Date Design Audit Notes: Version: Vertical Section: BGGM2019 MPU M -19i 1.0 12/30/2019 Declination Dip Angle Field Strength (°) (°) (nT) 16.19 80.90 57,403.99555685 Phase: ACTUAL Tie On Depth Depth From (TVD) +N/ -S +E/ -W (usft) (usft) (usft) 34.36 0.00 0.00 13,917.35 Direction (1) 124.50 Survey Program Date 12/31/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 220.94 8,873.82 MPU M-19PB1 MWD+IFR2+MS+Sag (1) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 12/11/2019 8,968.99 13,917.35 MPU M-19PI31 MWD+IFR2+MS+Sag (2) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 12/27/2019 13,960.00 17,375.92 MPU M-19 MWD+IFR2+MS+Sag (3) (MF 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 12/30/2019 Survey MD Inc Azi TVD TVDSS +N/ -S (usft) (°) (1 (usft) (usft) (usft) 34.36 0.00 0.00 34.36 -25.10 0.00 220.94 0.74 163.83 220.93 161.47 -1.16 314.21 3.55 170.24 314.13 254.67 -4.58 407.53 6.32 171.15 407.10 347.64 -12.51 500.32 8.81 167.91 499.07 439.61 -24.50 592.62 11.44 164.67 589.93 530.47 -40.24 686.17 14.31 167.64 681.12 621.66 -60.49 781.61 17.52 169.95 772.89 713.43 -86.16 876.70 21.38 167.65 862.53 803.07 -117.20 971.69 25.48 168.39 949.67 890.21 -154.14 1,066.56 30.30 168.27 1,033.50 974.04 -197.59 1,162.26 36.25 168.47 1,113.47 1,054.01 -249.00 12/31/2019 1:44:18PM Page 2 COMPASS 5000.15 Build 91E Map Map Vertical +E/ -W Northing Easting DLS Section (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.00 6,027,765.55 533,513.82 0.00 0.00 UNDEFINED 0.34 6,027,764.39 533,514.16 0.40 0.93 3_MWD+IFR2+MS+Sag (1) 0.99 6,027,760.97 533,514.83 3.02 3.41 3_MWD+IFR2+MS+Sag (1) 2.27 6,027,753.06 533,516.15 2.97 8.96 3_MWD+IFR2+MS+Sag (1) 4.55 6,027,741.07 533,518.48 2.72 17.63 3_MWD+IFR2+MS+Sag (1) 8.45 6,027,725.35 533,522.45 2.91 29.76 3_MWD+IFR2+MS+Sag (1) 13.38 6,027,705.13 533,527.47 3.15 45.29 3_MWD+IFR2+MS+Sag (1) 18.41 6,027,679.48 533,532.62 3.43 63.98 3_MWD+IFR2+MS+Sag (1) 24.62 6,027,648.47 533,538.96 4.14 86.67 3_MWD+IFR2+MS+Sag (1) 32.44 6,027,611.57 533,546.95 4.33 114.04 3_MWD+IFR2+MS+Sag (1) 41.41 6,027,568.17 533,556.12 5.08 146.05 3_MWD+IFR2+MS+Sag (1) 51.99 6,027,516.81 533,566.92 6.22 183.88 3_MWD+IFR2+MS+Sag (1) 12/31/2019 1:44:18PM Page 2 COMPASS 5000.15 Build 91E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M -19i MPU M -19i MPU M -19i Local Co-ordinate Reference: Well MPU M -19i TVD Reference: MPU M-19 Actual RK13 @ 59.46usft MD Reference: MPU M-19 Actual RKB @ 59.46usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,256.94 41.46 168.10 1,187.18 1,127.72 -307.14 64.05 6,027,458.74 533,579.25 5.51 226.75 3_MWD+IFR2+MS+Sag (1) 1,352.91 43.87 168.71 1,257.74 1,198.28 -370.85 77.12 6,027,395.09 533,592.60 2.55 273.60 3_MWD+IFR2+MS+Sag (1) 1,448.55 45.69 167.34 1,325.63 1,266.17 -436.74 91.11 6,027,329.27 533,606.88 2.15 322.45 3_MWD+IFR2+MS+Sag (1) 1,543.64 52.07 167.44 1,388.13 1,328.67 -506.61 106.73 6,027,259.48 533,622.82 6.71 374.91 3_MWD+IFR2+MS+Sag (1) 1,638.77 55.10 166.90 1,444.60 1,385.14 -581.24 123.74 6,027,184.93 533,640.16 3.22 431.19 3_MWD+IFR2+MS+Sag (1) 1,733.44 59.51 165.45 1,495.72 1,436.26 -658.58 142.79 6,027,107.69 533,659.57 4.83 490.70 3_MWD+IFR2+MS+Sag(1) 1,828.76 62.28 166.21 1,542.08 1,482.62 -739.32 163.17 6,027,027.05 533,680.31 2.99 553.23 3_MWD+IFR2+MS+Sag (1) 1,924.01 62.60 167.17 1,586.16 1,526.70 -821.49 182.61 6,026,944.97 533,700.11 0.95 615.79 3_MWD+IFR2+MS+Sag (1) 2,019.59 65.22 166.43 1,628.19 1,568.73 -905.05 202.22 6,026,861.51 533,720.09 2.83 679.28 3_MWD+IFR2+MS+Sag (1) 2,115.42 68.07 166.31 1,666.17 1,606.71 -990.55 222.95 6,026,776.12 533,741.21 2.98 744.79 3_MWD+IFR2+MS+Sag (1) 2,212.65 71.09 167.07 1,700.09 1,640.63 -1,079.21 243.92 6,026,687.56 533,762.57 3.19 812.29 3_MWD+IFR2+MS+Sag (1) 2,308.56 71.28 167.63 1,731.02 1,671.56 -1,167.79 263.80 6,026,599.08 533,782.85 0.59 878.85 3_MWD+IFR2+MS+Sag (1) 2,404.20 70.14 168.29 1,762.62 1,703.16 -1,256.07 282.63 6,026,510.89 533,802.08 1.36 944.37 3_MWD+IFR2+MS+Sag (1) 2,499.78 69.51 167.91 1,795.58 1,736.12 -1,343.86 301.13 6,026,423.19 533,820.97 0.76 1,009.34 3_MWD+IFR2+MS+Sag (1) 2,596.19 71.42 167.18 1,827.82 1,768.36 -1,432.58 320.73 6,026,334.58 533,840.97 2.11 1,075.74 3_MWD+IFR2+MS+Sag (1) 2,691.55 70.41 168.17 1,859.00 1,799.54 -1,520.61 339.97 6,026,246.63 533,860.60 1.44 1,141.46 3_MWD+IFR2+MS+Sag (1) 2,786.65 70.36 168.21 1,890.93 1,831.47 -1,608.30 358.30 6,026,159.04 533,879.33 0.07 1,206.24 3_MWD+IFR2+MS+Sag (1) 2,882.11 72.19 168.57 1,921.57 1,862.11 -1,696.85 376.49 6,026,070.58 533,897.92 1.95 1,271.39 3_MWD+IFR2+MS+Sag (1) 2,976.86 71.86 169.19 1,950.81 1,891.35 -1,785.29 393.87 6,025,982.23 533,915.70 0.71 1,335.80 3_MWD+IFR2+MS+Sag (1) 3,072.21 71.53 169.02 1,980.76 1,921.30 -1,874.18 410.98 6,025,893.43 533,933.20 0.39 1,400.25 3_MWD+IFR2+MS+Sag (1) 3,167.10 74.00 168.03 2,008.87 1,949.41 -1,962.99 429.02 6,025,804.71 533,951.64 2.79 1,465.41 3_MWD+IFR2+MS+Sag (1) 3,262.22 73.93 169.02 2,035.15 1,975.69 -2,052.58 447.20 6,025,715.21 533,970.22 1.00 1,531.15 3_MWD+IFR2+MS+Sag (1) 3,356.73 73.42 168.85 2,061.71 2,002.25 -2,141.59 464.61 6,025,626.29 533,988.03 0.57 1,595.91 3_MWD+IFR2+MS+Sag (1) 3,451.35 73.48 165.97 2,088.67 2,029.21 -2,230.10 484.38 6,025,537.88 534,008.20 2.92 1,662.33 3_MWD+IFR2+MS+Sag (1) 3,547.11 72.12 165.09 2,116.99 2,057.53 -2,318.67 507.23 6,025,449.42 534,031.45 1.67 1,731.34 3_MWD+IFR2+MS+Sag (1) 3,642.36 72.70 165.34 2,145.77 2,086.31 -2,406.46 530.40 6,025,361.74 534,055.01 0.66 1,800.16 3_MWD+IFR2+MS+Sag (1) 3,737.12 72.05 165.38 2,174.46 2,115.00 -2,493.84 553.23 6,025,274.47 534,078.23 0.69 1,868.46 3_MWD+IFR2+MS+Sag (1) 3,832.24 67.92 165.98 2,207.01 2,147.55 -2,580.42 575.34 6,025,188.00 534,100.72 4.38 1,935.72 3_MWD+IFR2+MS+Sag (1) 3,927.73 67.98 166.78 2,242.86 2,183.40 -2,666.43 596.18 6,025,102.09 534,121.95 0.78 2,001.61 3_MWD+IFR2+MS+Sag (1) 4,022.79 69.62 168.98 2,277.24 2,217.78 -2,753.08 614.78 6,025,015.54 534,140.93 2.76 2,066.01 3_MWD+IFR2+MS+Sag (1) 4,117.80 70.29 168.87 2,309.80 2,250.34 -2,840.67 631.92 6,024,928.04 534,158.47 0.71 2,129.76 3_MWD+IFR2+MS+Sag (1) 4,212.70 69.30 169.18 2,342.58 2,283.12 -2,928.10 648.88 6,024,840.69 534,175.82 1.09 2,193.25 3_MWD+IFR2+MS+Sag (1) 4,308.22 71.60 168.97 2,374.54 2,315.08 -3,016.48 665.94 6,024,752.40 534,193.28 2.42 2,257.37 3_MWD+IFR2+MS+Sag (1) 4,403.45 72.12 167.67 2,404.19 2,344.73 -3,105.10 684.26 6,024,663.88 534,211.99 1.41 2,322.66 3_MWD+IFR2+MS+Sag (1) 4,496.76 71.20 168.33 2,433.55 2,374.09 -3,191.73 702.67 6,024,577.33 534,230.80 1.19 2,386.91 3_MWD+IFR2+MS+Sag (1) 4,593.91 72.58 165.45 2,463.76 2,404.30 -3,281.64 723.62 6,024,487.52 534,252.15 3.16 2,455.10 3_MWD+IFR2+MS+Sag (1) 4,688.09 71.98 165.49 2,492.42 2,432.96 -3,368.49 746.13 6,024,400.79 534,275.05 0.64 2,522.84 3_MWD+IFR2+MS+Sag (1) 4,783.08 72.45 166.08 2,521.44 2,461.98 -3,456.17 768.34 6,024,313.22 534,297.65 0.77 2,590.80 3_MWD+IFR2+MS+Sag (1) 4,880.39 72.89 166.35 2,550.42 2,490.96 -3,546.38 790.48 6,024,223.11 534,320.19 0.52 2,660.14 3_MWD+IFR2+MS+Sag (1) 4,976.70 72.95 165.87 2,578.71 2,519.25 -3,635.75 812.58 6,024,133.85 534,342.69 0.48 2,728.98 3_MWD+IFR2+MS+Sag (1) 12/312019 1:44:18PM Page 3 COMPASS 5000.15 Build 91E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -19i Wellbore: MPU M -19i Design: MPU M -19i Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M -19i MPU M-19 Actual RKB @ 59.46usft MPU M-19 Actual RKB @ 59.46usft True Minimum Curvature NORTH US + CANADA Vertical Section (ft) Survey Tool Name 2,796.50 3_MWD+IFR2+MS+Sag (1) 2,864.71 3_MWD+IFR2+MS+Sag (1) 2,932.35 3_MWD+IFR2+MS+Sag (1) 2,999.12 3_MWD+IFR2+MS+Sag (1) 3,065.14 3_MWD+IFR2+MS+Sag (1) 3,129.89 3_MWD+IFR2+MS+Sag (1) 3,194.91 3_MWD+IFR2+MS+Sag (1) 3,259.60 3_MWD+IFR2+MS+Sag (1) 3,323.98 3_MWD+IFR2+MS+Sag (1) 3,387.94 3_MWD+IFR2+MS+Sag (1) 3,453.26 3_MWD+IFR2+MS+Sag (1) 3,518.24 3_MWD+IFR2+MS+Sag (1) 3,584.35 3_MWD+IFR2+MS+Sag (1) 3,651.17 3_MWD+IFR2+MS+Sag (1) 3,717.56 3_MWD+IFR2+MS+Sag (1) 3,784.72 3_MWD+IFR2+MS+Sag (1) 3,851.59 3_MWD+IFR2+MS+Sag (1) 3,918.03 3_MWD+IFR2+MS+Sag (1) 3,983.84 3_MWD+IFR2+MS+Sag (1) 4,050.31 3_MWD+IFR2+MS+Sag (1) 4,116.50 3_MWD+IFR2+MS+Sag (1) 4,182.47 3_MWD+IFR2+MS+Sag (1) 4,247.89 3_MWD+IFR2+MS+Sag (1) 4,312.96 3_MWD+IFR2+MS+Sag (1) 4,376.95 3_MWD+IFR2+MS+Sag (1) 4,442.48 3_MWD+IFR2+MS+Sag (1) 4,508.11 3_MWD+IFR2+MS+Sag (1) 4,578.34 3_MWD+IFR2+MS+Sag (1) 4,651.84 3_MWD+IFR2+MS+Sag (1) 4,731.73 3_MWD+IFR2+MS+Sag (1) 4,812.14 3_MWD+IFR2+MS+Sag (1) 4,897.67 3_MWD+IFR2+MS+Sag (1) 4,984.43 3_MWD+IFR2+MS+Sag (1) 5,072.75 3_MWD+IFR2+MS+Sag (1) 5,161.21 3_MWD+IFR2+MS+Sag (1) 5,250.41 3_MWD+IFR2+MS+Sag (1) 5,342.26 3_MWD+IFR2+MS+Sag (1) 5,435.55 3_MWD+IFR2+MS+Sag (1) 5,529.40 3_MWD+IFR2+MS+Sag (1) 5,624.45 3_MWD+IFR2+MS+Sag (1) COMPASS 5000.15 Build 91E Map Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') 5,071.21 72.06 166.11 2,607.12 2,547.66 -3,723.21 834.40 6,024,046.51 534,364.90 0.97 5,167.03 70.28 165.33 2,638.05 2,578.59 -3,811.09 856.76 6,023,958.73 534,387.66 2.01 5,262.07 71.35 165.87 2,669.28 2,609.82 -3,898.04 879.08 6,023,871.90 534,410.37 1.25 5,357.36 70.49 167.41 2,700.43 2,640.97 -3,985.65 899.90 6,023,784.39 534,431.58 1.77 5,453.13 71.01 167.80 2,732.00 2,672.54 -4,073.96 919.30 6,023,696.18 534,451.38 0.67 5,547.40 70.82 167.95 2,762.83 2,703.37 -4,161.06 938.01 6,023,609.17 534,470.48 0.25 5,642.68 69.90 168.19 2,794.85 2,735.39 -4,248.85 956.57 6,023,521.47 534,489.43 0.99 5,737.91 70.80 168.47 2,826.87 2,767.41 -4,336.68 974.71 6,023,433.73 534,507.96 0.98 5,832.92 71.01 168.91 2,857.96 2,798.50 -4,424.72 992.31 6,023,345.78 534,525.96 0.49 5,927.27 71.60 168.69 2,888.20 2,828.74 -4,512.39 1,009.67 6,023,258.20 534,543.71 0.66 6,023.49 72.24 169.17 2,918.06 2,858.60 -4,602.16 1,027.23 6,023,168.52 534,561.68 0.82 6,118.53 71.92 167.95 2,947.30 2,887.84 -4,690.79 1,045.17 6,023,079.98 534,580.01 1.27 6,213.64 73.99 167.78 2,975.18 2,915.72 -4,779.68 1,064.28 6,022,991.18 534,599.52 2.18 6,308.90 72.58 167.03 3,002.58 2,943.12 -4,868.72 1,084.18 6,022,902.24 534,619.82 1.66 6,403.08 73.36 166.97 3,030.16 2,970.70 -4,956.46 1,104.43 6,022,814.60 534,640.47 0.83 6,498.52 71.26 166.81 3,059.16 2,999.70 -5,045.02 1,125.05 6,022,726.15 534,661.48 2.21 6,594.07 71.20 166.86 3,089.90 3,030.44 -5,133.11 1,145.66 6,022,638.17 534,682.48 0.08 6,689.56 71.15 167.51 3,120.72 3,061.26 -5,221.24 1,165.71 6,022,550.13 534,702.93 0.65 6,784.42 72.75 167.77 3,150.11 3,090.65 -5,309.33 1,185.01 6,022,462.13 534,722.62 1.71 6,880.05 71.65 167.45 3,179.34 3,119.88 -5,398.26 1,204.55 6,022,373.30 534,742.56 1.19 6,975.47 69.82 166.96 3,210.82 3,151.36 -5,486.10 1,224.49 6,022,285.56 534,762.90 1.98 7,070.96 70.02 167.33 3,243.61 3,184.15 -5,573.54 1,244.45 6,022,198.23 534,783.24 0.42 7,166.00 69.35 167.21 3,276.60 3,217.14 -5,660.48 1,264.09 6,022,111.39 534,803.27 0.71 7,261.30 68.44 167.71 3,310.92 3,251.46 -5,747.26 1,283.39 6,022,024.70 534,822.97 1.07 7,355.97 69.05 168.31 3,345.24 3,285.78 -5,833.57 1,301.72 6,021,938.49 534,841.68 0.87 7,452.82 70.76 168.50 3,378.51 3,319.05 -5,922.66 1,320.00 6,021,849.48 534,860.36 1.78 7,546.89 74.00 166.37 3,406.99 3,347.53 -6,010.15 1,339.51 6,021,762.09 534,880.27 4.06 7,641.97 74.63 162.41 3,432.70 3,373.24 -6,098.29 1,364.14 6,021,674.07 534,905.29 4.06 7,735.95 74.00 157.87 3,458.12 3,398.66 -6,183.37 1,394.87 6,021,589.14 534,936.40 4.70 7,833.20 73.80 153.56 3,485.10 3,425.64 -6,268.51 1,433.28 6,021,504.18 534,975.19 4.26 7,926.89 77.06 150.47 3,508.67 3,449.21 -6,348.55 1,475.84 6,021,424.34 535,018.10 4.72 8,023.03 75.65 145.87 3,531.36 3,471.90 -6,427.91 1,525.08 6,021,345.21 535,067.70 4.88 8,117.82 74.57 140.41 3,555.74 3,496.28 -6,501.18 1,580.00 6,021,272.20 535,122.94 5.68 8,212.85 72.11 136.53 3,582.99 3,523.53 -6,569.33 1,640.33 6,021,204.33 535,183.57 4.69 8,308.10 70.89 135.77 3,613.21 3,553.75 -6,634.47 1,702.90 6,021,139.48 535,246.43 1.49 8,403.25 73.55 133.35 3,642.27 3,582.81 -6,698.02 1,767.46 6,021,076.22 535,311.27 3.70 8,498.95 77.50 130.62 3,666.19 3,606.73 -6,759.97 1,836.33 6,021,014.59 535,380.41 4.97 8,594.18 82.08 129.06 3,683.07 3,623.61 -6,819.99 1,908.28 6,020,954.90 535,452.62 5.07 8,688.83 84.75 126.66 3,693.92 3,634.46 -6,877.68 1,982.50 6,020,897.55 535,527.10 3.78 8,784.23 85.80 122.60 3,701.78 3,642.32 -6,931.70 2,060.72 6,020,843.89 535,605.55 4.38 12/31/2019 1:44:18PM Page 4 Vertical Section (ft) Survey Tool Name 2,796.50 3_MWD+IFR2+MS+Sag (1) 2,864.71 3_MWD+IFR2+MS+Sag (1) 2,932.35 3_MWD+IFR2+MS+Sag (1) 2,999.12 3_MWD+IFR2+MS+Sag (1) 3,065.14 3_MWD+IFR2+MS+Sag (1) 3,129.89 3_MWD+IFR2+MS+Sag (1) 3,194.91 3_MWD+IFR2+MS+Sag (1) 3,259.60 3_MWD+IFR2+MS+Sag (1) 3,323.98 3_MWD+IFR2+MS+Sag (1) 3,387.94 3_MWD+IFR2+MS+Sag (1) 3,453.26 3_MWD+IFR2+MS+Sag (1) 3,518.24 3_MWD+IFR2+MS+Sag (1) 3,584.35 3_MWD+IFR2+MS+Sag (1) 3,651.17 3_MWD+IFR2+MS+Sag (1) 3,717.56 3_MWD+IFR2+MS+Sag (1) 3,784.72 3_MWD+IFR2+MS+Sag (1) 3,851.59 3_MWD+IFR2+MS+Sag (1) 3,918.03 3_MWD+IFR2+MS+Sag (1) 3,983.84 3_MWD+IFR2+MS+Sag (1) 4,050.31 3_MWD+IFR2+MS+Sag (1) 4,116.50 3_MWD+IFR2+MS+Sag (1) 4,182.47 3_MWD+IFR2+MS+Sag (1) 4,247.89 3_MWD+IFR2+MS+Sag (1) 4,312.96 3_MWD+IFR2+MS+Sag (1) 4,376.95 3_MWD+IFR2+MS+Sag (1) 4,442.48 3_MWD+IFR2+MS+Sag (1) 4,508.11 3_MWD+IFR2+MS+Sag (1) 4,578.34 3_MWD+IFR2+MS+Sag (1) 4,651.84 3_MWD+IFR2+MS+Sag (1) 4,731.73 3_MWD+IFR2+MS+Sag (1) 4,812.14 3_MWD+IFR2+MS+Sag (1) 4,897.67 3_MWD+IFR2+MS+Sag (1) 4,984.43 3_MWD+IFR2+MS+Sag (1) 5,072.75 3_MWD+IFR2+MS+Sag (1) 5,161.21 3_MWD+IFR2+MS+Sag (1) 5,250.41 3_MWD+IFR2+MS+Sag (1) 5,342.26 3_MWD+IFR2+MS+Sag (1) 5,435.55 3_MWD+IFR2+MS+Sag (1) 5,529.40 3_MWD+IFR2+MS+Sag (1) 5,624.45 3_MWD+IFR2+MS+Sag (1) COMPASS 5000.15 Build 91E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -19i Wellbore: MPU M -19i Design: MPU M -19i Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M -19i MPU M-19 Actual RKB @ 59.46usft MPU M-19 Actual RKB @ 59.46usft True Minimum Curvature NORTH US + CANADA Vertical Section (ft) Survey Tool Name 5,713.91 3_MWD+IFR2+MS+Sag (1) 5,809.05 3_MWD+IFR2+MS+Sag (2) 5,901.92 3_MWD+IFR2+MS+Sag (2) 5,999.11 3_MWD+IFR2+MS+Sag (2) 6,093.36 3_MWD+IFR2+MS+Sag (2) 6,190.39 3_MWD+IFR2+MS+Sag (2) 6,284.96 3_MWD+IFR2+MS+Sag (2) 6,380.51 3_MWD+IFR2+MS+Sag (2) 6,475.90 3_MWD+IFR2+MS+Sag (2) 6,570.37 3_MWD+IFR2+MS+Sag (2) 6,665.78 3_MWD+IFR2+MS+Sag (2) 6,760.63 3_MWD+IFR2+MS+Sag (2) 6,854.16 3_MWD+IFR2+MS+Sag (2) 6,950.83 3_MWD+IFR2+MS+Sag (2) 7,046.35 3_MWD+IFR2+MS+Sag (2) 7,140.93 3_MWD+IFR2+MS+Sag (2) 7,235.99 3_MWD+IFR2+MS+Sag (2) 7,330.87 3_MWD+IFR2+MS+Sag (2) 7,425.66 3_MWD+IFR2+MS+Sag (2) 7,521.07 3_MWD+IFR2+MS+Sag (2) 7,615.41 3_MWD+IFR2+MS+Sag (2) 7,710.78 3_MWD+IFR2+MS+Sag (2) 7,805.96 3_MWD+IFR2+MS+Sag (2) 7,900.49 3_MWD+IFR2+MS+Sag (2) 7,995.86 3_MWD+IFR2+MS+Sag (2) 8,090.89 3_MWD+IFR2+MS+Sag (2) 8,186.03 3_MWD+IFR2+MS+Sag (2) 8,280.30 3_MWD+IFR2+MS+Sag (2) 8,376.02 3_MWD+IFR2+MS+Sag (2) 8,472.08 3_MWD+IFR2+MS+Sag (2) 8,563.73 3_MWD+IFR2+MS+Sag (2) 8,661.64 3_MWD+IFR2+MS+Sag (2) 8,757.47 3_MWD+IFR2+MS+Sag (2) 8,852.98 3_MWD+IFR2+MS+Sag (2) 8,947.29 3_MWD+IFR2+MS+Sag (2) 9,041.01 3_MWD+IFR2+MS+Sag (2) 9,135.18 3_MWD+IFR2+MS+Sag (2) 9,230.66 3_MWD+IFR2+MS+Sag (2) 9,327.32 3_MWD+IFR2+MS+Sag (2) 9,421.35 3_MWD+IFR2+MS+Sag (2) 12/312019 1:44:18PM Page 5 COMPASS 5000.15 Build 91E Map Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') 8,873.82 88.52 124.75 3,706.22 3,646.76 -6,981.31 2,135.17 6,020,794.63 535,680.22 3.87 8,968.99 91.31 122.46 3,706.36 3,646.90 -7,033.97 2,214.42 6,020,742.32 535,759.70 3.79 9,061.89 90.31 124.36 3,705.05 3,645.59 -7,085.12 2,291.96 6,020,691.53 535,837.45 2.31 9,159.08 89.76 124.86 3,704.99 3,645.53 -7,140.32 2,371.95 6,020,636.70 535,917.68 0.76 9,253.34 89.14 124.42 3,705.90 3,646.44 -7,193.89 2,449.50 6,020,583.48 535,995.46 0.81 9,350.38 88.83 124.76 3,707.61 3,648.15 -7,248.97 2,529.37 6,020,528.76 536,075.58 0.47 9,445.00 87.78 124.12 3,710.41 3,650.95 -7,302.46 2,607.37 6,020,475.63 536,153.81 1.30 9,540.59 89.77 122.96 3,712.46 3,653.00 -7,355.26 2,687.02 6,020,423.20 536,233.69 2.41 9,636.03 89.14 122.57 3,713.36 3,653.90 -7,406.91 2,767.27 6,020,371.91 536,314.17 0.78 9,730.54 89.95 123.07 3,714.11 3,654.65 -7,458.13 2,846.69 6,020,321.06 536,393.81 1.01 9,825.98 89.20 123.42 3,714.82 3,655.36 -7,510.45 2,926.51 6,020,269.10 536,473.85 0.87 9,920.87 90.01 122.61 3,715.48 3,656.02 -7,562.15 3,006.07 6,020,217.77 536,553.64 1.21 10,014.43 91.06 123.42 3,714.60 3,655.14 -7,613.13 3,084.52 6,020,167.15 536,632.31 1.42 10,111.14 88.89 122.78 3,714.65 3,655.19 -7,665.94 3,165.53 6,020,114.71 536,713.55 2.34 10,206.75 87.47 123.02 3,717.68 3,658.22 -7,717.84 3,245.77 6,020,063.17 536,794.01 1.51 10,301.41 88.10 124.68 3,721.34 3,661.88 -7,770.53 3,324.32 6,020,010.85 536,872.79 1.87 10,396.58 86.92 126.62 3,725.48 3,666.02 -7,825.94 3,401.58 6,019,955.79 536,950.29 2.38 10,491.65 88.10 127.50 3,729.61 3,670.15 -7,883.18 3,477.37 6,019,898.90 537,026.33 1.55 10,586.62 86.92 126.48 3,733.73 3,674.27 -7,940.26 3,553.15 6,019,842.16 537,102.36 1.64 10,682.18 87.29 125.26 3,738.56 3,679.10 -7,996.18 3,630.49 6,019,786.59 537,179.94 1.33 10,776.64 87.04 125.08 3,743.23 3,683.77 -8,050.53 3,707.61 6,019,732.61 537,257.30 0.33 10,872.12 87.97 125.63 3,747.39 3,687.93 -8,105.72 3,785.40 6,019,677.77 537,335.34 1.13 10,967.38 89.39 127.30 3,749.58 3,690.12 -8,162.32 3,861.99 6,019,621.52 537,412.17 2.30 11,061.99 88.83 125.96 3,751.05 3,691.59 -8,218.76 3,937.90 6,019,565.43 537,488.33 1.53 11,157.39 90.51 125.32 3,751.60 3,692.14 -8,274.35 4,015.43 6,019,510.20 537,566.10 1.88 11,252.43 90.32 125.41 3,750.91 3,691.45 -8,329.35 4,092.93 6,019,455.55 537,643.84 0.22 11,347.58 89.20 123.68 3,751.31 3,691.85 -8,383.30 4,171.30 6,019,401.95 537,722.44 2.17 11,441.87 89.64 122.96 3,752.27 3,692.81 -8,435.10 4,250.09 6,019,350.52 537,801.45 0.89 11,537.61 89.39 123.89 3,753.08 3,693.62 -8,487.83 4,329.99 6,019,298.15 537,881.58 1.01 11,633.68 89.76 125.65 3,753.79 3,694.33 -8,542.61 4,408.90 6,019,243.73 537,960.73 1.87 11,725.38 90.01 126.97 3,753.97 3,694.51 -8,596.91 4,482.79 6,019,189.77 538,034.86 1.47 11,823.38 89.95 126.85 3,754.01 3,694.55 -8,655.77 4,561.15 6,019,131.28 538,113.47 0.14 11,919.27 87.53 124.65 3,756.12 3,696.66 -8,711.77 4,638.94 6,019,075.63 538,191.51 3.41 12,014.95 86.42 121.64 3,761.17 3,701.71 -8,764.01 4,718.93 6,019,023.76 538,271.73 3.35 12,109.64 87.97 118.97 3,765.80 3,706.34 -8,811.72 4,800.57 6,018,976.42 538,353.57 3.26 12,203.76 89.70 119.69 3,767.71 3,708.25 -8,857.82 4,882.61 6,018,930.70 538,435.81 1.99 12,298.27 90.50 119.70 3,767.55 3,708.09 -8,904.63 4,964.71 6,018,884.26 538,518.11 0.85 12,394.00 90.32 121.09 3,766.86 3,707.40 -8,953.07 5,047.27 6,018,836.20 538,600.89 1.46 12,490.77 91.43 122.65 3,765.39 3,705.93 -9,004.15 5,129.44 6,018,785.49 538,683.28 1.98 12,584.97 90.56 120.01 3,763.75 3,704.29 -9,053.12 5,209.89 6,018,736.89 538,763.93 2.95 Vertical Section (ft) Survey Tool Name 5,713.91 3_MWD+IFR2+MS+Sag (1) 5,809.05 3_MWD+IFR2+MS+Sag (2) 5,901.92 3_MWD+IFR2+MS+Sag (2) 5,999.11 3_MWD+IFR2+MS+Sag (2) 6,093.36 3_MWD+IFR2+MS+Sag (2) 6,190.39 3_MWD+IFR2+MS+Sag (2) 6,284.96 3_MWD+IFR2+MS+Sag (2) 6,380.51 3_MWD+IFR2+MS+Sag (2) 6,475.90 3_MWD+IFR2+MS+Sag (2) 6,570.37 3_MWD+IFR2+MS+Sag (2) 6,665.78 3_MWD+IFR2+MS+Sag (2) 6,760.63 3_MWD+IFR2+MS+Sag (2) 6,854.16 3_MWD+IFR2+MS+Sag (2) 6,950.83 3_MWD+IFR2+MS+Sag (2) 7,046.35 3_MWD+IFR2+MS+Sag (2) 7,140.93 3_MWD+IFR2+MS+Sag (2) 7,235.99 3_MWD+IFR2+MS+Sag (2) 7,330.87 3_MWD+IFR2+MS+Sag (2) 7,425.66 3_MWD+IFR2+MS+Sag (2) 7,521.07 3_MWD+IFR2+MS+Sag (2) 7,615.41 3_MWD+IFR2+MS+Sag (2) 7,710.78 3_MWD+IFR2+MS+Sag (2) 7,805.96 3_MWD+IFR2+MS+Sag (2) 7,900.49 3_MWD+IFR2+MS+Sag (2) 7,995.86 3_MWD+IFR2+MS+Sag (2) 8,090.89 3_MWD+IFR2+MS+Sag (2) 8,186.03 3_MWD+IFR2+MS+Sag (2) 8,280.30 3_MWD+IFR2+MS+Sag (2) 8,376.02 3_MWD+IFR2+MS+Sag (2) 8,472.08 3_MWD+IFR2+MS+Sag (2) 8,563.73 3_MWD+IFR2+MS+Sag (2) 8,661.64 3_MWD+IFR2+MS+Sag (2) 8,757.47 3_MWD+IFR2+MS+Sag (2) 8,852.98 3_MWD+IFR2+MS+Sag (2) 8,947.29 3_MWD+IFR2+MS+Sag (2) 9,041.01 3_MWD+IFR2+MS+Sag (2) 9,135.18 3_MWD+IFR2+MS+Sag (2) 9,230.66 3_MWD+IFR2+MS+Sag (2) 9,327.32 3_MWD+IFR2+MS+Sag (2) 9,421.35 3_MWD+IFR2+MS+Sag (2) 12/312019 1:44:18PM Page 5 COMPASS 5000.15 Build 91E Company Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M -19i MPU M -19i MPU M-191 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M -19i MPU M-19 Actual RKB @ 59.46usft MPU M-19 Actual RKB @ 59.46usft True Minimum Curvature NORTH US + CANADA 12/312019 1:44:18PM Page 6 COMPASS 5000.15 Build 91 E 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 12,677.97 92.54 118.91 3,761.23 3,701.77 -9,098.84 5,290.83 6,018,691.54 538,845.07 2.44 9,513.95 3_MWD+IFR2+MS+Sag (2) 12,774.14 92.41 120.67 3,757.08 3,697.62 -9,146.57 5,374.21 6,018,644.19 538,928.65 1.83 9,609.70 3_MWD+IFR2+MS+Sag (2) 12,871.17 89.94 122.45 3,755.09 3,695.63 -9,197.34 5,456.86 6,018,593.80 539,011.53 3.14 9,706.57 3_MWD+IFR2+MS+Sag (2) 12,966.26 90.75 126.68 3,754.52 3,695.06 -9,251.28 5,535.14 6,018,540.22 539,090.05 4.53 9,801.64 3_MWD+IFR2+MS+Sag (2) 13,061.29 91.37 127.47 3,752.76 3,693.30 -9,308.56 5,610.95 6,018,483.29 539,166.10 1.06 9,896.55 3_MWD+IFR2+MS+Sag (2) 13,155.59 92.29 127.41 3,749.75 3,690.29 -9,365.85 5,685.78 6,018,426.34 539,241.18 0.98 9,990.68 3_MWD+IFR2+MS+Sag (2) 13,251.55 92.66 127.56 3,745.61 3,686.15 -9,424.20 5,761.86 6,018,368.34 539,317.51 0.42 10,086.42 3_MWD+IFR2+MS+Sag (2) 13,346.85 90.31 125.90 3,743.14 3,683.68 -9,481.16 5,838.20 6,018,311.72 539,394.11 3.02 10,181.61 3_MWD+IFR2+MS+Sag (2) 13,438.57 90.87 123.31 3,742.19 3,682.73 -9,533.25 5,913.69 6,018,259.99 539,469.82 2.89 10,273.31 3_MWD+IFR2+MS+Sag (2) 13,536.10 91.06 123.61 3,740.55 3,681.09 -9,587.01 5,995.04 6,018,206.59 539,551.41 0.36 10,370.81 3_MWD+IFR2+MS+Sag (2) 13,628.97 88.95 122.88 3,740.54 3,681.08 -9,637.92 6,072.71 6,018,156.04 539,629.29 2.40 10,463.66 3_MWD+IFR2+MS+Sag (2) 13,721.41 87.85 123.60 3,743.12 3,683.66 -9,688.57 6,149.99 6,018,105.74 539,706.80 1.42 10,556.03 3_MWD+IFR2+MS+Sag (2) 13,820.80 87.85 123.79 3,746.85 3,687.39 -9,743.67 6,232.62 6,018,051.02 539,789.67 0.19 10,655.35 3_MWD+IFR2+MS+Sag (2) 13,917.35 87.97 124.05 3,750.37 3,690.91 -9,797.51 6,312.69 6,017,997.55 539,869.97 0.30 10,751.83 3_MWD+IFR2+MS+Sag (2) 13,960.00 88.41 125.30 3,751.72 3,692.26 -9,821.77 6,347.75 6,017,973.46 539,905.13 3.11 10,794.45 3_MWD+IFR2+MS+Sag (3) 14,011.65 86.42 125.27 3,754.05 3,694.59 -9,851.57 6,389.86 6,017,943.85 539,947.38 3.85 10,846.04 3_MWD+IFR2+MS+Sag (3) 14,105.05 87.41 125.59 3,759.07 3,699.61 -9,905.63 6,465.86 6,017,890.13 540,023.61 1.11 10,939.29 3_MWD+IFR2+MS+Sag (3) 14,201.92 90.76 127.33 3,760.62 3,701.16 -9,963.18 6,543.74 6,017,832.94 540,101.74 3.90 11,036.08 3_MWD+IFR2+MS+Sag (3) 14,297.95 89.76 127.73 3,760.19 3,700.73 -10,021.68 6,619.89 6,017,774.79 540,178.15 1.12 11,131.97 3_MWD+IFR2+MS+Sag (3) 14,393.43 89.27 130.25 3,760.99 3,701.53 -10,081.75 6,694.10 6,017,715.06 540,252.62 2.69 11,227.15 3_MWD+IFR2+MS+Sag (3) 14,487.96 89.83 132.60 3,761.74 3,702.28 -10,144.29 6,764.97 6,017,652.85 540,323.76 2.56 11,320.98 3_MWD+IFR2+MS+Sag (3) 14,584.41 90.20 128.65 3,761.71 3,702.25 -10,207.07 6,838.16 6,017,590.40 540,397.23 4.11 11,416.86 3_MWD+IFR2+MS+Sag (3) 14,680.37 89.08 125.25 3,762.31 3,702.85 -10,264.75 6,914.83 6,017,533.08 540,474.15 3.73 11,512.71 3_MWD+IFR2+MS+Sag (3) 14,776.05 89.33 125.03 3,763.64 3,704.18 -10,319.81 6,993.07 6,017,478.37 540,552.63 0.35 11,608.38 3_MWD+IFR2+MS+Sag (3) 14,870.99 89.02 125.44 3,765.01 3,705.55 -10,374.58 7,070.61 6,017,423.96 540,630.40 0.54 11,703.30 3_MWD+IFR2+MS+Sag (3) 14,966.03 91.43 124.06 3,764.64 3,705.18 -10,428.75 7,148.69 6,017,370.15 540,708.72 2.92 11,798.33 3_MWD+IFR2+MS+Sag (3) 15,061.01 92.11 123.32 3,761.70 3,702.24 -10,481.41 7,227.68 6,017,317.85 540,787.94 1.06 11,893.25 3_MWD+IFR2+MS+Sag (3) 15,156.40 89.70 122.64 3,760.20 3,700.74 -10,533.32 7,307.68 6,017,266.30 540,868.17 2.63 11,988.59 3_MWD+IFR2+MS+Sag (3) 15,249.69 88.40 123.05 3,761.74 3,702.28 -10,583.91 7,386.04 6,017,216.07 540,946.75 1.46 12,081.83 3_MWD+IFR2+MS+Sag (3) 15,344.96 86.73 121.63 3,765.79 3,706.33 -10,634.83 7,466.46 6,017,165.52 541,027.38 2.30 12,176.94 3_MWD+IFR2+MS+Sag (3) 15,440.56 87.05 122.71 3,770.98 3,711.52 -10,685.65 7,547.26 6,017,115.07 541,108.41 1.18 12,272.31 3_MWD+IFR2+MS+Sag (3) 15,535.93 88.71 125.65 3,774.50 3,715.04 -10,739.19 7,626.09 6,017,061.90 541,187.47 3.54 12,367.60 3_MWD+IFR2+MS+Sag (3) 15,631.12 90.07 127.10 3,775.52 3,716.06 -10,795.63 7,702.73 6,017,005.80 541,264.35 2.09 12,462.73 3_MWD+IFR2+MS+Sag (3) 15,725.90 90.81 128.86 3,774.79 3,715.33 -10,853.96 7,777.43 6,016,947.82 541,339.31 2.01 12,557.33 3_MWD+IFR2+MS+Sag (3) 15,821.17 89.39 126.94 3,774.62 3,715.16 -10,912.47 7,852.60 6,016,889.65 541,414.73 2.51 12,652.43 3_MWD+IFR2+MS+Sag (3) 15,916.60 89.45 123.47 3,775.59 3,716.13 -10,967.48 7,930.56 6,016,835.00 541,492.93 3.64 12,747.83 3_MWD+IFR2+MS+Sag (3) 16,011.43 88.59 121.30 3,777.21 3,717.75 -11,018.26 8,010.62 6,016,784.58 541,573.22 2.46 12,842.57 3_MWD+IFR2+MS+Sag (3) 16,106.98 87.16 121.90 3,780.76 3,721.30 -11,068.29 8,091.95 6,016,734.93 541,654.76 1.62 12,937.93 3_MWD+IFR2+MS+Sag (3) 16,201.27 86.61 122.42 3,785.88 3,726.42 -11,118.40 8,171.65 6,016,685.18 541,734.68 0.80 13,032.00 3_MWD+IFR2+MS+Sag (3) 16,297.60 87.23 123.96 3,791.06 3,731.60 -11,171.06 8,252.15 6,016,632.89 541,815.40 1.72 13,128.17 3_MWD+IFR2+MS+Sag (3) 12/312019 1:44:18PM Page 6 COMPASS 5000.15 Build 91 E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M -19i MPU M -19i MPU M -19i Local Co-ordinate Reference: Well MPU M -19i TVD Reference: MPU M-19 Actual RKB @ 59.46usft MD Reference: MPU M-19 Actual RKB @ 59.46usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (a) (a) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 16,392.44 87.10 123.94 3,795.75 3,736.29 -11,223.96 8,330.72 6,016,580.35 541,894.21 0.14 13,222.89 3_MWD+IFR2+MS+Sag (3) 16,487.58 87.79 123.32 3,799.99 3,740.53 -11,276.60 8,409.86 6,016,528.07 541,973.57 0.97 13,317.92 3_MWD+IFR2+MS+Sag (3) 16,582.50 88.71 123.94 3,802.89 3,743.43 -11,329.14 8,488.85 6,016,475.89 542,052.80 1.17 13,412.78 3_MWD+IFR2+MS+Sag (3) 16,678.03 89.51 124.46 3,804.37 3,744.91 -11,382.83 8,567.85 6,016,422.56 542,132.03 1.00 13,508.30 3_MWD+IFR2+MS+Sag (3) 16,773.21 89.95 124.77 3,804.82 3,745.36 -11,436.90 8,646.19 6,016,368.86 542,210.60 0.57 13,603.48 3_MWD+IFR2+MS+Sag (3) 16,867.91 90.01 124.54 3,804.85 3,745.39 -11,490.75 8,724.08 6,016,315.36 542,288.73 0.25 13,698.18 3_MWD+IFR2+MS+Sag (3) 16,963.37 89.57 124.62 3,805.20 3,745.74 -11,544.93 8,802.68 6,016,261.54 542,367.56 0.47 13,793.64 3_MWD+IFR2+MS+Sag (3) 17,058.82 88.65 123.75 3,806.68 3,747.22 -11,598.55 8,881.63 6,016,208.28 542,446.74 1.33 13,889.07 3_MWD+IFR2+MS+Sag (3) 17,153.75 88.28 123.32 3,809.23 3,749.77 -11,650.97 8,960.73 6,016,156.22 542,526.07 0.60 13,983.95 3_MWD+IFR2+MS+Sag (3) 17,249.89 92.55 123.26 3,808.53 3,749.07 -11,703.73 9,041.07 6,016,103.83 542,606.64 4.44 14,080.05 3_MWD+IFR2+MS+Sag (3) 17,343.22 93.71 123.00 3,803.43 3,743.97 -11,754.66 9,119.11 6,016,053.26 542,684.90 1.27 14,173.21 3_MWD+IFR2+MS+Sag (3) 17,375.92 94.28 123.10 3,801.16 3,741.70 -11,772.45 9,146.45 6,016,035.59 542,712.32 1.77 14,205.82 3_MWD+IFR2+MS+Sag (3) 17,450.00 94.28 123.10 3,795.63 3,736.17 -11,812.79 9,208.34 6,015,995.53 542,774.38 0.00 14,279.67 PROJECTED to TD Checked B Chelsea Wri htWrighllysignedbyChelsea Approved B Benjamin Hand oa,.202 0106092526-0900nd Date: 12-31-2019 Y _ DDate 2019.12.311051:23-09'00' pp Y 12/3112019 1:44:18PM Page 7 COMPASS 5000.15 Build 91E 31 December, 2019 Milne Point M Pt Moose Pad MPU M-19PB1 500292365570 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-19i MPU M-19PB1 Survey Calculation Method:Minimum Curvature MPU M-19 Actual RKB @ 59.46usft Design:MPU M-19PB1 Database:NORTH US + CANADA MD Reference:MPU M-19 Actual RKB @ 59.46usft North Reference: Well MPU M-19i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU M-19i usft usft 0.00 0.00 6,027,765.55 533,513.82 25.10Wellhead Elevation:usft0.50 70° 29' 12.796 N 149° 43' 33.890 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU M-19PB1 Model NameMagnetics BGGM2019 11/30/2019 16.23 80.90 57,408.27326725 Phase:Version: Audit Notes: Design MPU M-19PB1 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:34.36 124.500.000.0034.36 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 12/30/2019 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa220.94 8,873.82 MPU M-19PB1 MWD+IFR2+MS+Sag (1) 12/11/2019 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa8,968.99 14,561.00 MPU M-19PB1 MWD+IFR2+MS+Sag (2) 12/27/2019 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 34.36 0.00 0.00 34.36 0.00 0.00-25.10 6,027,765.55 533,513.82 0.00 0.00 UNDEFINED 220.94 0.74 163.83 220.93 -1.16 0.34161.47 6,027,764.39 533,514.16 0.40 0.93 3_MWD+IFR2+MS+Sag (1) 314.21 3.55 170.24 314.13 -4.58 0.99254.67 6,027,760.97 533,514.83 3.02 3.41 3_MWD+IFR2+MS+Sag (1) 407.53 6.32 171.15 407.10 -12.51 2.27347.64 6,027,753.06 533,516.15 2.97 8.96 3_MWD+IFR2+MS+Sag (1) 500.32 8.81 167.91 499.07 -24.50 4.55439.61 6,027,741.07 533,518.48 2.72 17.63 3_MWD+IFR2+MS+Sag (1) 592.62 11.44 164.67 589.93 -40.24 8.45530.47 6,027,725.35 533,522.45 2.91 29.76 3_MWD+IFR2+MS+Sag (1) 686.17 14.31 167.64 681.12 -60.49 13.38621.66 6,027,705.13 533,527.47 3.15 45.29 3_MWD+IFR2+MS+Sag (1) 781.61 17.52 169.95 772.89 -86.16 18.41713.43 6,027,679.48 533,532.62 3.43 63.98 3_MWD+IFR2+MS+Sag (1) 876.70 21.38 167.65 862.53 -117.20 24.62803.07 6,027,648.47 533,538.96 4.14 86.67 3_MWD+IFR2+MS+Sag (1) 971.69 25.48 168.39 949.67 -154.14 32.44890.21 6,027,611.57 533,546.95 4.33 114.04 3_MWD+IFR2+MS+Sag (1) 1,066.56 30.30 168.27 1,033.50 -197.59 41.41974.04 6,027,568.17 533,556.12 5.08 146.05 3_MWD+IFR2+MS+Sag (1) 1,162.26 36.25 168.47 1,113.47 -249.00 51.991,054.01 6,027,516.81 533,566.92 6.22 183.88 3_MWD+IFR2+MS+Sag (1) 1,256.94 41.46 168.10 1,187.18 -307.14 64.051,127.72 6,027,458.74 533,579.25 5.51 226.75 3_MWD+IFR2+MS+Sag (1) 12/31/2019 1:43:11PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-19i MPU M-19PB1 Survey Calculation Method:Minimum Curvature MPU M-19 Actual RKB @ 59.46usft Design:MPU M-19PB1 Database:NORTH US + CANADA MD Reference:MPU M-19 Actual RKB @ 59.46usft North Reference: Well MPU M-19i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,352.91 43.87 168.71 1,257.74 -370.85 77.121,198.28 6,027,395.09 533,592.60 2.55 273.60 3_MWD+IFR2+MS+Sag (1) 1,448.55 45.69 167.34 1,325.63 -436.74 91.111,266.17 6,027,329.27 533,606.88 2.15 322.45 3_MWD+IFR2+MS+Sag (1) 1,543.64 52.07 167.44 1,388.13 -506.61 106.731,328.67 6,027,259.48 533,622.82 6.71 374.91 3_MWD+IFR2+MS+Sag (1) 1,638.77 55.10 166.90 1,444.60 -581.24 123.741,385.14 6,027,184.93 533,640.16 3.22 431.19 3_MWD+IFR2+MS+Sag (1) 1,733.44 59.51 165.45 1,495.72 -658.58 142.791,436.26 6,027,107.69 533,659.57 4.83 490.70 3_MWD+IFR2+MS+Sag (1) 1,828.76 62.28 166.21 1,542.08 -739.32 163.171,482.62 6,027,027.05 533,680.31 2.99 553.23 3_MWD+IFR2+MS+Sag (1) 1,924.01 62.60 167.17 1,586.16 -821.49 182.611,526.70 6,026,944.97 533,700.11 0.95 615.79 3_MWD+IFR2+MS+Sag (1) 2,019.59 65.22 166.43 1,628.19 -905.05 202.221,568.73 6,026,861.51 533,720.09 2.83 679.28 3_MWD+IFR2+MS+Sag (1) 2,115.42 68.07 166.31 1,666.17 -990.55 222.951,606.71 6,026,776.12 533,741.21 2.98 744.79 3_MWD+IFR2+MS+Sag (1) 2,212.65 71.09 167.07 1,700.09 -1,079.21 243.921,640.63 6,026,687.56 533,762.57 3.19 812.29 3_MWD+IFR2+MS+Sag (1) 2,308.56 71.28 167.63 1,731.02 -1,167.79 263.801,671.56 6,026,599.08 533,782.85 0.59 878.85 3_MWD+IFR2+MS+Sag (1) 2,404.20 70.14 168.29 1,762.62 -1,256.07 282.631,703.16 6,026,510.89 533,802.08 1.36 944.37 3_MWD+IFR2+MS+Sag (1) 2,499.78 69.51 167.91 1,795.58 -1,343.86 301.131,736.12 6,026,423.19 533,820.97 0.76 1,009.34 3_MWD+IFR2+MS+Sag (1) 2,596.19 71.42 167.18 1,827.82 -1,432.58 320.731,768.36 6,026,334.58 533,840.97 2.11 1,075.74 3_MWD+IFR2+MS+Sag (1) 2,691.55 70.41 168.17 1,859.00 -1,520.61 339.971,799.54 6,026,246.63 533,860.60 1.44 1,141.46 3_MWD+IFR2+MS+Sag (1) 2,786.65 70.36 168.21 1,890.93 -1,608.30 358.301,831.47 6,026,159.04 533,879.33 0.07 1,206.24 3_MWD+IFR2+MS+Sag (1) 2,882.11 72.19 168.57 1,921.57 -1,696.85 376.491,862.11 6,026,070.58 533,897.92 1.95 1,271.39 3_MWD+IFR2+MS+Sag (1) 2,976.86 71.86 169.19 1,950.81 -1,785.29 393.871,891.35 6,025,982.23 533,915.70 0.71 1,335.80 3_MWD+IFR2+MS+Sag (1) 3,072.21 71.53 169.02 1,980.76 -1,874.18 410.981,921.30 6,025,893.43 533,933.20 0.39 1,400.25 3_MWD+IFR2+MS+Sag (1) 3,167.10 74.00 168.03 2,008.87 -1,962.99 429.021,949.41 6,025,804.71 533,951.64 2.79 1,465.41 3_MWD+IFR2+MS+Sag (1) 3,262.22 73.93 169.02 2,035.15 -2,052.58 447.201,975.69 6,025,715.21 533,970.22 1.00 1,531.15 3_MWD+IFR2+MS+Sag (1) 3,356.73 73.42 168.85 2,061.71 -2,141.59 464.612,002.25 6,025,626.29 533,988.03 0.57 1,595.91 3_MWD+IFR2+MS+Sag (1) 3,451.35 73.48 165.97 2,088.67 -2,230.10 484.382,029.21 6,025,537.88 534,008.20 2.92 1,662.33 3_MWD+IFR2+MS+Sag (1) 3,547.11 72.12 165.09 2,116.99 -2,318.67 507.232,057.53 6,025,449.42 534,031.45 1.67 1,731.34 3_MWD+IFR2+MS+Sag (1) 3,642.36 72.70 165.34 2,145.77 -2,406.46 530.402,086.31 6,025,361.74 534,055.01 0.66 1,800.16 3_MWD+IFR2+MS+Sag (1) 3,737.12 72.05 165.38 2,174.46 -2,493.84 553.232,115.00 6,025,274.47 534,078.23 0.69 1,868.46 3_MWD+IFR2+MS+Sag (1) 3,832.24 67.92 165.98 2,207.01 -2,580.42 575.342,147.55 6,025,188.00 534,100.72 4.38 1,935.72 3_MWD+IFR2+MS+Sag (1) 3,927.73 67.98 166.78 2,242.86 -2,666.43 596.182,183.40 6,025,102.09 534,121.95 0.78 2,001.61 3_MWD+IFR2+MS+Sag (1) 4,022.79 69.62 168.98 2,277.24 -2,753.08 614.782,217.78 6,025,015.54 534,140.93 2.76 2,066.01 3_MWD+IFR2+MS+Sag (1) 4,117.80 70.29 168.87 2,309.80 -2,840.67 631.922,250.34 6,024,928.04 534,158.47 0.71 2,129.76 3_MWD+IFR2+MS+Sag (1) 4,212.70 69.30 169.18 2,342.58 -2,928.10 648.882,283.12 6,024,840.69 534,175.82 1.09 2,193.25 3_MWD+IFR2+MS+Sag (1) 4,308.22 71.60 168.97 2,374.54 -3,016.48 665.942,315.08 6,024,752.40 534,193.28 2.42 2,257.37 3_MWD+IFR2+MS+Sag (1) 4,403.45 72.12 167.67 2,404.19 -3,105.10 684.262,344.73 6,024,663.88 534,211.99 1.41 2,322.66 3_MWD+IFR2+MS+Sag (1) 4,496.76 71.20 168.33 2,433.55 -3,191.73 702.672,374.09 6,024,577.33 534,230.80 1.19 2,386.91 3_MWD+IFR2+MS+Sag (1) 4,593.91 72.58 165.45 2,463.76 -3,281.64 723.622,404.30 6,024,487.52 534,252.15 3.16 2,455.10 3_MWD+IFR2+MS+Sag (1) 4,688.09 71.98 165.49 2,492.42 -3,368.49 746.132,432.96 6,024,400.79 534,275.05 0.64 2,522.84 3_MWD+IFR2+MS+Sag (1) 4,783.08 72.45 166.08 2,521.44 -3,456.17 768.342,461.98 6,024,313.22 534,297.65 0.77 2,590.80 3_MWD+IFR2+MS+Sag (1) 4,880.39 72.89 166.35 2,550.42 -3,546.38 790.482,490.96 6,024,223.11 534,320.19 0.52 2,660.14 3_MWD+IFR2+MS+Sag (1) 4,976.70 72.95 165.87 2,578.71 -3,635.75 812.582,519.25 6,024,133.85 534,342.69 0.48 2,728.98 3_MWD+IFR2+MS+Sag (1) 5,071.21 72.06 166.11 2,607.12 -3,723.21 834.402,547.66 6,024,046.51 534,364.90 0.97 2,796.50 3_MWD+IFR2+MS+Sag (1) 12/31/2019 1:43:11PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-19i MPU M-19PB1 Survey Calculation Method:Minimum Curvature MPU M-19 Actual RKB @ 59.46usft Design:MPU M-19PB1 Database:NORTH US + CANADA MD Reference:MPU M-19 Actual RKB @ 59.46usft North Reference: Well MPU M-19i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 5,167.03 70.28 165.33 2,638.05 -3,811.09 856.762,578.59 6,023,958.73 534,387.66 2.01 2,864.71 3_MWD+IFR2+MS+Sag (1) 5,262.07 71.35 165.87 2,669.28 -3,898.04 879.082,609.82 6,023,871.90 534,410.37 1.25 2,932.35 3_MWD+IFR2+MS+Sag (1) 5,357.36 70.49 167.41 2,700.43 -3,985.65 899.902,640.97 6,023,784.39 534,431.58 1.77 2,999.12 3_MWD+IFR2+MS+Sag (1) 5,453.13 71.01 167.80 2,732.00 -4,073.96 919.302,672.54 6,023,696.18 534,451.38 0.67 3,065.14 3_MWD+IFR2+MS+Sag (1) 5,547.40 70.82 167.95 2,762.83 -4,161.06 938.012,703.37 6,023,609.17 534,470.48 0.25 3,129.89 3_MWD+IFR2+MS+Sag (1) 5,642.68 69.90 168.19 2,794.85 -4,248.85 956.572,735.39 6,023,521.47 534,489.43 0.99 3,194.91 3_MWD+IFR2+MS+Sag (1) 5,737.91 70.80 168.47 2,826.87 -4,336.68 974.712,767.41 6,023,433.73 534,507.96 0.98 3,259.60 3_MWD+IFR2+MS+Sag (1) 5,832.92 71.01 168.91 2,857.96 -4,424.72 992.312,798.50 6,023,345.78 534,525.96 0.49 3,323.98 3_MWD+IFR2+MS+Sag (1) 5,927.27 71.60 168.69 2,888.20 -4,512.39 1,009.672,828.74 6,023,258.20 534,543.71 0.66 3,387.94 3_MWD+IFR2+MS+Sag (1) 6,023.49 72.24 169.17 2,918.06 -4,602.16 1,027.232,858.60 6,023,168.52 534,561.68 0.82 3,453.26 3_MWD+IFR2+MS+Sag (1) 6,118.53 71.92 167.95 2,947.30 -4,690.79 1,045.172,887.84 6,023,079.98 534,580.01 1.27 3,518.24 3_MWD+IFR2+MS+Sag (1) 6,213.64 73.99 167.78 2,975.18 -4,779.68 1,064.282,915.72 6,022,991.18 534,599.52 2.18 3,584.35 3_MWD+IFR2+MS+Sag (1) 6,308.90 72.58 167.03 3,002.58 -4,868.72 1,084.182,943.12 6,022,902.24 534,619.82 1.66 3,651.17 3_MWD+IFR2+MS+Sag (1) 6,403.08 73.36 166.97 3,030.16 -4,956.46 1,104.432,970.70 6,022,814.60 534,640.47 0.83 3,717.56 3_MWD+IFR2+MS+Sag (1) 6,498.52 71.26 166.81 3,059.16 -5,045.02 1,125.052,999.70 6,022,726.15 534,661.48 2.21 3,784.72 3_MWD+IFR2+MS+Sag (1) 6,594.07 71.20 166.86 3,089.90 -5,133.11 1,145.663,030.44 6,022,638.17 534,682.48 0.08 3,851.59 3_MWD+IFR2+MS+Sag (1) 6,689.56 71.15 167.51 3,120.72 -5,221.24 1,165.713,061.26 6,022,550.13 534,702.93 0.65 3,918.03 3_MWD+IFR2+MS+Sag (1) 6,784.42 72.75 167.77 3,150.11 -5,309.33 1,185.013,090.65 6,022,462.13 534,722.62 1.71 3,983.84 3_MWD+IFR2+MS+Sag (1) 6,880.05 71.65 167.45 3,179.34 -5,398.26 1,204.553,119.88 6,022,373.30 534,742.56 1.19 4,050.31 3_MWD+IFR2+MS+Sag (1) 6,975.47 69.82 166.96 3,210.82 -5,486.10 1,224.493,151.36 6,022,285.56 534,762.90 1.98 4,116.50 3_MWD+IFR2+MS+Sag (1) 7,070.96 70.02 167.33 3,243.61 -5,573.54 1,244.453,184.15 6,022,198.23 534,783.24 0.42 4,182.47 3_MWD+IFR2+MS+Sag (1) 7,166.00 69.35 167.21 3,276.60 -5,660.48 1,264.093,217.14 6,022,111.39 534,803.27 0.71 4,247.89 3_MWD+IFR2+MS+Sag (1) 7,261.30 68.44 167.71 3,310.92 -5,747.26 1,283.393,251.46 6,022,024.70 534,822.97 1.07 4,312.96 3_MWD+IFR2+MS+Sag (1) 7,355.97 69.05 168.31 3,345.24 -5,833.57 1,301.723,285.78 6,021,938.49 534,841.68 0.87 4,376.95 3_MWD+IFR2+MS+Sag (1) 7,452.82 70.76 168.50 3,378.51 -5,922.66 1,320.003,319.05 6,021,849.48 534,860.36 1.78 4,442.48 3_MWD+IFR2+MS+Sag (1) 7,546.89 74.00 166.37 3,406.99 -6,010.15 1,339.513,347.53 6,021,762.09 534,880.27 4.06 4,508.11 3_MWD+IFR2+MS+Sag (1) 7,641.97 74.63 162.41 3,432.70 -6,098.29 1,364.143,373.24 6,021,674.07 534,905.29 4.06 4,578.34 3_MWD+IFR2+MS+Sag (1) 7,735.95 74.00 157.87 3,458.12 -6,183.37 1,394.873,398.66 6,021,589.14 534,936.40 4.70 4,651.84 3_MWD+IFR2+MS+Sag (1) 7,833.20 73.80 153.56 3,485.10 -6,268.51 1,433.283,425.64 6,021,504.18 534,975.19 4.26 4,731.73 3_MWD+IFR2+MS+Sag (1) 7,926.89 77.06 150.47 3,508.67 -6,348.55 1,475.843,449.21 6,021,424.34 535,018.10 4.72 4,812.14 3_MWD+IFR2+MS+Sag (1) 8,023.03 75.65 145.87 3,531.36 -6,427.91 1,525.083,471.90 6,021,345.21 535,067.70 4.88 4,897.67 3_MWD+IFR2+MS+Sag (1) 8,117.82 74.57 140.41 3,555.74 -6,501.18 1,580.003,496.28 6,021,272.20 535,122.94 5.68 4,984.43 3_MWD+IFR2+MS+Sag (1) 8,212.85 72.11 136.53 3,582.99 -6,569.33 1,640.333,523.53 6,021,204.33 535,183.57 4.69 5,072.75 3_MWD+IFR2+MS+Sag (1) 8,308.10 70.89 135.77 3,613.21 -6,634.47 1,702.903,553.75 6,021,139.48 535,246.43 1.49 5,161.21 3_MWD+IFR2+MS+Sag (1) 8,403.25 73.55 133.35 3,642.27 -6,698.02 1,767.463,582.81 6,021,076.22 535,311.27 3.70 5,250.41 3_MWD+IFR2+MS+Sag (1) 8,498.95 77.50 130.62 3,666.19 -6,759.97 1,836.333,606.73 6,021,014.59 535,380.41 4.97 5,342.26 3_MWD+IFR2+MS+Sag (1) 8,594.18 82.08 129.06 3,683.07 -6,819.99 1,908.283,623.61 6,020,954.90 535,452.62 5.07 5,435.55 3_MWD+IFR2+MS+Sag (1) 8,688.83 84.75 126.66 3,693.92 -6,877.68 1,982.503,634.46 6,020,897.55 535,527.10 3.78 5,529.40 3_MWD+IFR2+MS+Sag (1) 8,784.23 85.80 122.60 3,701.78 -6,931.70 2,060.723,642.32 6,020,843.89 535,605.55 4.38 5,624.45 3_MWD+IFR2+MS+Sag (1) 8,873.82 88.52 124.75 3,706.22 -6,981.31 2,135.173,646.76 6,020,794.63 535,680.22 3.87 5,713.91 3_MWD+IFR2+MS+Sag (1) 12/31/2019 1:43:11PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-19i MPU M-19PB1 Survey Calculation Method:Minimum Curvature MPU M-19 Actual RKB @ 59.46usft Design:MPU M-19PB1 Database:NORTH US + CANADA MD Reference:MPU M-19 Actual RKB @ 59.46usft North Reference: Well MPU M-19i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,968.99 91.31 122.46 3,706.36 -7,033.97 2,214.423,646.90 6,020,742.32 535,759.70 3.79 5,809.05 3_MWD+IFR2+MS+Sag (2) 9,061.89 90.31 124.36 3,705.05 -7,085.12 2,291.963,645.59 6,020,691.53 535,837.45 2.31 5,901.92 3_MWD+IFR2+MS+Sag (2) 9,159.08 89.76 124.86 3,704.99 -7,140.32 2,371.953,645.53 6,020,636.70 535,917.68 0.76 5,999.11 3_MWD+IFR2+MS+Sag (2) 9,253.34 89.14 124.42 3,705.90 -7,193.89 2,449.503,646.44 6,020,583.48 535,995.46 0.81 6,093.36 3_MWD+IFR2+MS+Sag (2) 9,350.38 88.83 124.76 3,707.61 -7,248.97 2,529.373,648.15 6,020,528.76 536,075.58 0.47 6,190.39 3_MWD+IFR2+MS+Sag (2) 9,445.00 87.78 124.12 3,710.41 -7,302.46 2,607.373,650.95 6,020,475.63 536,153.81 1.30 6,284.96 3_MWD+IFR2+MS+Sag (2) 9,540.59 89.77 122.96 3,712.46 -7,355.26 2,687.023,653.00 6,020,423.20 536,233.69 2.41 6,380.51 3_MWD+IFR2+MS+Sag (2) 9,636.03 89.14 122.57 3,713.36 -7,406.91 2,767.273,653.90 6,020,371.91 536,314.17 0.78 6,475.90 3_MWD+IFR2+MS+Sag (2) 9,730.54 89.95 123.07 3,714.11 -7,458.13 2,846.693,654.65 6,020,321.06 536,393.81 1.01 6,570.37 3_MWD+IFR2+MS+Sag (2) 9,825.98 89.20 123.42 3,714.82 -7,510.45 2,926.513,655.36 6,020,269.10 536,473.85 0.87 6,665.78 3_MWD+IFR2+MS+Sag (2) 9,920.87 90.01 122.61 3,715.48 -7,562.15 3,006.073,656.02 6,020,217.77 536,553.64 1.21 6,760.63 3_MWD+IFR2+MS+Sag (2) 10,014.43 91.06 123.42 3,714.60 -7,613.13 3,084.523,655.14 6,020,167.15 536,632.31 1.42 6,854.16 3_MWD+IFR2+MS+Sag (2) 10,111.14 88.89 122.78 3,714.65 -7,665.94 3,165.533,655.19 6,020,114.71 536,713.55 2.34 6,950.83 3_MWD+IFR2+MS+Sag (2) 10,206.75 87.47 123.02 3,717.68 -7,717.84 3,245.773,658.22 6,020,063.17 536,794.01 1.51 7,046.35 3_MWD+IFR2+MS+Sag (2) 10,301.41 88.10 124.68 3,721.34 -7,770.53 3,324.323,661.88 6,020,010.85 536,872.79 1.87 7,140.93 3_MWD+IFR2+MS+Sag (2) 10,396.58 86.92 126.62 3,725.48 -7,825.94 3,401.583,666.02 6,019,955.79 536,950.29 2.38 7,235.99 3_MWD+IFR2+MS+Sag (2) 10,491.65 88.10 127.50 3,729.61 -7,883.18 3,477.373,670.15 6,019,898.90 537,026.33 1.55 7,330.87 3_MWD+IFR2+MS+Sag (2) 10,586.62 86.92 126.48 3,733.73 -7,940.26 3,553.153,674.27 6,019,842.16 537,102.36 1.64 7,425.66 3_MWD+IFR2+MS+Sag (2) 10,682.18 87.29 125.26 3,738.56 -7,996.18 3,630.493,679.10 6,019,786.59 537,179.94 1.33 7,521.07 3_MWD+IFR2+MS+Sag (2) 10,776.64 87.04 125.08 3,743.23 -8,050.53 3,707.613,683.77 6,019,732.61 537,257.30 0.33 7,615.41 3_MWD+IFR2+MS+Sag (2) 10,872.12 87.97 125.63 3,747.39 -8,105.72 3,785.403,687.93 6,019,677.77 537,335.34 1.13 7,710.78 3_MWD+IFR2+MS+Sag (2) 10,967.38 89.39 127.30 3,749.58 -8,162.32 3,861.993,690.12 6,019,621.52 537,412.17 2.30 7,805.96 3_MWD+IFR2+MS+Sag (2) 11,061.99 88.83 125.96 3,751.05 -8,218.76 3,937.903,691.59 6,019,565.43 537,488.33 1.53 7,900.49 3_MWD+IFR2+MS+Sag (2) 11,157.39 90.51 125.32 3,751.60 -8,274.35 4,015.433,692.14 6,019,510.20 537,566.10 1.88 7,995.86 3_MWD+IFR2+MS+Sag (2) 11,252.43 90.32 125.41 3,750.91 -8,329.35 4,092.933,691.45 6,019,455.55 537,643.84 0.22 8,090.89 3_MWD+IFR2+MS+Sag (2) 11,347.58 89.20 123.68 3,751.31 -8,383.30 4,171.303,691.85 6,019,401.95 537,722.44 2.17 8,186.03 3_MWD+IFR2+MS+Sag (2) 11,441.87 89.64 122.96 3,752.27 -8,435.10 4,250.093,692.81 6,019,350.52 537,801.45 0.89 8,280.30 3_MWD+IFR2+MS+Sag (2) 11,537.61 89.39 123.89 3,753.08 -8,487.83 4,329.993,693.62 6,019,298.15 537,881.58 1.01 8,376.02 3_MWD+IFR2+MS+Sag (2) 11,633.68 89.76 125.65 3,753.79 -8,542.61 4,408.903,694.33 6,019,243.73 537,960.73 1.87 8,472.08 3_MWD+IFR2+MS+Sag (2) 11,725.38 90.01 126.97 3,753.97 -8,596.91 4,482.793,694.51 6,019,189.77 538,034.86 1.47 8,563.73 3_MWD+IFR2+MS+Sag (2) 11,823.38 89.95 126.85 3,754.01 -8,655.77 4,561.153,694.55 6,019,131.28 538,113.47 0.14 8,661.64 3_MWD+IFR2+MS+Sag (2) 11,919.27 87.53 124.65 3,756.12 -8,711.77 4,638.943,696.66 6,019,075.63 538,191.51 3.41 8,757.47 3_MWD+IFR2+MS+Sag (2) 12,014.95 86.42 121.64 3,761.17 -8,764.01 4,718.933,701.71 6,019,023.76 538,271.73 3.35 8,852.98 3_MWD+IFR2+MS+Sag (2) 12,109.64 87.97 118.97 3,765.80 -8,811.72 4,800.573,706.34 6,018,976.42 538,353.57 3.26 8,947.29 3_MWD+IFR2+MS+Sag (2) 12,203.76 89.70 119.69 3,767.71 -8,857.82 4,882.613,708.25 6,018,930.70 538,435.81 1.99 9,041.01 3_MWD+IFR2+MS+Sag (2) 12,298.27 90.50 119.70 3,767.55 -8,904.63 4,964.713,708.09 6,018,884.26 538,518.11 0.85 9,135.18 3_MWD+IFR2+MS+Sag (2) 12,394.00 90.32 121.09 3,766.86 -8,953.07 5,047.273,707.40 6,018,836.20 538,600.89 1.46 9,230.66 3_MWD+IFR2+MS+Sag (2) 12,490.77 91.43 122.65 3,765.39 -9,004.15 5,129.443,705.93 6,018,785.49 538,683.28 1.98 9,327.32 3_MWD+IFR2+MS+Sag (2) 12,584.97 90.56 120.01 3,763.75 -9,053.12 5,209.893,704.29 6,018,736.89 538,763.93 2.95 9,421.35 3_MWD+IFR2+MS+Sag (2) 12,677.97 92.54 118.91 3,761.23 -9,098.84 5,290.833,701.77 6,018,691.54 538,845.07 2.44 9,513.95 3_MWD+IFR2+MS+Sag (2) 12/31/2019 1:43:11PM COMPASS 5000.15 Build 91E Page 5 Project: Company:Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Halliburton Definitive Survey Report Well: Wellbore: MPU M-19i MPU M-19PB1 Survey Calculation Method:Minimum Curvature MPU M-19 Actual RKB @ 59.46usft Design:MPU M-19PB1 Database:NORTH US + CANADA MD Reference:MPU M-19 Actual RKB @ 59.46usft North Reference: Well MPU M-19i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 12,774.14 92.41 120.67 3,757.08 -9,146.57 5,374.213,697.62 6,018,644.19 538,928.65 1.83 9,609.70 3_MWD+IFR2+MS+Sag (2) 12,871.17 89.94 122.45 3,755.09 -9,197.34 5,456.863,695.63 6,018,593.80 539,011.53 3.14 9,706.57 3_MWD+IFR2+MS+Sag (2) 12,966.26 90.75 126.68 3,754.52 -9,251.28 5,535.143,695.06 6,018,540.22 539,090.05 4.53 9,801.64 3_MWD+IFR2+MS+Sag (2) 13,061.29 91.37 127.47 3,752.76 -9,308.56 5,610.953,693.30 6,018,483.29 539,166.10 1.06 9,896.55 3_MWD+IFR2+MS+Sag (2) 13,155.59 92.29 127.41 3,749.75 -9,365.85 5,685.783,690.29 6,018,426.34 539,241.18 0.98 9,990.68 3_MWD+IFR2+MS+Sag (2) 13,251.55 92.66 127.56 3,745.61 -9,424.20 5,761.863,686.15 6,018,368.34 539,317.51 0.42 10,086.42 3_MWD+IFR2+MS+Sag (2) 13,346.85 90.31 125.90 3,743.14 -9,481.16 5,838.203,683.68 6,018,311.72 539,394.11 3.02 10,181.61 3_MWD+IFR2+MS+Sag (2) 13,438.57 90.87 123.31 3,742.19 -9,533.25 5,913.693,682.73 6,018,259.99 539,469.82 2.89 10,273.31 3_MWD+IFR2+MS+Sag (2) 13,536.10 91.06 123.61 3,740.55 -9,587.01 5,995.043,681.09 6,018,206.59 539,551.41 0.36 10,370.81 3_MWD+IFR2+MS+Sag (2) 13,628.97 88.95 122.88 3,740.54 -9,637.92 6,072.713,681.08 6,018,156.04 539,629.29 2.40 10,463.66 3_MWD+IFR2+MS+Sag (2) 13,721.41 87.85 123.60 3,743.12 -9,688.57 6,149.993,683.66 6,018,105.74 539,706.80 1.42 10,556.03 3_MWD+IFR2+MS+Sag (2) 13,820.80 87.85 123.79 3,746.85 -9,743.67 6,232.623,687.39 6,018,051.02 539,789.67 0.19 10,655.35 3_MWD+IFR2+MS+Sag (2) 13,917.35 87.97 124.05 3,750.37 -9,797.51 6,312.693,690.91 6,017,997.55 539,869.97 0.30 10,751.83 3_MWD+IFR2+MS+Sag (2) 14,012.98 88.96 126.85 3,752.93 -9,852.95 6,390.563,693.47 6,017,942.46 539,948.08 3.10 10,847.40 3_MWD+IFR2+MS+Sag (2) 14,108.40 91.06 127.66 3,752.92 -9,910.71 6,466.503,693.46 6,017,885.05 540,024.27 2.36 10,942.70 3_MWD+IFR2+MS+Sag (2) 14,204.02 93.91 128.71 3,748.77 -9,969.76 6,541.583,689.31 6,017,826.35 540,099.61 3.18 11,038.02 3_MWD+IFR2+MS+Sag (2) 14,298.99 92.66 127.89 3,743.33 -10,028.52 6,615.993,683.87 6,017,767.93 540,174.27 1.57 11,132.63 3_MWD+IFR2+MS+Sag (2) 14,394.05 90.81 123.97 3,740.45 -10,084.26 6,692.913,680.99 6,017,712.54 540,251.44 4.56 11,227.59 3_MWD+IFR2+MS+Sag (2) 14,489.60 91.80 123.82 3,738.27 -10,137.54 6,772.203,678.81 6,017,659.63 540,330.96 1.05 11,323.11 3_MWD+IFR2+MS+Sag (2) 14,561.00 92.50 123.80 3,735.60 -10,177.24 6,831.483,676.14 6,017,620.20 540,390.41 0.98 11,394.45 3_MWD+IFR2+MS+Sag (2) Approved By:Checked By:Date: 12/31/2019 1:43:11PM COMPASS 5000.15 Build 91E Page 6 12-31-2019 Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. MP M-19 County North Slope Borough State Alaska Supv CASING RECORD Surface TD 8.914.00 Shoe Deoth: 8.914.00 PBTD: Date Run 22 -Dec -19 D. Yessak / C. Demoski Csg Wt. On Hook: Type Float Collar: Innovex No. Hrs to Run: 37 Csg Wt. On Slips: Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes No 5.4 Ft. Min. 9.3 PPG Fluid Description: Spud Mud CEMENTING REPORT Shoe @ 8907 FC @ 8,825.24 Top of Liner Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Premium G Lead Sacks: 960 Yield: 2.35 Density (ppg) 12 Volume pumped (BBLs) w Tail Slurry Type: Premium G Tail F Density (ppg) 15.8 Volume pumped (BBLs) 15 Displacement: LL Type: Spud Mud Density (ppg) 9.4 Rate (bpm): FCP (psi): 550 Pump used for disp: Rig #1 Casing Rotated? Yes X No Reciprocated? Cement returns to surface? X Yes No Spacer returns? Cement In Place At: 8:07 Date: 12/23/2019 Method Used To Determine TOC: Cement circulated out Stage Collar @ 2943.62 Type Preflush (Spacer) Type: Tuned Spacer Lead Slurry uJ Type: Permafrost L lead C7 y Density (ppg) 10.7 Z Displacement: 401.6 82 Mixing / Pumping Rate (bpm): 5 Sacks: 400 Yield: 1.16 Mixing / Pumping Rate (bpm): 2.5 6.5 Volume (actual / calculated): 593.68/587.52 Bump Plug? X Yes No Bump press 1080 Yes X No % Returns during job 100 ' X Yes No Vol to Surf: 60 Estimated TOC: 2,944 Closure OK Density (ppg) 10 Volume pumped (BBLs) 60 Sacks: 600 Yield: 4.41 Volume pumped (BBLs) 471 Mixing / Pumping Rate (bpm): 5 Type: Spud Mud Density (ppg) 9.4 Rate (bpm): LU cn FCP (psi): 480 Pump used for disp: Rig pump #1 Casing Rotated? Yes X No Reciprocated? Cement returns to surface? X Yes No Spacer returns? Cement In Place At: 23:18 Date: 12/23/2019 Method Used To Determine TOC: Returns to surface Post Job Calculations: 6 Volume (actual / calculated): 222.81/233.81 Bump Plug? X Yes No Bump press 1420 Yes X No % Returns during job 100 Yes X No Vol to Surf: 202.8 Estimated TOC: 38 Calculated Cmt Vol @ 0% excess: 530.76 Total Volume cmt Pumped: 1010.8 Cmt returned to surface: 262.8 Calculated cement left in wellbore: 748 OH volume Calculated: 490.65 OH volume actual: 726.55 Actual % Washout: 48 www.wellez.net WellEz Information Management LLC ver 04818br Casing (Or Liner) Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 TXP BTC -SR Innovex 1.60 8,907.00 8,905.40 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 78.86 8,905.40 8,826.54 1 Float Collar 103/4 50.0 TXP BTC -SR Innovex 1.30 8,826.54 8,825.24 1 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 39.40 8,825.24 8,785.84 1 Baffle Adapter 103/4 50.0 TXP BTC -SR HES 1.47 8,785.84 8,784.37 148 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 5,823.85 8,784.37 2,960.52 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 14.05 2,960.52 2,946.47 1 ES Cementer 103/4 TXP BTC -SR HES 2.85 2,946.47 2,943.62 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 13.59 2,943.62 2,930.03 73 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,876.00 2,930.03 54.43 1 Fut Joint of Casin 95/8 40.0 L-80 TXP BTC -SR Tenaris 20.00 54.43 34.43 Csg Wt. On Hook: Type Float Collar: Innovex No. Hrs to Run: 37 Csg Wt. On Slips: Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes No 5.4 Ft. Min. 9.3 PPG Fluid Description: Spud Mud CEMENTING REPORT Shoe @ 8907 FC @ 8,825.24 Top of Liner Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Premium G Lead Sacks: 960 Yield: 2.35 Density (ppg) 12 Volume pumped (BBLs) w Tail Slurry Type: Premium G Tail F Density (ppg) 15.8 Volume pumped (BBLs) 15 Displacement: LL Type: Spud Mud Density (ppg) 9.4 Rate (bpm): FCP (psi): 550 Pump used for disp: Rig #1 Casing Rotated? Yes X No Reciprocated? Cement returns to surface? X Yes No Spacer returns? Cement In Place At: 8:07 Date: 12/23/2019 Method Used To Determine TOC: Cement circulated out Stage Collar @ 2943.62 Type Preflush (Spacer) Type: Tuned Spacer Lead Slurry uJ Type: Permafrost L lead C7 y Density (ppg) 10.7 Z Displacement: 401.6 82 Mixing / Pumping Rate (bpm): 5 Sacks: 400 Yield: 1.16 Mixing / Pumping Rate (bpm): 2.5 6.5 Volume (actual / calculated): 593.68/587.52 Bump Plug? X Yes No Bump press 1080 Yes X No % Returns during job 100 ' X Yes No Vol to Surf: 60 Estimated TOC: 2,944 Closure OK Density (ppg) 10 Volume pumped (BBLs) 60 Sacks: 600 Yield: 4.41 Volume pumped (BBLs) 471 Mixing / Pumping Rate (bpm): 5 Type: Spud Mud Density (ppg) 9.4 Rate (bpm): LU cn FCP (psi): 480 Pump used for disp: Rig pump #1 Casing Rotated? Yes X No Reciprocated? Cement returns to surface? X Yes No Spacer returns? Cement In Place At: 23:18 Date: 12/23/2019 Method Used To Determine TOC: Returns to surface Post Job Calculations: 6 Volume (actual / calculated): 222.81/233.81 Bump Plug? X Yes No Bump press 1420 Yes X No % Returns during job 100 Yes X No Vol to Surf: 202.8 Estimated TOC: 38 Calculated Cmt Vol @ 0% excess: 530.76 Total Volume cmt Pumped: 1010.8 Cmt returned to surface: 262.8 Calculated cement left in wellbore: 748 OH volume Calculated: 490.65 OH volume actual: 726.55 Actual % Washout: 48 www.wellez.net WellEz Information Management LLC ver 04818br Regg, James B (CED) From: Sent: To: Cc: Subject: Attachments: See attached report. Thanks. Sloan Sunderland Hilcorp North Slope Sr Drilling Forman Office 907-670-3090 Cell- 907-715-0591 Prb 2-111,54o Sloan Sunderland <ssunderland@hilcorp.com> Monday, January 6, 2020 12:15 PM Ke/1 Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (CED); Wallace, Chris D (CED) Wyatt Rivard; Joseph Engel; Jeremiah Vanderpool - (C) Pre MIT IA M-19 HILCORP MIT MPU M-19 01-05-20.xlsx 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. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaa0alaska.aov: AOGCC.Inspectors0alaska.aov;. phoebe. brooksCdlalaska.gov OPERATOR: Hilcorp Alaska LLC FIELD / UNIT / PAD: Milne Point MPU M pad DATE: 01/05/20 OPERATOR REP: Jeremiah Vanderpool AOGCC REP: chhs.wallace(ccDalaska. aov TV-- 1161kzo Well M-19 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O = Other (describe in Notes) PTD 219-154 Type Inj N Tubing 0 0 0 0 O = Other (describe in notes) Type Test P Packer TVD 3694 BBL Pump 6.2 - IA 0 2615 2525' 2510- Interval 0 Test psi 1500 BBL Return 6.2 - OA Result P Notes: Witness waived by Matthew Herrrera on 01/04/2020 at 08:43 AM. Initial, pre-injection MIT -IA performed on the rig. Monobore injector, no OA. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10426 (Revised 01/2017) 2020-0105_101IT_MPU_M-19 THE STATE °'ALASKA 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.00gcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-19 Hilcorp Alaska, LLC Permit to Drill Number: 219-154 Surface Location: 4915' FSL, 651' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 1563' FNL, 2084' FEL, SEC. 30, TI 3N, RI OE, 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, 2 Jer y P ice Chair DATED this day of _November, 2019. STATE OF ALASKA RECEIVE® ALr,—r<A OIL AND GAS CONSERVATION COMM,_ION PERMIT TO DRILL NOV 0 5 2019 20 AAC 25.005 . n et er r% 1 a. Type of Work: 1b.. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ a 6✓ Vs proposed for: Drill Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj Single Zone 21 Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-19 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,449' TVD: 3,782' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4915' FSL, 651' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL025515, ADL025517 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 2075' FNL, 1512' FWL, Sec 24, T13N, R9E, UM, AK LONS 16-004 11/24/2019 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 1563' FNL, 2084' FEL, Sec 30, T13N, R1 OE, UM, AK 7659 3205' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.8' _ 15. Distance to Nearest Well Open Surface: x-533513 y- 6027765 Zone -4 GL / BF Elevation above MSL (ft): 25.1' Ito Same Pool: 755' MPJ -20A 16. Deviated wells: Kickoff depth: 450 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92.8 degrees Downhole: 1609 Surface: 1243 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 113' Surface Surface 113' 113' -270 ft3 12-1/4" 9-5/8" 40# L-80 TXP C4, ,L�.2. Surface Surface Stg 1 - L - 2254 ft3 / T - 458 ft3 9,035' 3,655' _O Stg 2 - L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 8,564' 8,885' 3,642' 17,449' 3,782' Cementless Injection Liner ICDs Tieback 3-1/2" 9.3# 1 L-80 EUE 8RD 8,885' Surface Surface 8,885' 1 ,642' 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 Diverter Sketch Drilling Program Time v. Depth Plot ❑ Seabed Report ❑ Drilling Fluid Program B✓ Shallow Hazard Analysis 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hIICOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 �Lfl M o�t7;rY M Y �S Authorized Signature: Date: 17 Commission Use Only Permit to Drill Ll API Number: Permit ApprovalSee cover letter for other Number: — 150- 6 -0O - Qp Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other:�-��© �� /� , ---� Samples req'd: Yes ❑ No � Mud log req'd: Yes ❑ No [1� PP H2S measures: Yes ❑ No [R" Directional svy req'd: Yes VNo ❑ j Spacing exception req'd: Yes ❑ No ER Inclination -only svy req'd: Yes �❑/ No V �� �^• �)p_.Lrz�X Post initial injection MIT req'd: Yes IYJ No ❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and Form 10-401 Revised 017 This permit is valid for 24 month f 0B t O I er 20 AAC 5.005 ) �ach,ments in Dup icat — —.—--— — — — ——— _H Z W Y Q CL D Y J JQ — Y U) � w as �a LL DO Q ~e z m -: a a '_- O W J m 3 QQ HRS out —i_ 4d3iA �' ge �o 34 V7 r3 U v vu a m v .-� Ol U v v y O O a p L v .-� Ol N E O N N u l~D YO ate+ cnm ��o r N n H N om4 d bo u c 00 -0 ^ `"•3 N 3 u "O 0 V w v o a N v c @ m u E Q. n 3 00 N O D o m 00 o c o p r� n u 83 v x a u c r0 rn '3 t0 "6 0- 0 0 H ^ c N co o fo oo O N @ Ql C O c v -o x v m 3 v u s o w a u N -o U � . :76, u ns u fo v ti o- � n w M N E a, m .a � u E �^ rn y N �o v °o° o° ax 3 o c t ^@ n c N v a o v 3 L ° o o v 3 v^ c a c yo m u o ^ O v m a m asc N v c E ma) Zn o c v m aci @ v � y Q v -' o N .moi c u v o aci u N o u E Ln c E 3 @ E � v un O o -o r-: •. ou O a v -O N c u °1 I O u v u m u a s u -o a v °�° E N a o m u ai E E a� E oo No t m o t v E Y v a u a v n .� m J u= cL ra 3 y 3 41 N Q O N N Ln Ln O In O >?. sU U U U v1 O ++ Q� U U U U U U CC C > i J N7 .... 7 7 7 7 m U cn N N to rn N v 4- 0 „ O' u u u v v U CU Q Va m aro F' C L It L a�M I-- L L aim L It- L J d -j ro U N N N rn N (n U Ln Zn I� G Q m m M m M M FO- 0 N C�C ZD G G M Il Ql t\ 00 Ol LPI N LO In W 0 CL c) m m r� o0 00 -o L z n H a a0 a a m 00 J J Q J O O -i m O N W Z Z c N N i a nCL O O 0 0 0 O 0 O o O o O O N O O O O O O 19 10 O m m N lD O N a Lr) LO m r- r m Q O O l0 rn Ol m r1 N N m N N N N N N N Ol Ql 01 Ql (3) N N N N N (N N O O O O O O O O O O O O Ln Ln Ln ill Ln Ln 00 m O 0 c -I u) Q I, -i r- Ln N 00 1 l O O r- 1 i a m Zt ai 0 0 0 oo 00 .-i 0 0 O H -I N N N N Hilcorp Alaska, LLC Milne Point Unit (MPU) M-19 Drilling Program Version 1 11/5/19 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work.........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................37 18.0 RDMO............................................................................................................................................38 19.0 Doyon 14 Diverter Schematic.......................................................................................................39 20.0 Doyon 14 BOP Schematic.............................................................................................................40 21.0 Wellhead Schematic......................................................................................................................41 22.0 Days Vs Depth...............................................................................................................................42 23.0 Formation Tops & Information...................................................................................................43 24.0 Anticipated Drilling Hazards.......................................................................................................44 25.0 Doyon 14 Layout............................................................................................................................47 26.0 FIT Procedure...............................................................................................................................48 27.0 Doyon 14 Choke Manifold Schematic.........................................................................................49 28.0 Casing Design................................................................................................................................50 29.0 8-1/2" Hole Section MASP............................................................................................................51 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 31.0 Surface Plat (As Built) (NAD 27).................................................................................................53 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................54 Hilcorp E-gy C-p.uy 1.0 Well Summary Milne Point Unit M-19 SB Injector Drilling Procedure Well MPU M-19 Pad Milne Point "M" Pad Planned Completion Type 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 17,448' MD / 3,782' TVD PBTD, MD / TVD 17,448' MD / 3,782' TVD Surface Location (Governmental) 4915' FSL, 651' FEL, Sec 14, TON, R9E, UM, AK Surface Location (NAD 27) X= 533,513 Y= 6,027,765 Top of Productive Horizon (Governmental) 2075' FNL, 1512' FWL, Sec 24, T13N, R9E, UM, AK TPH Location (NAD 27) X= 535,713 Y= 6,020,786 BHL (Governmental) 1563' FNL, 2084' FEL, Sec 30, T13N, R10E, UM, AK BHL (NAD 27) X= 542,664 Y=6,016,055 AFE Number 1915812M (D,C,F) AFE Drilling Days 20 days AFE Completion Das 4 days AFE Drilling Amount $4,662,925 AFE Completion Amount $1,667,122 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1243 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1609 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.1 ft = 58.8 ft GL Elevation above MSL: 25.1 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information Hilcorp Alaska, LLC HilcQrp Changes to Approved Permit to Drill Date: 11/312019 Subject: Changes to Approved Permit to Drill foj MPU M-19 File #: MPU M-19 Drilling and Completion Program Any modifications to MPU M-19 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 Milne Point Unit M-19 SB Injector Hiicorp E�rgy Cvmpavy Drilling Procedure 2.0 Management of Change Information Hilcorp Alaska, LLC HilcQrp Changes to Approved Permit to Drill Date: 11/312019 Subject: Changes to Approved Permit to Drill foj MPU M-19 File #: MPU M-19 Drilling and Completion Program Any modifications to MPU M-19 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-19 SB Injector Drilling Procedure HoleD Section (in) ID in Drift in Conn OD in Wt #/ft(psi) a Conn Burst Collapse (psi) Tensio k -lb Cond 20" 19.25" - - - X-52 Weld k -lbs Surface & 5" 4.276" 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 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hote OD ID(in) TJ ID TJ OD Wt Grade Conn M/U 1 M/U Tension Section in in in "" ' "" ' "' . Min Max . ' k -lbs Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560k1b 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 WN 5.0 Internal Reporting Requirements Milne Point Unit M-19 SB Injector Drilling Procedure 5.1 Fill out daily drilling report and cost report on Wel1Ez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mm ers@hilcorp, jengel@bilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyersghilcorp,com jengelghilcorp.com and cdingerghilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyersAhilcorp.com jen-elghilcorp.com and cdin eg_rghilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 iengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 tweliman@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 kfleming2!1 orp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinser@hilcorp.com Page 5 Hilcorp E—gy C=pmy 6.0 Planned Wellbore Schematic Ul ft X5 ev,_2S1 T-"=17AW INVI 1TD=3,732 iT.2f PBT-"_ VA' Iflop / P 5M=3.7'ITVD Page 6 '3 i Milne Point Unit M-19 SB Injector Drilling Procedure tiilne F'r iqt Unit veli. MPU M-19 Proposed Schernatic PTD: TBD APP TBD TREE � 1NELLHEAD Tree Cameron 318" SM w/ 4-06' SPA Camerorr N Yrfe6head Cameron 11` 5K x 6altom w/ 122-1116'SK cL& --------------------------------- - - --- - - - --------------- -----, I OpEht i`84Lf ,/ Cft�IENT DETAIL I 42" SOyards dum d[19almhackside 12-1,/4„ S%1—Lead 2254 R3 f Tail 458 83 S%2—Lead 19371t3/Tail314U 9-112' 1 CvvwHrm 1 `ectian Liner in 8-i/7' hale --------------------------------------------------------------------------------------------• CASING DETAIL size Type �,W Gradel Cann Dfft M Tap 6 i BPF 2SI x34- CunduMt IInsulatedl .115.5 / X-42 / V*W rl/A Swfate 1 113' A 9-5/B" Surface 40/1 -BD T%P N.677' Surface 9:,^.35' OA758 4-i/2" Liner 13.5/L-80/UjA625 3.79T' 8,885 1 17,449' OA1d9 TLONG DET41L +, Tubina 9 3 1-80 rur n6 I 18Gi I Sud I &MS' OO$�iO WELL INCLINATloN DETAIL XOP & 45O' tide AtWe @ XN = TSD 11deAn Ie UnerTvp=TBD Max LIn1e Angle = TBA )Gfi, siiVt" T4t5' ittt;Sre9 fi3eka Null 11 ''t; T66 I ThD --------- W"JEiL 11rtFC1 APIA- TBC ed by Duvcn 14- Future JEWELRY DETAIL I No Tap MDs item IQ upgz•er Camp etian 1 =2,352' 3.S" X NI 4e I2.813' PatkingBurel 2.6131. 2 ±7,00LY .3.5')04 Ni 2813" Pxki ^ Bute; 2.75" No-Gt) 2.750' 3 18.0w IS" G&W Wridrel SGM4(PQG wl)V Wire 2.M' 4 ±8,875' 8.26` No Go Latatrr w/ 7-375' Sas] Assemb 2.992' 5 28,a85' 7.375'Twbackabove the 5L2itPUnerTopPacket 2.692' tat aerCo = etlon 6 ±8,885' UP Liner Top Packer 7 17,440' Shoe )Gfi, siiVt" T4t5' ittt;Sre9 fi3eka Null 11 ''t; T66 I ThD --------- W"JEiL 11rtFC1 APIA- TBC ed by Duvcn 14- Future 7.0 Drilling / Completion Summary Milne Point Unit M-19 SB Injector Drilling Procedure MPU M-19 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-19 is partof a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD injection liner will be run in the open hole section. • The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately November 24, 2019, pending rig schedule. Surface casing will be run to 9,035 MD / 3,655' 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. NX & 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/TJ & 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/TJ Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Milne Point Unit M-19 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-19. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 8 ff Hilcorp Energy C—pmy Summary of BOP Equipment & Notifications Milne Point Unit M-19 SB Injector Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reggga,alaska.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(a,alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixsegalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(2alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) ,/ Page 9 Hilcorp Energy Cmnpmy 9.0 RX and Preparatory Work Milne Point Unit M-19 SB Injector Drilling Procedure 9.1 M-19 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 (a), 95% volumetric efficiency. Page 10 10.0 NX 21-1/4112M Diverter System Milne Point Unit M-19 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. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 11 Hilw� 10.4 Rig & Diverter Orientation: • May change on location M--22 -( M-17 M-18 IAf f~ '—" M— 19 1i-03 � Milne Point Unit M-19 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources i erter Line MPU M -Pad 'Drawing Not To Scale Page 12 0 Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-19 SB Injector Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 Milne Point Unit M-19 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 actual offset wells with a clearance factors <1.0 in the surface hole section • M -19i P2 DSW is a planned well and does not exist yet 11.4 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Page 14 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 N1ih M �$•`� • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. PrJ 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. Milne Point Unit M-19 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 FLH lb sx I Temp Surface 8.8-9.8 1 75-175 20-40 25-45 <10 8.5-9.0 <_ 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme LTL 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 ff Hilcorp E -W C-vmy 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-19 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 P/U 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 Company 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 (it used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth ATFloat Shoe Depth Hole TO "Reference Casm,_n Sales Manual Sectio,,5 Page 17 "A Overall Length B Mist. ID After Mlout C Max. Tc -,l QD D Open��g Seat ID E Ctosino Seat ID Plug Set Part No. • Closing • • Opening Plug OD OD Shut-off Plug OD Bypass Plug (ti used) OD Milne Point Unit M-19 SB Injector Drilling Procedure HBtorp ES41 Running Order ES -0 Cementer .Shut Off Pug Baffle Adapter ih pass Plug By pass Baffle Float Collar Float Shoe Milne Point Unit M-19 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 5joints 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" 409 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 Milne Point Unit M-19 SB Injector Drilling Procedure TXPV BTC ��e>> 1110812018 Outside Diameter 9.625,:n. Min. Wall 67.5°k Thickness �') Grade L80 Type 1 Wall Thickness O-395 n. Connection DD REGULAR option COUPUNG RIPE 8013Y Body. Red fist Band. Red Grade L60 Type 1• Drift API Standard 9s. Bard: Broom 2nd Band: 2nd Sand: - Brown Type C -f9 arc Band: - Bra Band: - 4Ih Band' - Nominal Cr 9.625 in, Wminal IWght 40 lbs'R Drift 6.679 in. Nvatinal ID 6.635 in. .Aral: TItici taas 0.395 ;'air End tVeiOht 36.97 �s'ft Or, Tcnce API PERFORMANCE Body Y -e4 SL—.-,glh 916 x1 ODD S,r tntenta=Y4.ii3 5750 ps SMYS EOOOi ps Cass a 3D9D psi CONNECTION DATA GEOMETRY cc,inect -n OD 10.625 in Cazcpknp L B:h 90.825 T Connection IC 6:923 m, Make-up Lose 4.634 in. Tares s per in, Connection CO Option REGULAR PERFORMANCE 'aElsian Eff6ency 100,0% 3aiat b -e�1 St-.rTh 916.OD0 x1000 Internal Pressure Capacity I', 5750.000 p3i lbs Ccrnpression Efficiency 100 % . Gsmpression SrwT..h 916.000. x1600 Max. AllokvEt4 Sending 39.1100 ft Ibs Er..arral Pressase Capacity 3090.800 ps MAKE-UP TORQUE S M ttamurr; ff Hilcorp E -By C-PmY Milne Point Unit M-19 SB Injector Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Hilcorp Enmgy Company 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-19 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 RAJ cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1' Stage Total Cement Volume: Page 21 Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" (8,035'- 2500') x .0558 bpf x 1.3 = 401.5 2254 J Casing Total Lead 401.5 2254 12-1/4" OH x 9-5/8" (9,035'- 8,035') x .0558 bpf x 1.3 = 72.5 407 — Casing ~F 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Hilcorp Evagy Company Milne Point Unit M-19 SB Injector 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. • 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: 8,915' x .0758 bpf = 675.8 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage 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 TM 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. • 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: 8,915' x .0758 bpf = 675.8 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage 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 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 -1I 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 Milne Point Unit M-19 SB Injector Hilco1rp+ E -W C-pmy 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 -1I 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 F—gy C®psuy Second Stage Surface Cement Job: Milne Point Unit M-19 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 211 Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM TM System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 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 (2500' - 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM System (Hal Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 Hilcorp E—u Company Milne Point Unit M-19 SB Injector Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run "casing tally & casing and cement report to iengelghilcorp. com and cdi�(a,hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 ff Hilcorp Energy Company 14.0 BOP NX and Test Milne Point Unit M-19 SB Injector Drilling Procedure 14.1 N/D the diverter T, knife gate, diverter line & NX 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/TJ 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 — C • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 Hilcorp Energy Compmy 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-19 SB Injector Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 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. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 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# 5-135 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 0 Hilcorp E—gy Company Milne Point Unit M-19 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 FloPro drilling fluid Properties: ✓ Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 1 15-25 - ALAP 1 15-30 4-6 <10% <8 <1 1.0 <100 System Formulation: H 16, 9\0=$ tCrFJ Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 1b sx 6 CONQOR 404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Page 28 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 OA & 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 in the Schrader OA sand that have a clearance factor of <1.0. • There are existing wells with clearance factor <1.0, but they are in different sands and collision can be ruled out geologically • J-23 & J-24 are laterals in the OB sand J -23A, J -24A, and J-27 are laterals in the NB sand • 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% Page 29 Milne Point Unit M-19 SB Injector Hilco+{�/+� Energy Company Drilling Procedure 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 OA & 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 in the Schrader OA sand that have a clearance factor of <1.0. • There are existing wells with clearance factor <1.0, but they are in different sands and collision can be ruled out geologically • J-23 & J-24 are laterals in the OB sand J -23A, J -24A, and J-27 are laterals in the NB sand • 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% Page 29 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. • 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. Page 30 Milne Point Unit M-19 SB Injector Hileorp E-W C-P Drilling Procedure 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. • 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. Page 30 Milne Point Unit M-19 SB Injector Drilling Procedure 15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 Hilcorp E—By Company Milne Point Unit M-19 SB Injector Drilling Procedure 16.0 Run 4-1/2" Injection Liner (Lower Completion) < 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. 6.3. 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 4-1/2" 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). X • 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 Milne Point Unit M-19 SB Injector Hil 2,T Drilling Procedure E it Company 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 For the latest performance data. always visit our Website, www.tenaris.com Wedge 6250 Outride Diameter 4.500 i, Wall Thickness 0.290 M. Grade LBO Type t' Min. Wall 87.5% Thickness Connection OD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-19 SB Injector Drilling Procedure 12i17412A i 7 {*) Grade LBO 4.500 u^ Nomnal weight Type 7 Nmnsnal ID COUPLING PIPE BODY Body: Red tst Band: Red 1st Band: Brawn 2nd Band: 2nd Band: - Brown 3rd Band: - 3rd Band: - 9020 psi SMYS 80600 ps, 4th Band: - GEOMETRY J� Nominal OD 4.500 u^ Nomnal weight 13.50 lbsi t Drip. 3.795 m. Nmnsnal ID 3.920 To Wag Thickness 0290 n. Fba n E . We ght 13.05 Wt 00 Tolerance APi Conneccon OD Option PERFORMANCE Body Yds Slrerir*s 307 x tCW lbs InterntA Yield 9020 psi SMYS 80600 ps, collapse 8540 ps Tension Eficiency 91.0% Joint Yield Strenp Connecbm OD 4Jt4 in. Connect an 10 3.849 sn Make-up Loss 4230m. Threats ;sr in 359 Conneccon OD Option REGULAR. PERFORMANCE Tension Eficiency 91.0% Joint Yield Strenp 279.370 x1000 Internal Pressure Capaory 9020.000 psi Ills Compression Eff+c:ercy 945% Compression Strength 290.115 000 Max..AOawable Sending 73.7';IGO ft lbs External P!essure Capacity 8540.000 psi MAKE-UP TORQUES +Minimum 8000Nb5 Cpbmm 9500 if -lbs Malaria 128WOabs OPERATION LIMIT TORQUES Opera" Torque 12800 ft lbs Yeid TorgL* MOD 914bs Notes For further infamat)on On concepts indicated in this datasheet, download the Datasheet Manual From www.tenans-cant 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 Milne Point Unit M-19 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. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.19. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.20. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.21. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. Page 35 Milne Point Unit M-19 SB Injector Drilling Procedure 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. Displace 2-3/8" x Liner, pump 2 circulations. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean out run 16.25. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.26. Flush liner top at max rate while displacing out well to clean brine. 16.27. POOH LD Remaining 5" DP. 16.28. Once runniniz tools are L/D, Swap to Completion AFE. Page 36 Hilcorp E.-gy C-pmy 17.0 Run 3-1/2" Tubing (Upper Completion) Milne Point Unit M-19 SB Injector Drilling Procedure 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivardghilcorp.com for submission to AOGCC. 17.2 17.3 17.4 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 R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-1/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-%2" 9.3#/ft, L-80 EUE 8RD tubing • 3-%2" "X -N" 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-%2" 9.3#/ft, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 37 Hilcorp Energy Company 17.5 Makeup the tubing hanger and landing joint. Milne Point Unit M-19 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 I% corrosion inhibitor. 1 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. s... J 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Page 38 Hilcorp E—gy C—P.Y 19.0 Doyon 14 Diverter Schematic 21-1,d' 2M Rrser- 21-F!-v 26A-DN*rw IT, - 2 macer spoo 1&3'4'Wx 21 -JA' ltd DSA Page 39 Milne Point Unit M-19 SB Injector Drilling Procedure —16' 1'uffi Opoviing KnKe Vahe IB' Diveiter Une Hilcorp E ..gy C—peuy 20.0 Doyon 14 BOP Schematic KW tip---""`'. Page 40 Milne Point Unit M-19 SB Injector Drilling Procedure 2-7/811 x 5" VBR Blind Rams x Say HCR at Gale Valve 2-7/811 x 5" VBR Hilcorp Energy C—peuy 21.0 Wellhead Schematic Milne Point Unit M-19 SB Injector Drilling Procedure CAMERON -•11 " 5K AlBS 4-1/16"5K 16.09" 11" 5F — 2-1116" 5i: tt�! 31.34" 2125" 112" Control Lines 24 Si" Vote L7imenaonal irfvzmation xflected on chis drsxi Z ase. e:bnufed measgrrsneats only. t Page 41 Hilcorp Ecegy Cumpavy 22.0 Days Vs Depth 0 2000 4000 6000 a W-31 10000 ea s 12000 14000 MPU M-19 SB OA Injector Days vs Depth 18000 0 5 10 15 20 Days Page 42 Milne Point Unit M-19 SB Injector Drilling Procedure jector 25 30 Hilcorp Energy Company 23.0 Formation Tops & Information Milne Point Unit M-19 SB Injector Drilling Procedure MPU M-19 Formations (wp08) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2224 -1776 1834 806.96 8.46 LA3 6320 -2969 3027 1331.88 8.46 Schrader Bluff NA j 7882 j -3419 j 3477 1 1529.88 8.46 Schrader Bluff OA 1 9060 1 -3599 1 3657 1 1609.08 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL _FORECAST COMMENTS Ss GEOLOGICAL TVD FM LITH DESCRIPTION ae 0-4 NOTE: Soo individual Well Program for T�A Gubik specific casing design, depth s, sizes, .aIQe`. 60G weights, grades and connections. _a Unconsolidated coarse to medium sand and small gravel • with "nor s(itstoxne. 1,000 a IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE -4*m SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. +Tse• Base permafrost htorbecis of sand. clays and siitstones with occasional 2,000' show of coal. watch possible sidetracking while washing�reaming. L-33 b L•75. Sagav �r tIok -ooe No hydrates encountered on L -Pad wells drilled to date. Continued Imorbeds of sand. clays and siltstonos with occasional shows of coal. Trans of pyrite at -1- 3700 it 3,000• hterval at -f• 3400 n can be sticky and tight (L .0i M. Clay htetbads between 3000 and 4500 h C 3472'- L A 3657' Kaand. UGNU: series of coarsening upward sands which are (,A&CDY F made up of: (from top to bottom) coarse sand fine sand• silty shale. Better developed intervening shales as you UGNU progress Into the L and M (doapef), Ugrw and Schrador Stuff Possible hydrocarbons limited L• d. to S W corner of Milnes development Northem area (s '�.. (-Xs) downstnutve and wet. .',.. '3739• Wanda '4000• (NA) Schrader Bluff Sands: 4,000 Ns,,ds IA&c,o. Con tirwed layering coarsening upward sands as above -4*m Schrader Bluff: Possible lost circulation EX) except more condensed and with occasional coal. zone while drilling long strings and running 4770• oSand. Clay rich shate interval4300 to4600ft Ugnu and Schrader Blurt. Possible hydrocarbons limited casing. Recommend deep setting surface (OA) R to SW corner of Milne development 1.37 and L -O sre casing for Kuparuk long strings. Also, the o completed in the Schrader stuff sand. Northam area of Schrader Bluff sands area potential Schrader L -Pad is dowrwtructure and wet. differential stuck pipe interval If left un -cases! Bluff `+ Surface casing point in shale Glow for Kuparuk long strings. Sands: Schrader Stuff OB sand for longer reach wells. I t_ Page 43 / 4�p' �— /\ A 0A 015 Milne Point Unit M-19 SB Injector Hil 2lxDrilling Procedure Ecei l Company 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 44 Hilcorp Energy Company Milne Point Unit M-19 SB Injector Drilling Procedure 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. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 45 8-1/2" Hole Section: Milne Point Unit M-19 SB Injector Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 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 1-12S 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 E—gy Compeuy 25.0 Doyon 14 Layout Milne Point Unit M-19 SB Injector Drilling Procedure Page 47 Hilcorp E—gy Company 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-19 SB Injector Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/TJ 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 �/cow ff 27.0 Doyon 14 Choke Manifold Schematic Milne Point Unit «Q9SBInjector Drilling Procedure �<<1 Z 7(DOD 9ZZ I Z g: 0 § ; a ¢ m8 CO @ § 0 o Z;v $ Q � , _ .'Mr. k )«\03 0 CL Ln 3/ 7 - / X Aga e L) 2 § & $ 2 ci BLP/ / sib Z 0 \ _ R �21 3 � � . o � § Page 4 Hilcorp Energy Company Milne Point Unit M-19 SB Injector Drilling Procedure 28.0 Casing Design n 14HcO,, Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 11/5/2019 WELL: MPU M-19 DESIGN BY: Joe Engel Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1243 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1243 psi (see attached MASP determination & calculation Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 50 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 4-1/2" Top (MD) 0 9,035 Top (TVD) 0 3,655 Bottom (MD) 9,035 17,448 Bottom (TVD) 3,655 3,782 Length 9,035 8,413 Weight (ppo 40 13.5 Grade L-80 L-80 Connection TXP H625 Weight w/o Bouyancy Factor (lbs) 361,400 113,576 Tension at Top of Section (Ibs) 361,400 113,576 Min strength Tension (1000 lbs) 916 279 Worst Case Safety Factor (Tension) 2.53 2.46 Collapse Pressure at bottom (Psi) 1,806 1,868 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.71- 4.57 MASP (psi) 1,243 1,243 Minimum Yield (psi) 5,750 9,020 Worst case safety factor (Burst) 4.63 ✓ 7.26 Page 50 Hilcorp E—W Company 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11xilcorp 8-1/2" Hole Section `" °"' MPU M-19 Milne Point Unit MD TVD Planned Top: 9035 3655 Planned TD: 17448 3782 Milne Point Unit M-19 SB Injector Drilling Procedure Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,655 1 1608 1 Oil 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 to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,655 (ft) x 0.78(psi/ft)= 2851 2851(psi) - [0.1(psi/ft)*3655(ft)]= 2485 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 655 (ft) x 0.44(psi/ft)= 1608 psi 1608(psi) - 0. 1(psi/ft) *3655(ft) 1243 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 51 ff Hilcorp Em,gy Company 30.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-19 SB Injector Drilling Procedure K€iPARt1K RIVER UNIT Sec:.11 ADL355023 �t 1 d �s f�+' _ - ADL388235 Sac. 12 - L+r�- `'y jj r t r - ,` ` • % r ' " a e�'t v ♦♦ADt 023509 <`'7 .«his ,♦ f;�t.l82Bl�r♦ t ttc`x ( , { v fir I,i� �67 L i t�' 3 �, ,' ♦ a -n n ♦�\. \F 1Fu V, FM-19i_SHL ).MPU 1411 �. -�ilR4 e�Y@ fc`-!iPE!♦ .ice' �"� -r ♦. d ♦. x` I; _:{Z 1♦A` �♦ si `' t 7PF11001A GESI.J;C,♦+ 'f I !i {♦.! ✓ 4 1 �♦ ! y ! ! P'S A d y ♦ L. . '• ;t ' + V•�j T ir• !d c +1C F -1C?' �,� r. »r ♦ Sec' 14 y*k i f'Sec .13 i r; t (fi33) di r t{ + r t x • , �4 P�6i M PJPa' mit-wE Po*T uNn 1• _ _ D1-025513 D `�,,��. �2551�A. ro+_sa ! i U013N009E ardc.' r s '• dJl � U013N010E SC ! L•�iPe` .�.. �•AkI. IA ♦: {tr51 : •sem 9 +' 1 i �.:'J i1 d L.5* *. t 41PL! Nt-19i TPH w!ePai `w s L.x. 1 J 1. Sec:'23 1 y Sec! 24 �" Sec. 19'`{4 t 3 F474P2.«1 .ter y5a>P81P 1 1 r ir:x, ♦ ''.♦ 1 1 ! w }''}a +r : ZSLi PBi E4!5 L'3uWB21.3S4 TM' •' IWL *SPS! 3{C-21 S��9it�'i91E!i't, PAD FA t7 v 4 s t• + .. '__� mss,.• ": + J:214' s ~ a?4iPl? Legend ♦ Nt-l9i_BHL° ~ �� • MPU M-19i_SHL • Other Surface Hales (SHL) ADL025517^ _Seal. 3D. - - - --- "' _, I MPUM-19i_TPH Other BottomHoles(SHL} a - Other Well Paths J.ixi as I -i MPU M-19i_BHL .....�._ Coastleafe (USGS 1:63X) x�e r t1 Oil and Gas Unit Boundary l ! Pad Footprint r! ! Milne Point Unit Alaska State Plane Zone 4 MAO 1927 /r 114 ItA. �, MPU M -13i Wel! a 1.100 2.200 U* own, lutwis wD 08 Feet Page 52 H Hilc=F..w C 31.0 Surface Plat (As Built) (NAD 27) I I e FHTTZ EEBEETZ- VEC 71 M AD CELLAR, Na rCqaqC1iAm5 Com?v%-Es p-pek- L 14 W-17 Y- 6,C27,7G,,,kS5 N- I.IG&OO 7-5�2VIZT91- IV,4000"- 4.9,1 : F4"' - 24.0' 24.W 1*'4,YX36 149,72EZ40-v 534 FE - w --19 Y- 5,027,76Mi N- fov.% mus"i z -'mr I 79.4001-TtlY 4.91 b' (,5L 2*,B' 2.7" W�603,a7 Eft MIMM 4;V4 -,'l - - 1*4 '14407 149,72- -4-45 561' FE- G,G2?,7r-qSS5 t4- ],S67.-CrQ 7-3----jJZ790' I ?U.4U15LIZ�'.�- 4�9i 5' F$L 3 3. :1 1 �,-, A 2 E V,01+90 V-22 Alp IA -21 y - G,C,27,2.F-0.77 N- 1,292.14 71J:ig 14 �097' i 7GL40 =4.1- "M F3t - 2;.Q' J 2!5�0 X - '-:I-'L M182 + 14T4'- 4 1 *0 7243-i43� 41 V FS -- X."mmil, . W-22 _74, Y-ms�w N- 292.zD % 0-29,14.0�1z— 'm F81 �6 1 . .... .... .. . S.0 2, 2 4.21 GRAFHZ [Nm 3Z H-3 R5 Em 147 .Y29,4 '4 t40794MW,- SM' M, C P1 r --T gel HARM*" W..k. — 3X, n. A UPLl WQ1)$F 'PAD a-autr MWNJI�ToRs Milne Point Unit M-19 SB Injector Drilling Procedure m--QN1rL-UAP ,T5 .9 LLQrho- 14-0 RES*: 'Otht I m i ALUM ST# -E RAC WOMA rrs AJZ *AMI. WK 1 CV3rVC PD570OAr H&OZT. wz A:S-DA7 Ru"OD111, -k 9 0 EY13Th-. COOLCrW !L eam Cr tiWILW-4, Am wrthm pw*m NX Mier A-V ke 04 IA� V( w -ce 4k NPU " XYMM FM SC -M_- WS r%qtW.J x mm rir mrw(,. 4 AT I WN * ZV, k 0, 11V mwv ?w em � W -V-0 4,4 1 -1 k Z74* VATHN PROTRLCTED SEC. 1A, T. 13 N.. R. 9 E.. UWAT mmwx ALASKA Page 53 i FHTTZ EEBEETZ- VEC 71 M AD CELLAR, Na rCqaqC1iAm5 Com?v%-Es p-pek- W-17 Y- 6,C27,7G,,,kS5 N- I.IG&OO 7-5�2VIZT91- IV,4000"- 4.9,1 : F4"' - 24.0' 24.W 1*'4,YX36 149,72EZ40-v 534 FE - w --19 Y- 5,027,76Mi N- fov.% mus"i z -'mr I 79.4001-TtlY 4.91 b' (,5L 2*,B' 2.7" W�603,a7 Eft MIMM 4;V4 -,'l - - 1*4 '14407 149,72- -4-45 561' FE- G,G2?,7r-qSS5 t4- ],S67.-CrQ 7-3----jJZ790' I ?U.4U15LIZ�'.�- 4�9i 5' F$L 3 3. :1 1 �,-, A 2 E V,01+90 I 4,E114,1 44. 2W' 651' FZ- IA -21 y - G,C,27,2.F-0.77 N- 1,292.14 71J:ig 14 �097' i 7GL40 =4.1- "M F3t - 2;.Q' J 2!5�0 X - '-:I-'L M182 Ea, 1,-64.Ct9 14T4'- 4 1 *0 7243-i43� 41 V FS -- X."mmil, . W-22 _74, Y-ms�w N- 292.zD % 0-29,14.0�1z— 'm F81 �6 1 . .... .... .. . S.0 2, 2 4.21 [Nm 3Z H-3 R5 Em 147 .Y29,4 '4 t40794MW,- SM' M, gel HARM*" A UPLl WQ1)$F 'PAD a-autr MWNJI�ToRs 11wft, kv� A. .9L t to -O -p SL -At2- WEI I S 17,19,13.'.1.22 Page 53 Milne Point Unit M-19 SB Injector Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD mw, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110.3 MS 0 1 111]] 500 1000 1500 2000 I 2500 3000 3500 4000 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) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -19i MPU M -19i Plan: MPU M -19i wp08 Standard Proposal Report 29 October, 2019 HALLIBURTON Sperry Drilling Services Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU Jile19 Wellbore: MPUM-19i Design: MPU M -19i wpo Hilcerp Alaska, LLC Calculation Method: Minimum Curvature HALLIBURTON Error System: ISCWSA Scan Method: Closest Approach 30 sR, la„R Error Surface: Pedal Curve --r Warning Method: Error Ratio REFERENCE INFORMATION Coordinate (N,E) Reference: Well Plan: MPU M -19i, True North Vertical (ND) Reference: MPU M-19 Planned RKB @ 58.80usft Measured Depth Reference: MPU M-19 Planned RKB @ 58.80usft Calculation Method: Minimum Curvature FORMATION TOP DETAILS No formatbn 4ote h evalabM CASING DETAILS ND NDSS MD S' N 3655.00 3596.20 9035.42 ze ame 9-5/8 9 SECTION DETAILS 3782.00 3723.20 1744566 4-1/2 4 Sec 1 MD 33.70 Inc 0.00 Azi 0.00 ND 33.70 +NAS 0.00 +EAW 0.00 Dleg 0.00 TFace 0.00 VSect 0.00 Target Annotation 2 450.00 0.00 0.00 450.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100: 450' MD, 391.2 TVD 3 640.00 5.70 167.00 639.69 -9.20 2.12 3.00 167.00 6.96 MPU M -19i Wp08 (MPU M-1 9i StartDir4°/100': 640'MD,580.89'TVD 4 2325.55 73.12 167.41 1868.12 -994.22 222.78 4.00 0.43 746.73 0.00 0.00 End Dir : 2325.55' MD, 1809.32' ND 5 7644.00 73.12 167.41 3412.27 -5961.24 1331.93 0.00 0.00 4474.17 Start Dir 4°/100' : 7644' MD, 3353.47TVD 6 8735.42 85.00 124.50 3628.85 -6820.81 1922.62 4.00 -79.28 5447.83 End Dir : 8735.42' MD, 3570.05' ND 7 9035.42 85.00 124.50 3655.00 5990.08 2168.92 0.00 0.00 5746.69 M-19 wp07 Heel 8 9065.42 85.00 124.50 3657.61 -7007.01 2193.55 0.00 0.00 5776.58 Start Dir4°/100': 9065.42'MD, 3598.81'ND 9 9141.19 88.03 124.50 3662.22 -7049.84 2255.87 4.00 -0.02 5852.20 End Dir : 9141.19' MD, 3603.42' ND 10 94811 88.03 124.50 3674.15 -7246.44 2541.93 0.00 0.00 6199.30 Start.i14-/100' 9488.49'MD, 3615.357VD 11 9495.23 88.30 124.50 3674.37 -7250.25 2547.47 4.00 0.24 6206.02 End Dir : 9495.23' MD, 3615.57' ND 12 10595.23 88.30 124.50 3707.00 -7873.02 3453.61 0.00 0.00 7305.54 M-19 wp08 CP1 Start Dir 4°/100' : 10595.23' MD, 3648.2rVD 13 10674.09 85.15 124.50 3711.51 -7917.61 3518.49 L00 -180.00 7384.26 End Dir : 10674.09' MD, 3652.71' ND 14 10907.66 85.15 124.50 3731.27 -6049.43 3710.30 0.00 0.00 7617.00 Start Dir 4°/100': 10907.66' MD, 3672A 'TV 15 10996.53 88.70 124.50 3736.04 5099.68 3783.41 4.00 a00 7705.72 End Dir : 10996.53' MD, 3677.24' ND 16 12096.53 88.70 124.50 3761.00 -6722.57 4689.72 0.00 0.00 8805.44 M-19 Wp08 CP2 Start Dir 4°/100'. 12096.53' MD, 3702.2'ND 17 12198.93 92.80 124.50 3759.66 -8780.55 4774.08 4.00 -0.02 8907.81 End Dir . 12198.93' MD, 3700.86' ND 18 12524.48 92.80 124.50 3743.78 -6964.72 5042.07 0.00 0.00 9232.96 Start Dir 4-/100': 12524.48' MD, 3684.98TV 19 12596.88 89.90 124.50 3742.08 -9005.71 5101.71 4.00 179.97 9305.35 End Dir : 12596.88' MD, 3683.28' ND 20 13696.88 89.90 124.50 3744.00 -9628.76 6008.25 0.00 0.00 10405.34 M-19 wp08 CP3 Start Dir 4°!100' : 13696.88' MD, 3685.7ND 21 13804.39 85.60 124.50 3748.22 -9689.59 6096.76 4.00 179.99 10512.75 End Dir : 13804.39' MD, 3689.47 ND 22 14002.64 85.60 124.50 3763.43 -9801.56 6259.66 0.00 0.00 10710.41 Start Dir4°/100': 14002.64'MD, 3704.63'TV 23 14097 65 89.40 124.50 3767.58 -9855.31 6337.87 4.00 -0.01 10805.32 End Dir : 14097.65' MD, 3708.78' ND 24 14997.65 89.40 124.50 3777.00 -10365.05 7079.55 0.00 0.00 11705.27 M-19 Wp08 CP4 Start Dir 4°/100' : 14997.65' MD, 3718.2'ND 25 15109,31 93.87 124.50 3773,82 -10428.25 7171.50 4.00 0.00 11816.85 End Dir : 15109.31' MD, 3715.02' ND 26 15301.50 93.87 124.50 3760.86 -10536.86 7329.54 0.00 0.00 12008.61 Start Dir 4°/100': 15301.5'MD, 3702.06TVD 27 15398.16 90.00 124.50 3757.60 -10591.56 7409.13 4.00 179.99 12105.19 End Dir : 15398.16' MD, 3698.8' ND 28 16198.16 90.00 124.50 3757.60 -11044.69 8068.43 0.00 0.00 12905.19 M-19 Wp08 CP5 Start Dir 4./100': 16198.16' MD, 3698.8'T!D 29 16288.15 66.40 124.50 3760.43 -11095.63 8142.55 4.00 -179.97 12995.12 End Dir : 16288.15' MD, 3701.63' ND 30 16516.17 86.40 124.50 3774.74 -11224.52 8330.10 0.00 0.00 13222.69 Start Dir 4°/100': 16516.17'MD, 3715.94'TV 31 16598.66 89.70 124.50 3777.55 -11271.21 8398.04 4.00 0.03 13305.12 End Dir : 16598.66' MD, 3718.75' ND 32 17448.66 89.70 124.50 3782.00 -11752.65 9098.54 0.00 0.00 14155.11 M-19 wp08 Toe Total Depth: 17448.66' MD, 3723.7 ND 3655.00 3596.20 9035.42 ze ame 9-5/8 9 3782.00 3723.20 1744566 4-1/2 4 SURVEY PROGRAM Date: 201902-25T0000:00 Validated: Yes Version' ® WELL DETAILS: Plan: MPU M-1 9i Depth From DepthTo Survey/Plan Tool 33.70 9035.42 MPU M-191 WPO8 (MPU M -1 9i) 3 MWDI+FR2+MS+Sag 25.10 9035.42 17448.32 MPU M -19i Wp08 (MPU M-1 9i 3_MWD +FR2+MS+Sag +N/ -S +E/ -W Northing Eashrng LatdtudeLongitude 0.00 0.00 6027765.55 533513.82 70° 29' 12.796 N 149' 43'33.890 W IRt Start Dir 3-/100': 450' MD, 391.2'TVD - - " Start Dir 4°/100' : 640' MD, 580.89'ND 750 w �000 J 0 � End Dir : 2325.55' MD, 1809.37 ND 1500- 2250 500 2250 dpi h o0 > co 2 3000 VA A � M" le �O 0 �° Mh ti A ^om ° h J ^o "' F n^ e 4 b 6 o of 4F rvo-r°- O a C 4i° 4he O y 5 ! ,° � o` ya o' b N05 ' y� _meg MPU M -19i WP08 m 4 1/2" X 8 1!2„ 95/8"x 12 1/4-,-- iii o„ M-19 wp07 Heel M-19 wDO8 CP1 M-19 wp08 CP2 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Vertical Section at 124.50° (1500 usWin) C),#,( 0 0 opD o 0 0 o m M-19 wp08 CP3 M-19 WP08 CP4 M-19 WPO8 CPS M-19 WPO8 Toe 9750 10500 11250 12000 12750 13500 14250 L 0J _ Start Di 3'/100': 450' MD, 391.2TVD Start Dir 4'/100': 640' MD, 580.89TVD EM Dir: 2325.55'MD,. 1809.32'TVD -2250 -3000 WELL DETAIIS: Plan: MPU M -19i Start Dir 4°/100' : 7644' MD, 3353.47TVD C 25.10 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027765.55 533513.82 70° 29' 12.796 N 149° 43'33.890 W p Project: Milne Point M Site: M Pt Moose Pad + -6750 Well: Plan: MPU M -19i Y Wellbore: MPU M -19i HALLIBURiON Plan: MPU M -19i wp08 5p®rry Orilh.q End Du : 10674.09' MD, 3652.7 V TVD CASING DETAILS TVD TVDSS MD Size Name 3655.00 3596.20 9035.42 9-5/8 9 5/8" x 12 1/4" 3782.00 3723.20 17448.66 4-1/2 4 1/2" x 8 1/2" REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M-1 9i, True North Vertical (ND) Reference: MPU M-19 Planned RKB @ 58.80usR Measured Depth Reference: MPU M-19 Planned RKB @ 58.80usfi Calculation Method: Minimum Curvature -12750 -13500 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usff/in) Start Dir 4°/100' : 7644' MD, 3353.47TVD C / -6000 End Dir : 8735.42' MD, 3570.05' TVD 7 ' p StartDir 4°/100' : 906542' MD, 3598.81TVD O v1 End Dv 9141.19' MD, 3603.42'TVD + -6750 Stan Dir 4°/100': 9488.49'MD, 3615.357VD Y 95/8"x121/4"----- ,-� '� -End Dir : 9495.23' MD, 3615.57' TVD 70 C ^ M-19 wp07 Heel Start Dir 4°/100';10595.23' MD, 3648.2TVD -7500 End Du : 10674.09' MD, 3652.7 V TVD Starr Dir 4°/100': 10907.66'MD, 3672.47TVD - - End Dir : 10996.53' MD, 3677.24' TVD M-19 wp08 CPI ----- -8250 Start Dir 4°/100' : 12096.53' MD, 3702.2TVD _ End Dir : 12198 93' MD, 3700.86' TVD - - Stan Dir4°/100' : 12524.48' MD, 3684.98TVD -9000 M-19 wp08 CP2 - - - - - End Dir : 12596.88' MD, 3683.28' TVD MPU 5001 Start Dir 4°/100': 13696.88'MD, 3685.2TVD Buffer , End Dir' 13804.39' MD, 3689.42' TVD M-19 wp08 CP3 - _ _' _ - - Start Dir 4°/100' : 14002.64'MD, 3704.637VD -9750 -_ End Dir : 14097.65' MD, 3708.78' TVD MPUStan Du 4°/100' : 14997.65' MD, 3718.2'TVD Boundary M-19 wp08 CP4---- _ -_ _ _ ,-- End Dir :15109.31'MD. 3715.92'TVD -10500 _ Start Dir 4°/100' : 15301.5' MD. 3702 06TVD Start Dir 4o/100': 16198.16' MD, 3698.8TVD End Dir : 16288.15'MD, 3701.63'TVD -11250 M-19 wp08 CPS' -StartDir4°/100': 16516.17'MD, 3715.947VD End Dir : 16598.66' MD, 3718.75' TVD -12000 M-19 wpO8 ToeNVUM-19i wp08 4 1/2" x 8`1/2" -12750 -13500 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usff/in) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -19i Wellbore: MPU M -19i Design: MPU M-1 9i wp08 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -19i TVD Reference: MPU M-19 Planned RKB @ 58.80usft MD Reference: MPU M-19 Planned RKB @ 58.80usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: Northing: 6,027,877.65 usft Latitude: 70° 29' 13.905 N From: Map Easting: 533,363.92 usft Longitude: 149° 43' 38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M -19i Well Position +N/ -S 0.00 usft Northing: 6,027,765.55 usfi Latitude: 70° 29' 12.796 N +E/ -W 0.00 usft Easting: 533,513.82 usfi Longitude: 149° 43'33.890 W Position Uncertainty 0.50 usft Wellhead Elevation: usfi Ground Level: 25.10 usft Wellbore MPU M-1 9i Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2018 11/30/2019 16.34 80.94 57,406.00292064 Design MPU M-1 9i wp08 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I 33.70 0.00 0.00 124.50 10/29/2019 6:28:24PM Page 2 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Turn Project: Milne Point +N/ -S +E/ -W Site: M Pt Moose Pad Rate Well: Plan: MPU M -19i (usft) Wellbore: MPU M -19i (°1100usft) (°1100usft) Design: MPU M-1 9i Wp08 0.00 Plan Sections 0.00 0.00 0.00 Measured 0.00 0.00 Vertical Depth Inclination Azimuth Depth (usft) -9,20 (1) (usft) 33.70 0.00 0.00 33.70 450.00 0.00 0.00 450.00 640.00 5.70 167.00 639.69 2,325.55 73.12 167.41 1,868.12 7,644.00 73.12 167.41 3,412.27 8,735.42 85.00 124.50 3,628.85 9,035.42 85.00 124.50 3,655.00 9,065.42 85.00 124.50 3,657.61 9,141.19 88.03 124.50 3,662.22 9,488.49 88.03 124.50 3,674.15 9,495.23 88.30 124.50 3,674.37 10,595.23 88.30 124.50 3,707.00 10,674.09 85.15 124.50 3,711.51 10,907.66 85.15 124.50 3,731.27 10,996.53 88.70 124.50 3,736.04 12,096.53 88.70 124.50 3,761.00 12,198.93 92.80 124.50 3,759.66 12,524.48 92.80 124.50 3,743.78 12,596.88 89.90 124.50 3,742.08 13,696.88 89.90 124.50 3,744.00 13,804.39 85.60 124.50 3,748.22 14,002.64 85.60 124.50 3,763.43 14,097.65 89.40 124.50 3,767.58 14,997.65 89.40 124.50 3,777.00 15,109.31 93.87 124.50 3,773.82 15,301.50 93.87 124.50 3,760.86 15,398.16 90.00 124.50 3,757.60 16,198.16 90.00 124.50 3,757.60 16,288.15 86.40 124.50 3,760.43 16,516.17 86.40 124.50 3,774.74 16,598.66 89.70 124.50 3,777.55 17,448.66 89.70 124.50 3,782.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -19i MPU M-19 Planned RKB @ 58.80usft MPU M-19 Planned RKB @ 58.80usft True Minimum Curvature ND Dogleg Build Turn System +N/ -S +E/ -W Rate Rate Rate Tool Face usft (usft) (usft) (°1100usft) (°1100usft) (°1100usft) C) -25.10 0.00 0.00 0.00 0.00 0.00 0.00 391.20 0.00 0.00 0.00 0.00 0.00 0.00 580.89 -9,20 2.12 3.00 3.00 0.00 167.00 1,809.32 -994.22 222.78 4.00 4.00 0.02 0.43 3,353.47 -5,961.24 1,331.93 0.00 0.00 0.00 0.00 3,570.05 -6,820.81 1,922.62 4.00 1.09 -3.93 -79.28 3,596.20 -6,990.08 2,168.92 0.00 0.00 0.00 0.00 3,598.81 -7,007.01 2,193.55 0.00 0.00 0.00 0.00 3,603.42 -7,049.84 2,255.87 4.00 4.00 0.00 -0.02 3,615.35 -7,246.44 2,541.93 0.00 0.00 0.00 0.00 3,615.57 -7,250.25 2,547.47 4.00 4.00 0.02 0.24 3,648.20 -7,873.02 3,453.61 0.00 0.00 0.00 0.00 3,652.71 -7,917.61 3,518.49 4.00 -4.00 0.00 -180.00 3,672.47 -8,049.43 3,710.30 0.00 0.00 0.00 0.00 3,677.24 -8,099.68 3,783.41 4.00 4.00 0.00 0.00 3,702.20 -8,722,57 4,689.72 0.00 0.00 0.00 0.00 3,700.86 -8,780.55 4,774.08 4.00 4.00 0.00 -0.02 3,684.98 -8,964.72 5,042.07 0.00 0.00 0.00 0.00 3,683.28 -9,005.71 5,101.71 4.00 -4.00 0.00 179.97 3,685.20 -9,628.76 6,008.25 0.00 0.00 0.00 0.00 3,689.42 -9,689.59 6,096.76 4.00 -4.00 0.00 179.99 3,704.63 -9,801.56 6,259.66 0.00 0.00 0.00 0.00 3,708.78 -9,855.31 6,337.87 4.00 4.00 0.00 -0.01 3,718.20 -10,365.05 7,079.55 0.00 0.00 0.00 0.00 3,715.02 -10,428.25 7,171.50 4.00 4.00 0.00 0.00 3,702.06 -10,536.86 7,329.54 0.00 0.00 0.00 0.00 3,698.80 -10,591.56 7,409.13 4.00 -4.00 0.00 179.99 3,698.80 -11,044.69 8,068.43 0.00 0.00 0.00 0.00 3,701.63 -11,095.63 8,142.55 4.00 -4.00 0.00 -179.97 3,715.94 -11,224.52 8,330.10 0.00 0.00 0.00 0.00 3,718.75 -11,271.21 8,398.04 4.00 4.00 0.00 0.03 3,723.20 -11,752.65 9,098.54 0.00 0.00 0.00 0.00 10/29/2019 6:28:24PM Page 3 COMPASS 5000.15 Build 91 1 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -19i Wellbore: MPU M -19i Design: MPU M -19i wp08 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -19i MPU M-19 Planned RKB @ 58.80usft MPU M-19 Planned RKB @ 58.80usft True Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -25.10 33.70 0.00 0.00 33.70 -25.10 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 100.00 0.00 0.00 100.00 41.20 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 200.00 0.00 0.00 200.00 141.20 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 300.00 0.00 0.00 300.00 241.20 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 400.00 0.00 0.00 400.00 341.20 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 450.00 0.00 0.00 450.00 391.20 0.00 0.00 6,027,765.55 533,513.82 0.00 0.00 Start Dir 3'1100': 450' MD, 391.2'TVD 500.00 1.50 167.00 499.99 441.19 -0.64 0.15 6,027,764.91 533,513.97 3.00 0.48 600.00 4.50 167.00 599.85 541.05 -5.74 1.32 6,027,759.82 533,515.17 3.00 4.34 640.00 5.70 167.00 639.69 580.89 -9.20 2.12 6,027,756.36 533,515.99 3.00 6.96 Start Dir 4°/100' : 640' MD, 580.89'TVD 700.00 8.10 167.13 699.25 640.45 -16.23 3.74 6,027,749.34 533,517.63 4.00 12.27 800.00 12.10 167.23 797.68 738.88 -33.32 7.62 6,027,732.27 533,521.59 4.00 25.16 900.00 16.10 167.28 894.65 835.85 -57.08 13.00 6,027,708.54 533,527.07 4.00 43.04 1,000.00 20.10 167.31 989.68 930.88 -87.38 19.83 6,027,678.27 533,534.04 4.00 65.83 1,100.00 24.10 167.33 1,082.31 1,023.51 -124.08 28.09 6,027,641.61 533,542.46 4.00 93.42 1,200.00 28.10 167.35 1,172.10 1,113.30 -166.99 37.73 6,027,598.75 533,552.29 4.00 125.68 1,300.00 32.10 167.36 1,258.59 1,199.79 -215.92 48.71 6,027,549.88 533,563.49 4.00 162.44 1,400.00 36.10 167.37 1,341.38 1,282.58 -270.61 60.97 6,027,495.24 533,576.00 4.00 203.52 1,500.00 40.10 167.37 1,420.06 1,361.26 -330.81 74.46 6,027,435.11 533,589.76 4.00 248.73 1,600.00 44.10 167.38 1,494.24 1,435.44 -396.22 89.10 6,027,369.78 533,604.70 4.00 297.85 1,700.00 48.10 167.39 1,563.57 1,504.77 -466.52 104.84 6,027,299.55 533,620.75 4.00 350.64 1,800.00 52.10 167.39 1,627.70 1,568.90 -541.37 121.58 6,027,224.79 533,637.83 4.00 406.83 1,900.00 56.10 167.40 1,686.33 1,627.53 -620.40 139.26 6,027,145.84 533,655.86 4.00 466.17 2,000.00 60.10 167.40 1,739.16 1,680.36 -703.24 157.78 6,027,063.10 533,674.75 4.00 528.35 2,100.00 64.10 167.40 1,785.95 1,727.15 -789.47 177.05 6,026,976.96 533,694.40 4.00 593.07 2,200.00 68.10 167.41 1,826.45 1,767.65 -878.68 196.98 6,026,887.85 533,714.73 4.00 660.02 2,300.00 72.10 167.41 1,860.48 1,801.68 -970.43 217.47 6,026,796.21 533,735.64 4.00 728.88 2,325.55 73.12 167.41 1,868.12 1,809.32 -994.22 222.78 6,026,772.44 533,741.06 4.00 746.74 End Dir : 2325.55' MD, 1809.32' TVD 2,400.00 73.12 167.41 1,889.73 1,830.93 -1,063.75 238.31 6,026,702.99 533,756.90 0.00 798.91 2,500.00 73.12 167.41 1,918.77 1,859.97 -1,157.15 259.16 6,026,609.70 533,778.17 0.00 869.00 2,600.00 73.12 167.41 1,947.80 1,889.00 -1,250.54 280.02 6,026,516.41 533,799.44 0.00 939.08 2,700.00 73.12 167.41 1,976.84 1,918.04 -1,343.93 300.87 6,026,423.12 533,820.72 0.00 1,009.17 2,800.00 73.12 167.41 2,005.87 1,947.07 -1,437.32 321.73 6,026,329.83 533,841.99 0.00 1,079.25 2,900.00 73.12 167.41 2,034.90 1,976.10 -1,530.72 342.58 6,026,236.54 533,863.26 0.00 1,149.34 3,000.00 73.12 167.41 2,063.94 2,005.14 -1,624.11 363.44 6,026,143.26 533,884.54 0.00 1,219.42 3,100.00 73.12 167.41 2,092.97 2,034.17 -1,717.50 384.29 6,026,049.97 533,905.81 0.00 1,289.51 3,200.00 73.12 167.41 2,122.00 2,063.20 -1,810.89 405.15 6,025,956.68 533,927.08 0.00 1,359.59 3,300.00 73.12 167.41 2,151.04 2,092.24 -1,904.28 426.00 6,025,863.39 533,948.36 0.00 1,429.68 3,400.00 73.12 167.41 2,180.07 2,121.27 -1,997.68 446.86 6,025,770.10 533,969.63 0.00 1,499.76 3,500.00 73.12 167.41 2,209.11 2,150.31 -2,091.07 467.71 6,025,676.82 533,990.90 0.00 1,569.85 3,600.00 73.12 167.41 2,238.14 2,179.34 -2,184.46 488.57 6,025,583.53 534,012.18 0.00 1,639.93 3,700.00 73.12 167.41 2,267.17 2,208.37 -2,277.85 509.42 6,025,490.24 534,033.45 0.00 1,710.02 3,800.00 73.12 167.41 2,296.21 2,237.41 -2,371.25 530.28 6,025,396.95 534,054.72 0.00 1,780.10 10/29/2019 6:28.24PM Page 4 COMPASS 5000.15 Build 91 Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-1 9i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-19 Planned RKB @ 58.80usft Project: Milne Point MD Reference: MPU M-19 Planned RKB @ 58.80usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -19i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -19i (°) V) Design: MPU M-1 9i wp08 (usft) (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) V) (usft) usft (usft) (usft) (usft) (usft) 2,266.44 3,900.00 73.12 167.41 2,325.24 2,266.44 -2,464.64 551.13 6,025,303.66 534,076.00 0.00 1,850.19 4,000.00 73.12 167.41 2,354.28 2,295.48 -2,558.03 571.99 6,025,210.38 534,097.27 0.00 1,920.27 4,100.00 73.12 167.41 2,383.31 2,324.51 -2,651.42 592.84 6,025,117.09 534,118.54 0.00 1,990.36 4,200.00 73.12 167.41 2,412.34 2,353.54 -2,744.81 613.70 6,025,023.80 534,139.82 0.00 2,060.44 4,300.00 73.12 167.41 2,441.38 2,382.58 -2,838.21 634.55 6,024,930.51 534,161.09 0.00 2,130.53 4,400.00 73.12 167.41 2,470.41 2,411.61 -2,931.60 655.40 6,024,837.22 534,182.36 0.00 2,200.61 4,500.00 73.12 167.41 2,499.44 2,440.64 -3,024.99 676.26 6,024,743.93 534,203.64 0.00 2,270.70 4,600.00 73.12 167.41 2,528.48 2,469.68 -3,118.38 697.11 6,024,650.65 534,224.91 0.00 2,340.78 4,700.00 73.12 167.41 2,557.51 2,498.71 -3,211.78 717.97 6,024,557.36 534,246.18 0.00 2,410.87 4,800.00 73.12 167.41 2,586.55 2,527.75 -3,305.17 738.82 6,024,464.07 534,267.46 0.00 2,480.95 4,900.00 73.12 167.41 2,615.58 2,556.78 -3,398.56 759.68 6,024,370.78 534,288.73 0.00 2,551.04 5,000.00 73.12 167.41 2,644.61 2,585.81 -3,491.95 780.53 6,024,277.49 534,310.00 0.00 2,621.12 5,100.00 73.12 167.41 2,673.65 2,614.85 -3,585.35 801.39 6,024,184.21 534,331.28 0.00 2,691.21 5,200.00 73.12 167.41 2,702.68 2,643.88 -3,678.74 822.24 6,024,090.92 534,352.55 0.00 2,761.29 5,300.00 73.12 167.41 2,731.72 2,672.92 -3,772.13 843.10 6,023,997.63 534,373.82 0.00 2,831.38 5,400.00 73.12 167.41 2,760.75 2,701.95 -3,865.52 863.95 6,023,904.34 534,395.10 0.00 2,901.46 5,500.00 73.12 167.41 2,789.78 2,730.98 -3,958.91 884.81 6,023,811.05 534,416.37 0.00 2,971.55 5,600.00 73.12 167.41 2,818.82 2,760.02 -4,052.31 905.66 6,023,717.77 534,437.64 0.00 3,041.63 5,700.00 73.12 167.41 2,847.85 2,789.05 -4,145.70 926.52 6,023,624.48 534,458.92 0.00 3,111.72 5,800.00 73.12 167.41 2,876.88 2,818.08 -4,239.09 947.37 6,023,531.19 534,480.19 0.00 3,181.80 5,900.00 73.12 167.41 2,905.92 2,847.12 -4,332.48 968.23 6,023,437.90 534,501.46 0.00 3,251.89 6,000.00 73.12 167.41 2,934.95 2,876.15 -4,425.88 989.08 6,023,344.61 534,522.74 0.00 3,321.97 6,100.00 73.12 167.41 2,963.99 2,905.19 -4,519.27 1,009.94 6,023,251.33 534,544.01 0.00 3,392.06 6,200.00 73.12 167.41 2,993.02 2,934.22 -4,612.66 1,030.79 6,023,158.04 534,565.28 0.00 3,462.14 6,300.00 73.12 167.41 3,022.05 2,963.25 -4,706.05 1,051.65 6,023,064.75 534,586.56 0.00 3,532.23 6,400.00 73.12 167.41 3,051.09 2,992.29 -4,799.44 1,072.50 6,022,971.46 534,607.83 0.00 3,602.31 6,500.00 73.12 167.41 3,080.12 3,021.32 -4,892.84 1,093.36 6,022,878.17 534,629.10 0.00 3,672.40 6,600.00 73.12 167.41 3,109.16 3,050.36 -4,986.23 1,114.21 6,022,784.88 534,650.38 0.00 3,742.48 6,700.00 73.12 167.41 3,138.19 3,079.39 -5,079.62 1,135.06 6,022,691.60 534,671.65 0.00 3,812.57 6,800.00 73.12 167.41 3,167.22 3,108.42 -5,173.01 1,155.92 6,022,598.31 534,692.92 0.00 3,882.65 6,900.00 73.12 167.41 3,196.26 3,137.46 -5,266.41 1,176.77 6,022,505.02 534,714.20 0.00 3,952.74 7,000.00 73.12 167.41 3,225.29 3,166.49 -5,359.80 1,197.63 6,022,411.73 534,735.47 0.00 4,022.82 7,100.00 73.12 167.41 3,254.32 3,195.52 -5,453.19 1,218.48 6,022,318.44 534,756.74 0.00 4,092.91 7,200.00 73.12 167.41 3,283.36 3,224.56 -5,546.58 1,239.34 6,022,225.16 534,778.02 0.00 4,162.99 7,300.00 73.12 167.41 3,312.39 3,253.59 -5,639.97 1,260.19 6,022,131.87 534,799.29 0.00 4,233.08 7,400.00 73.12 167.41 3,341.43 3,282.63 -5,733.37 1,281.05 6,022,038.58 534,820.56 0.00 4,303.16 7,500.00 73.12 167.41 3,370.46 3,311.66 -5,826.76 1,301.90 6,021,945.29 534,841.84 0.00 4,373.25 7,600.00 73.12 167.41 3,399.49 3,340.69 -5,920.15 1,322.76 6,021,852.00 534,863.11 0.00 4,443.33 7,644.00 73.12 167.41 3,412.27 3,353.47 -5,961.24 1,331.93 6,021,810.96 534,872.47 0.00 4,474.17 Start Dir 411100': 7644' MD, 3353.47'TVD 7,700.00 73.55 165.12 3,428.33 3,369.53 -6,013.35 1,344.67 6,021,758.91 534,885.44 4.00 4,514.18 7,800.00 74.38 161.05 3,455.96 3,397.16 -6,105.28 1,372.64 6,021,667.12 534,913.82 4.00 4,589.30 7,900.00 75.28 157.01 3,482.14 3,423.34 -6,195.37 1,407.19 6,021,577.19 534,948.77 4.00 4,668.80 8,000.00 76.25 153.00 3,506.73 3,447.93 -6,283.20 1,448.14 6,021,489.56 534,990.11 4.00 4,752.29 8,100.00 77.29 149.04 3,529.63 3,470.83 -6,368.34 1,495.30 6,021,404.64 535,037.65 4.00 4,839.38 10/29/2019 6:28:24PM Page 5 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 -19i Wellbore: MPU M -19i Design: MPU M -19i wp08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -19i TVD Reference: MPU M-19 Planned RKB @ 58.80usft MD Reference: MPU M-19 Planned RKB @ 58.80usft North Reference: True Survey Calculation Method: Minimum Curvature 10/29/2019 6:28:24PM Page 6 COMPASS 5000.15 Build 91 Measured Map Vertical +E/ -W Northing Easting Depth Inclination Azimuth Depth TVDss +N/ -S 3,491.90 (usft) (1) (1) (usft) usft (usft) 1,607.29 8,200.00 78.38 145.10 3,550.70 3,491.90 -6,450.3E 535,214.97 8,300.00 79.53 141.20 3,569.86 3,511.06 -6,528.8E 5,214.92 8,400.00 80.73 137.32 3,587.01 3,528.21 -6,603.5C 6,020,974.33 8,500.00 81.96 133.47 3,602.07 3,543.27 -6,673.87 4.00 8,600.00 83.23 129.65 3,614.96 3,556.16 -6,739.64 2,057.74 8,700.00 84.53 125.84 3,625.62 3,566.82 -6,800.49 535,684.83 8,735.42 85.00 124.50 3,628.85 3,570.05 -6,820.81 5,746.69 End Dir : 8735.42' MD, 3570.05' TVD 6,020,769.19 535,738.70 0.00 8,800.00 85.00 124.50 3,634.48 3,575.68 -6,857.25 2,255.87 8,900.00 85.00 124.50 3,643.20 3,584.40 -6,913.67 535,849.79 9,000.00 85.00 124.50 3,651.91 3,593.11 -6,970.10 6,010.91 9,035.42 85.00 124.50 3,655.00 3,596.20 -6,990.08 vp 5?� 9 5/8" x 12 1/4" 0.00 6,199.29 2,547.48 6,020,527.57 536,093.69 9,065.42 85.00 124.50 3,657.61 3,598.81 -7,007.01 6,210.80 Start Dir 41/100': 9065.42' MD, 3598.81'TVD 0.00 6,310.75 9,100.00 86.38 124.50 3,660.21 3,601.41 -7,026.54 6,020,356.17 9,141.19 88.03 124.50 3,662.22 3,603.42 -7,049.84 0.00 End Dir : 9141.19' MD, 3603.42' TVD 536,510.74 0.00 6,710.58 9,200.00 88.03 124.50 3,664.24 3,605.44 -7,083.13 6,020,131.22 9,300.00 88.03 124.50 3,667.68 3,608.88 -7,139.74 0.00 9,400.00 88.03 124.50 3,671.11 3,612.31 -7,196.34 3,375.17 9,488.49 88.03 124.50 3,674.15 3,615.35 -7,246.43 537,002.53 Start Dir 40/100' : 9488.49' MD, 3615.35'TVD 6,019,906.26 537,006.47 4.00 9,495.23 88.30 124.50 3,674.37 3,615.57 -7,250.25 3,539.77 End Dir : 9495.23' MD, 3615.57' TVD 0.00 7,410.08 3,621.89 9,500.00 88.30 124.50 3,674.51 3,615.71 -7,252.95 537,259.98 9,600.00 88.30 124.50 3,677.48 3,618.68 -7,309.57 9,700.00 88.30 124.50 3,680.44 3,621.64 -7,366.18 9,800.00 88.30 124.50 3,683.41 3,624.61 -7,422.80 9,900.00 88.30 124.50 3,686.38 3,627.58 -7,479.41 10,000.00 88.30 124.50 3,689.34 3,630.54 -7,536.03 10,100.00 88.30 124.50 3,692.31 3,633.51 -7,592.64 10,200.00 88.30 124.50 3,695.28 3,636.48 -7,649.26 10,300.00 88.30 124.50 3,698.24 3,639.44 -7,705.87 10,400.00 88.30 124.50 3,701.21 3,642.41 -7,762.49 10,500.00 88.30 124.50 3,704.18 3,645.38 -7,819.11 10,595.23 88.30 124.50 3,707.00 3,648.20 -7,873.02 Start Dir 4°/100' : 10595.23' MD, 3648.2'TVD 10,600.00 88.11 124.50 3,707.15 3,648.35 -7,875.72 10,674.09 85.15 124.50 3,711.51 3,652.71 -7,917.61 End Dir : 10674.09' MD, 3652.71' TVD 10,700.00 85.15 124.50 3,713.70 3,654.90 -7,932.23 10,800.00 85.15 124.50 3,722.16 3,663.36 -7,988.67 10,907.66 85.15 124.50 3,731.27 3,672.47 -8,049.43 Start Dir 41/100' :10907.66' MD. 3672.47'TVD 10/29/2019 6:28:24PM Page 6 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,491.90 1,548.43 6,021,322.87 535,091.15 4.00 4,929.63 1,607.29 6,021,244.62 535,150.35 4.00 5,022.61 1,671.58 6,021,170.30 535,214.97 4.00 5,117.86 1,740.99 6,021,100.25 535,284.69 4.00 5,214.92 1,815.18 6,021,034.82 535,359.17 4.00 5,313.31 1,893.79 6,020,974.33 535,438.05 4.00 5,412.56 1,922.62 6,020,954.15 535,466.97 4.00 5,447.83 1,975.64 6,020,917.95 535,520.14 0.00 5,512.16 2,057.74 6,020,861.90 535,602.49 0.00 5,611.78 2,139.84 6,020,805.85 535,684.83 0.00 5,711.40 2,168.92 6,020,786.00 535,714.00 0.00 5,746.69 2,193.55 6,020,769.19 535,738.70 0.00 5,776.57 2,221.97 6,020,749.79 535,767.20 4.00 5,811.06 2,255.87 6,020,726.64 535,801.21 4.00 5,852.20 2,304.31 6,020,693.57 535,849.79 0.00 5,910.97 2,386.67 6,020,637.34 535,932.40 0.00 6,010.91 2,469.04 6,020,581.12 536,015.02 0.00 6,110.85 2,541.92 6,020,531.36 536,088.12 0.00 6,199.29 2,547.48 6,020,527.57 536,093.69 3.99 6,206.03 2,551.41 6,020,524.89 536,097.63 0.00 6,210.80 2,633.78 6,020,468.65 536,180.25 0.00 6,310.75 2,716.16 6,020,412.41 536,262.87 0.00 6,410.71 2,798.53 6,020,356.17 536,345.50 0.00 6,510.66 2,880.91 6,020,299.93 536,428.12 0.00 6,610.62 2,963.29 6,020,243.69 536,510.74 0.00 6,710.58 3,045.66 6,020,187.46 536,593.36 0.00 6,810.53 3,128.04 6,020,131.22 536,675.99 0.00 6,910.49 3,210.42 6,020,074.98 536,758.61 0.00 7,010.44 3,292.79 6,020,018.74 536,841.23 0.00 7,110.40 3,375.17 6,019,962.50 536,923.85 0.00 7,210.36 3,453.62 6,019,908.95 537,002.53 0.00 7,305.54 3,457.54 6,019,906.26 537,006.47 4.00 7,310.31 3,518.49 6,019,864.66 537,067.60 4.00 7,384.26 3,539.77 6,019,850.13 537,088.94 0.00 7,410.08 3,621.89 6,019,794.07 537,171.31 0.00 7,509.72 3,710.29 6,019,733.71 537,259.98 0.00 7,617.00 10/29/2019 6:28:24PM Page 6 COMPASS 5000.15 Build 91 Planned Survey Measured Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-1 9i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-19 Planned RKB @ 58.80usft Project: Milne Point MD Reference: MPU M-19 Planned RKB @ 58.80usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -19i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -19i (°) (°) Design: MPU M-1 9i wp08 usft (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,677.24 10,996.53 88.70 124.50 3,736.04 3,677.24 -8,099.69 3,783.42 6,019,683.79 537,333.32 4.00 7,705.72 End Dir : 10996.53' MD, 3677.24' TVD 11,000.00 88.70 124.50 3,736.12 3,677.32 -8,101.65 3,786.27 6,019,681.84 537,336.19 0.00 7,709.19 11,100.00 88.70 124.50 3,738.39 3,679.59 -8,158.28 3,868.67 6,019,625.59 537,418.82 0.00 7,809.17 11,200.00 88.70 124.50 3,740.66 3,681.86 -8,214.90 3,951.06 6,019,569.34 537,501.46 0.00 7,909.14 11,300.00 88.70 124.50 3,742.93 3,684.13 -8,271.53 4,033.45 6,019,513.10 537,584.10 0.00 8,009.12 11,400.00 88.70 124.50 3,745.20 3,686.40 -8,328.16 4,115.84 6,019,456.85 537,666.74 0.00 8,109.09 11,500.00 88.70 124.50 3,747.47 3,688.67 -8,384.78 4,198.23 6,019,400.60 537,749.37 0.00 8,209.06 11,600.00 88.70 124.50 3,749.74 3,690.94 -8,441.41 4,280.62 6,019,344.35 537,832.01 0.00 8,309.04 11,700.00 88.70 124.50 3,752.00 3,693.20 -8,498.03 4,363.01 6,019,288.10 537,914.65 0.00 8,409.01 11,800.00 88.70 124.50 3,754.27 3,695.47 -8,554.66 4,445.41 6,019,231.85 537,997.29 0.00 8,508.99 11,900.00 88.70 124.50 3,756.54 3,697.74 -8,611.29 4,527.80 6,019,175.60 538,079.92 0.00 8,608.96 12,000.00 88.70 124.50 3,758.81 3,700.01 -8,667.91 4,610.19 6,019,119.36 538,162.56 0.00 8,708.94 12,096.53 88.70 124.50 3,761.00 3,702.20 -8,722.57 4,689.72 6,019,065.06 538,242.33 0.00 8,805.44 Start Dir 4°/100' : 12096.53' MD, 3702.2'TVD 12,100.00 88.84 124.50 3,761.07 3,702.27 -8,724.54 4,692.58 6,019,063.11 538,245.20 4.00 8,808.91 12,198.93 92.80 124.50 3,759.66 3,700.86 -8,780.55 4,774.09 6,019,007.46 538,326.95 4.00 8,907.81 End Dir : 12198.93' MD, 3700.86' TVD 12,200.00 92.80 124.50 3,759.61 3,700.81 -8,781.16 4,774.97 6,019,006.86 538,327.83 0.00 8,908.88 12,300.00 92.80 124.50 3,754.73 3,695.93 -8,837.73 4,857.28 6,018,950.67 538,410.40 0.00 9,008.76 12,400.00 92.80 124.50 3,749.86 3,691.06 -8,894.30 4,939.60 6,018,894.47 538,492.96 0.00 9,108.64 12,500.00 92.80 124.50 3,744.98 3,686.18 -8,950.87 5,021.91 6,018,838.28 538,575.52 0.00 9,208.52 12,524.48 92.80 124.50 3,743.78 3,684.98 -8,964.72 5,042.07 6,018,824.52 538,595.73 0.00 9,232.97 Start Dir 4°/100' : 12524.48' MD, 3684.98'TVD 12,596.88 89.90 124.50 3,742.08 3,683.28 -9,005.71 5,101.71 6,018,783.80 538,655.55 4.00 9,305.35 End Dir : 12596.88' MD, 3683.28' TVD 12,600.00 89.90 124.50 3,742.09 3,683.29 -9,007.48 5,104.28 6,018,782.05 538,658.13 0.00 9,308.47 12,700.00 89.90 124.50 3,742.26 3,683.46 -9,064.12 5,186.69 6,018,725.79 538,740.79 0.00 9,408.47 12,800.00 89.90 124.50 3,742.43 3,683.63 -9,120.76 5,269.11 6,018,669.52 538,823.45 0.00 9,508.46 12,900.00 89.90 124.50 3,742.61 3,683.81 -9,177.40 5,351.52 6,018,613.26 538,906.11 0.00 9,608.46 13,000.00 89.90 124.50 3,742.78 3,683.98 -9,234.04 5,433.93 6,018,557.00 538,988.77 0.00 9,708.46 13,100.00 89.90 124.50 3,742.96 3,684.16 -9,290.68 5,516.34 6,018,500.73 539,071.43 0.00 9,808.46 13,200.00 89.90 124.50 3,743.13 3,684.33 -9,347.32 5,598.76 6,018,444.47 539,154.08 0.00 9,908.46 13,300.00 89.90 124.50 3,743.31 3,684.51 -9,403.96 5,681.17 6,018,388.21 539,236.74 0.00 10,008.46 13,400.00 89.90 124.50 3,743.48 3,684.68 -9,460.61 5,763.58 6,018,331.94 539,319.40 0.00 10,108.46 13,500.00 89.90 124.50 3,743.66 3,684.86 -9,517.25 5,845.99 6,018,275.68 539,402.06 0.00 10,208.46 13,600.00 89.90 124.50 3,743.83 3,685.03 -9,573.89 5,928.41 6,018,219.42 539,484.72 0.00 10,308.46 13,696.88 89.90 124.50 3,744.00 3,685.20 -9,628.76 6,008.25 6,018,164.91 539,564.80 0.00 10,405.34 Start Dir 4°/100' : 13696.88' MD, 3685.2'TVD 13,700.00 89.78 124.50 3,744.01 3,685.21 -9,630.53 6,010.82 6,018,163.16 539,567.38 4.00 10,408.46 13,804.39 85.60 124.50 3,748.22 3,689.42 -9,689.59 6,096.76 6,018,104.48 539,653.58 4.00 10,512.75 End Dir : 13804.39' MD, 3689.42' TVD 13,900.00 85.60 124.50 3,755.56 3,696.76 -9,743.59 6,175.32 6,018,050.85 539,732.37 0.00 10,608.07 14,002.64 85.60 124.50 3,763.43 3,704.63 -9,801.55 6,259.66 6,017,993.27 539,816.96 0.00 10,710.41 Start Dir 4°/100' : 14002.64' MD, 3704.63'TVD 10/2912019 6:28:24PM Page 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 -19i Wellbore: MPU M -19i Design: MPU M -19i wp08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -19i TVD Reference: MPU M-19 Planned RKB @ 58.80usft MD Reference: MPU M-19 Planned RKB @ 58.80usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical 13,306.46 Depth Inclination Azimuth Depth TVDss +N/ -S (usft) V) V) (usft) usft (usft) 14,097.65 89.40 124.50 3,767.58 3,708.78 -9,855.31 End Dir : 14097.65' MD, 3708.78' TVD 6,339.81 14,100.00 89.40 124.50 3,767.60 3,708.80 -9,856.64 14,200.00 89.40 124.50 3,768.65 3,709.85 -9,913.28 14,300.00 89.40 124.50 3,769.69 3,710.89 -9,969.91 14,400.00 89.40 124.50 3,770.74 3,711.94 -10,026.55 14,500.00 89.40 124.50 3,771.79 3,712.99 -10,083.19 14,600.00 89.40 124.50 3,772.84 3,714.04 -10,139.83 14,700.00 89.40 124.50 3,773.88 3,715.08 -10,196.46 14,800.00 89.40 124.50 3,774.93 3,716.13 -10,253.10 14,900.00 89.40 124.50 3,775.98 3,717.18 -10,309.74 14,997.65 89.40 124.50 3,777.00 3,718.20 -10,365.05 Start Dir 4°/100' : 14997.65' MD, 3718.2'TVD 15,000.00 89.49 124.50 3,777.02 3,718.22 -10,366.38 15,109.31 93.87 124.50 3,773.82 3,715.02 -10,428.25 End Dir : 15109.31' MD, 3715.02' TVD 0.00 15,200.00 93.87 124.50 3,767.70 3,708.90 -10,479.50 15,301.50 93.87 124.50 3,760.86 3,702.06 -10,536.86 Start Dir 4°/100' : 15301.5' MD, 3702.06'TVD 15,398.16 90.00 124.50 3,757.60 3,698.80 -10,591.56 End Dir : 15398.16' MD, 3698.8' TVD 0.00 15,400.00 90.00 124.50 3,757.60 3,698.80 -10,592.61 15,500.00 90.00 124.50 3,757.60 3,698.80 -10,649.25 15,600.00 90.00 124.50 3,757.60 3,698.80 -10,705.89 15,700.00 90.00 124.50 3,757.60 3,698.80 -10,762.53 15,800.00 90.00 124.50 3,757.60 3,698.80 -10,819.17 15,900.00 90.00 124.50 3,757.60 3,698.80 -10,875.81 16,000.00 90.00 124.50 3,757.60 3,698.80 -10,932.45 16,100.00 90.00 124.50 3,757.60 3,698.80 -10,989.09 16,198.16 90.00 124.50 3,757.60 3,698.80 -11,044.69 Start Dir 4°/100' : 16198.16' MD, 3698.8'TVD 16,200.00 89.93 124.50 3,757.60 3,698.80 -11,045.73 16,288.15 86.40 124.50 3,760.43 3,701.63 -11,095.63 End Dir : 16288.15' MD, 3701.63' TVD 13,206.55 16,300.00 86.40 124.50 3,761.17 3,702.37 -11,102.32 16,400.00 86.40 124.50 3,767.45 3,708.65 -11,158.85 16,500.00 86.40 124.50 3,773.73 3,714.93 -11,215.38 16,516.17 86.40 124.50 3,774.74 3,715.94 -11,224.52 Start Dir 4°/100' : 16516.17' MD, 3715.94'TVD 16,598.66 89.70 124.50 3,777.55 3,718.75 -11,271.21 End Dir : 16598.66' MD, 3718.75' TVD 16,600.00 89.70 124.50 3,777.56 3,718.76 -11,271.96 16,700.00 89.70 124.50 3,778.08 3,719.28 -11,328.60 16,800.00 89.70 124.50 3,778.60 3,719.80 -11,385.24 16,900.00 89.70 124.50 3,779.13 3,720.33 -11,441.88 8,399.14 Map Map 0.01 13,306.46 +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,708.78 13,506.46 6,337.87 6,017,939.87 539,895.41 4.00 10,805.31 6,339.81 6,017,938.55 539,897.35 0.01 10,807.66 6,422.22 6,017,882.29 539,980.00 0.00 10,907.66 6,504.62 6,017,826.03 540,062.66 0.00 11,007.65 6,587.03 6,017,769.77 540,145.31 0.00 11,107.65 6,669.44 6,017,713.51 540,227.97 0.00 11,207.64 6,751.85 6,017,657.25 540,310.62 0.00 11,307.64 6,834.26 6,017,600.99 540,393.28 0.00 11,407.63 6,916.66 6,017,544.73 540,475.93 0.00 11,507.62 6,999.07 6,017,488.47 540,558.58 0.00 11,607.62 7,079.54 6,017,433.53 540,639.30 0.00 11,705.26 7,081.48 6,017,432.21 540,641.24 3.99 11,707.61 7,171.51 6,017,370.75 540,731.53 4.00 11,816.85 7,246.08 6,017,319.84 540,806.33 0.00 11,907.33 7,329.53 6,017,262.87 540,890.03 0.00 12,008.60 7,409.13 6,017,208.52 540,969.87 4.00 12,105.19 7,410.65 6,017,207.49 540,971.39 0.00 12,107.03 7,493.06 6,017,151.23 541,054.05 0.00 12,207.03 7,575.48 6,017,094.96 541,136.71 0.00 12,307.03 7,657.89 6,017,038.70 541,219.37 0.00 12,407.03 7,740.30 6,016,982.44 541,302.03 0.00 12,507.03 7,822.71 6,016,926.17 541,384.69 0.00 12,607.03 7,905.13 6,016,869.91 541,467.35 0.00 12,707.03 7,987.54 6,016,813.65 541,550.00 0.00 12,807.03 8,068.44 6,016,758.42 541,631.14 0.00 12,905.19 8,069.95 6,016,757.38 541,632.66 4.01 12,907.03 8,142.55 6,016,707.82 541,705.48 4.00 12,995.12 8,152.30 6,016,701.17 541,715.25 0.00 13,006.95 8,234.55 6,016,645.02 541,797.75 0.00 13,106.75 8,316.80 6,016,588.87 541,880.25 0.00 13,206.55 8,330.10 6,016,579.79 541,893.59 0.00 13,222.69 8,398.03 6,016,533.41 541,961.73 4.00 13,305.12 8,399.14 6,016,532.66 541,962.83 0.01 13,306.46 8,481.55 6,016,476.40 542,045.49 0.00 13,406.46 8,563.96 6,016,420.13 542,128.15 0.00 13,506.46 8,646.37 6,016,363.87 542,210.81 0.00 13,606.46 101292019 6:28:24PM Page 8 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -19i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-19 Planned RKB @ 58.80usft Project: Milne Point MD Reference: MPU M-19 Planned RKB @ 58.80usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -19i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -19i Design: MPU M -19i wp08 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) C) (usft) usft (usft) (usft) (usft) (usft) 3,720.85 17,000.00 89.70 124.50 3,779.65 3,720.85 -11,498.52 8,728.78 6,016,307.61 542,293.46 0.00 13,706.46 17,100.00 89.70 124.50 3,780.17 3,721.37 -11,555.16 8,811.20 6,016,251.35 542,376.12 0.00 13,806.45 17,200.00 89.70 124.50 3,780.70 3,721.90 -11,611.80 8,893.61 6,016,195.08 542,458.78 0.00 13,906.45 17,300.00 89.70 124.50 3,781.22 3,722.42 -11,668.44 8,976.02 6,016,138.82 542,541.44 0.00 14,006.45 17,400.00 89.70 124.50 3,781.75 3,722.95 -11,725.08 9,058.43 6,016,082.56 542,624.10 0.00 14,106.45 17,448.66 89.70 124.50 3,782.00 3,723.20 -11,752.64 9,098.53 6,016,055.18 542,664.32 0.00 14,155.11 Total Depth : 17448.66' MD, 3723.2' TVD - 4 1/2" x 8 1/2" Targets Target Name hittmiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (1) V) (usft) (usft) (usft) (usft) (usft) M-19 wp08 CP4 0.00 0.00 3,777.00 -10,365.05 7,079.55 6,017,433.53 540,639.30 - plan hits target center - Point M-19 wp08 CP1 0.00 0.00 3,707.00 -7,873.02 3,453.61 6,019,908.95 537,002.53 plan hits target center Point M-19 wp08 Toe 0.00 0.00 3,782.00 -11,752.65 9,098.54 6,016,055.18 542,664.32 - plan hits target center - Point M-19 wp08 CP3 0.00 0.00 3,744.00 -9,628.76 6,008.25 6,018,164.91 539,564.80 - plan hits target center - Point M-19 wp08 CP2 0.00 0.00 3,761.00 -8,722.57 4,689.72 6,019,065.06 538,242.33 plan hits target center Point M-19 wp07 Heel 0.00 0.00 3,655.00 -6,990.08 2,168.92 6,020,786.00 535,714.00 - plan hits target center - Circle (radius 30.00) M-19wp08CP5 0.00 0.00 3,757.60 -11,044.69 8,068.43 6,016,758.42 541,631.14 plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 9,035.42 3,655.00 9 5/8" x 12 1/4" 9-5/8 12-1/4 17,448.66 3,782.00 4 1/2" x 8 1/2" 4-1/2 8-1/2 10/29/2019 6:28.24PM Page 9 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -19i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-19 Planned RKB @ 58.80usft Project: Milne Point MD Reference: MPU M-19 Planned RKB @ 58.80usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-1 9i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -19i Design: MPU M -19i wp08 Plan Annotations Measured Vertical Local Coordinates Depth Depth +Nl-S +El -W (usft) (usft) (usft) (usft) Comment 450.00 450.00 0.00 0.00 Start Dir 31/100': 450' MD, 391.2'TVD 640.00 639.69 -9.20 2.12 Start Dir 41/100': 640' MD, 580.89'TVD 2,325.55 1,868.12 -994.22 222.78 End Dir : 2325.55' MD, 1809.32' TVD 7,644.00 3,412.27 -5,961.24 1,331.93 Start Dir 4°/100' : 7644' MD, 3353.47'TVD 8,735.42 3,628.85 -6,820.81 1,922.62 End Dir : 8735.42' MD, 3570.05'TVD 9,065.42 3,657.61 -7,007.01 2,193.55 Start Dir 4°/100' : 9065.42' MD, 3598.81'TVD 9,141.19 3,662.22 -7,049.84 2,255.87 End Dir : 9141.19' MD, 3603.42' TVD 9,488.49 3,674.15 -7,246.43 2,541.92 Start Dir 4°/100' : 9488.49' MD, 3615.35'TVD 9,495.23 3,674.37 -7,250.25 2,547.48 End Dir : 9495.23' MD, 3615.57' TVD 10,595.23 3,707.00 -7,873.02 3,453.62 Start Dir 40/100' : 10595.23' MD, 3648.2'TVD 10,674.09 3,711.51 -7,917.61 3,518.49 End Dir : 10674.09' MD, 3652.71' TVD 10,907.66 3,731.27 -8,049.43 3,710.29 Start Dir 41/100' : 10907.66' MD, 3672.47'TVD 10,996.53 3,736.04 -8,099.69 3,783.42 End Dir : 10996.53' MD, 3677.24' TVD 12,096.53 3,761.00 -8,722.57 4,689.72 Start Dir 40/100' : 12096.53' MD, 3702.2'TVD 12,198.93 3,759.66 -8,780.55 4,774.09 End Dir : 12198.93' MD, 3700.86' TVD 12,524.48 3,743.78 -8,964.72 5,042.07 Start Dir 41/100' : 12524.48' MD, 3684.98'TVD 12,596.88 3,742.08 -9,005.71 5,101.71 End Dir : 12596.88' MD, 3683.28' TVD 13,696.88 3,744.00 -9,628.76 6,008.25 Start Dir 40/100' : 13696.88' MD, 3685.2'TVD 13,804.39 3,748.22 -9,689.59 6,096.76 End Dir : 13804.39' MD, 3689.42' TVD 14,002.64 3,763.43 -9,801.55 6,259.66 Start Dir 41/100' : 14002.64' MD, 3704.63'TVD 14,097.65 3,767.58 -9,855.31 6,337.87 End Dir : 14097.65' MD, 3708.78' TVD 14,997.65 3,777.00 -10,365.05 7,079.54 Start Dir 41/100' : 14997.65' MD, 3718.2'TVD 15,109.31 3,773.82 -10,428.25 7,171.51 End Dir : 15109.31' MD, 3715.02' TVD 15,301.50 3,760.86 -10,536.86 7,329.53 Start Dir 41/100' : 15301.5' MD, 3702.06'TVD 15,398.16 3,757.60 -10,591.56 7,409.13 End Dir : 15398.16' MD, 3698.8' TVD 16,198.16 3,757.60 -11,044.69 8,068.44 Start Dir 4°/100' : 16198.16' MD, 3698.8'TVD 16,288.15 3,760.43 -11,095.63 8,142.55 End Dir : 16288.15' MD, 3701.63' TVD 16,516.17 3,774.74 -11,224.52 8,330.10 Start Dir 41/100' : 16516.17' MD, 3715.94'TVD 16,598.66 3,777.55 -11,271.21 8,398.03 End Dir : 16598.66' MD, 3718.75' TVD 17,448.66 3,782.00 -11,752.64 9,098.53 Total Depth : 17448.66' MD, 3723.2' TVD 10/29/2019 6:28.24PM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -19i MPU M -19i MPU M -19i wP08 Sperry Drilling Services Clearance Summary Anticollision Report 29 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i wp08 Well Coordinates: 6,027,765.55 N, 533,513.82 E (70° 29' 12.80" N, 149° 43' 33.89" W) Datum Height: MPU M-19 Planned RKB @ 58.80usft Scan Range: 33.70 to 9,035.42 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: • • = Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M-1 9i - MPU M-1 9i wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M-191 wp08 Scan Range: 33.70 to 9,035.42 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M Pt M Pad M -01 -M -01A -M -01A M-01 - M -01A- M -01A M-01 - M -01A -M -01A 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-04 - MPU M-04 - MPU M-04 MPU M -04 -MPU M -04 -MPU M-04 MPU M-04 - MPU M-04 - MPU M-04 MPU M-06 - MPU M-06 - MPU M-06 MPU M-06 - MPU M-06 - MPU M-06 MPU M-06 - MPU M-06 - MPU M-06 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 -17i - MPU MAT - MPU M -17i MPU M -17i - MPU MAT - MPU M -17i MPU M -17i - MPU M -17i - MPU M-171 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 -18P81 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M -18 -MPU M-18PB1 -MPU M-18PB1 7,008.70 594.80 7,008.70 404.20 4,780.31 3.121 Clearance Factor Pass - 7,108.70 591.00 7,108.70 402.62 4,871.85 3.137 Ellipse Separation Pass - 7,252.25 589.30 7,252.25 406.60 5,009.77 3.225 Centre Distance Pass - 683.56 187.54 683.56 183.10 703.94 42.215 Centre Distance Pass - 708.70 187.60 708.70 183.01 730.90 40.913 Ellipse Separation Pass - 3,958.70 675.17 3,958.70 604.56 4,028.58 9.562 Clearance Factor Pass - 804.84 145.14 804.84 140.13 832.12 28.942 Centre Distance Pass - 808.70 145.14 808.70 140.11 836.09 28.809 Ellipse Separation Pass - 1,183.70 175.22 1,183.70 167.58 1,215.68 22.953 Clearance Factor Pass - 446.58 208.74 446.58 205.65 446.39 67.478 Centre Distance Pass - 458.70 208.75 458.70 205.59 458.08 66.122 Ellipse Separation Pass - 858.70 256.53 858.70 251.30 809.79 49.052 Clearance Factor Pass - 385.62 205.79 385.62 203.03 385.96 74.728 Centre Distance Pass - 433.70 205.92 433.70 202.92 432.83 68.490 Ellipse Separation Pass - 3,033.70 560.24 3,033.70 508.78 2,914.18 10.886 Clearance Factor Pass - 405.52 119.30 405.52 116.32 405.62 40.040 Centre Distance Pass - 433.70 119.36 433.70 116.23 433.25 38.113 Ellipse Separation Pass - 3,233.70 370.45 3,233.70 309.85 3,148.36 6.113 Clearance Factor Pass - 538.15 86.04 538.15 82.36 537.49 23.362 Centre Distance Pass - 558.70 86.08 558.70 82.29 557.52 22.730 Ellipse Separation Pass - 3,908.70 223.85 3,908.70 144.75 3,861.86 2.830 Clearance Factor Pass - 538.15 86.04 538.15 82.36 537.49 23.362 Centre Distance Pass - 558.70 86.08 558.70 82.29 557.52 22.730 Ellipse Separation Pass - 3,908.70 223.85 3,908.70 144.73 3,861.86 2.829 Clearance Factor Pass - 29 October, 2019 - 18:32 Page 2 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-1 9i - MPU M-1 9i wp08 33.70 194.92 33.70 193.50 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 138.076 Centre Distance Pass - MPU M-22 - MPU M-22 - MPU M-22 308.70 195.48 Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i Wp08 193.10 307.79 82.291 Ellipse Separation Pass - MPU M-22 - MPU M-22 - MPU M-22 Scan Range: 33.70 to 9,035.42 usft. Measured Depth. 1,611.44 6,733.70 1,461.01 9,673.30 10.713 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M -22P81 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 193.50 33.95 138.076 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Pass - Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 607.14 6.870 Centre Distance MPU M-18 - MPU M-18PB2 - MPU M-18PB2 538.15 86.04 538.15 82.36 537.49 23.362 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 558.70 86.08 558.70 82.29 557.52 22.730 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 3,908.70 223.85 3,908.70 144.75 3,861.86 2.830 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 7,764.44 301.28 7,764.44 161.11 11,283.66 2.149 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 7,883.70 312.10 7,883.70 148.10 11,383.28 1.903 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 7,983.70 336.10 7,983.70 155.73 11,474.59 1.863 Clearance Factor Pass - MPU M-20- MPU M-20PB1 - MPU M-20PB1 7,764.44 301.28 7,764.44 161.12 11,283.66 2.150 Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 7,883.70 312.10 7,883.70 148.11 11,383.28 1.903 Ellipse Separation Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 7,983.70 336.10 7,983.70 155.74 11,474.59 1.863 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 7,764.44 301.28 7,764.44 161.11 11,283.66 2.149 Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 7,883.70 312.10 7,883.70 148.10 11,383.28 1.903 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 7,983.70 336.10 7,983.70 155.73 11,474.59 1.863 Clearance Factor Pass - MPU M-22 - MPU M-22 - MPU M-22 33.70 194.92 33.70 193.50 33.95 138.076 Centre Distance Pass - MPU M-22 - MPU M-22 - MPU M-22 308.70 195.48 308.70 193.10 307.79 82.291 Ellipse Separation Pass - MPU M-22 - MPU M-22 - MPU M-22 6,733.70 1,611.44 6,733.70 1,461.01 9,673.30 10.713 Clearance Factor Pass - MPU M-22 - MPU M-22PB1 - MPU M -22P81 33.70 194.92 33.70 193.50 33.95 138.076 Centre Distance Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 308.70 195.48 308.70 193.10 307.79 82.291 Ellipse Separation Pass - MPU M-22 - MPU M-22PB1 - MPU M-22PB1 6,733.70 1,611.44 6,733.70 1,460.98 9,673.30 10.710 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 607.42 29.48 607.42 25.19 607.14 6.870 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 633.70 29.57 633.70 25.14 633.32 6.671 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 683.70 30.54 683.70 25.83 683.00 6.483 Clearance Factor Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOf 332.50 59.82 332.50 57.02 332.40 21.310 Centre Distance Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOf 408.70 59.93 408.70 56.73 408.45 18.704 Ellipse Separation Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOf 783.70 77.53 783.70 72.24 776.57 14.642 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 398.91 29.60 398.91 26.32 398.88 9.031 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 433.70 29.70 433.70 26.07 433.57 8.171 Ellipse Separation Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 683.70 40.66 683.70 34.53 680.25 6.627 Clearance Factor Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,132.72 40.67 1,132.72 33.01 1,162.24 5.310 Centre Distance Pass - Plan :MPU M-07WSW- MPU M-07(WSW)-M-07WS 1,133.70 40.67 1,133.70 33.00 1,163.15 5.301 Ellipse Separation Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,158.70 42.18 1,158.70 34.07 1,186.27 5.204 Clearance Factor Pass - 29 October, 2019 - 18:32 Page 3 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-1 9i - MPU WI 9i wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-191- MPU M -19i - MPU M-191 Wp08 Scan Range: 33.70 to 9,035.42 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 386.00 240.20 386.00 236.66 385.90 67.801 Centre Distance Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 433.70 240.32 433.70 236.53 431.89 63.332 Ellipse Separation Pass - Plan MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 3,683.70 729.08 3,683.70 656.14 3,486.97 9.996 Clearance Factor Pass - Plan: MPU M-17iP2 - M112 Phase 2 - M -17i P2 wp02 261.46 150.20 261.46 147.32 261.36 52.234 Centre Distance Pass - Plan MPU MAT P2 - M112 Phase 2 - M -17i P2 wp02 308.70 150.27 308.70 147.15 307.85 48.222 Ellipse Separation Pass - Plan: MPU M -17i P2 - M112 Phase 2 - M-171 P2 wp02 4,433.70 587.08 4,433.70 483.19 4,214.78 5.651 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 283.70 60.19 283.70 57.64 279.60 23.648 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 333.70 60.30 333.70 57.50 329.32 21.540 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 5,783.70 420.04 5,783.70 268.19 5,602.07 2.766 Clearance Factor Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl S - - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl -, Plan: MPU M -19i P2 -Slot 27 - M -19i P2 - M-191 P2 wl Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 7,721.88 266.30 7,721.88 106.65 10,601.46 1.668 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 7,858.70 278.85 7,858.70 90.72 10,722.86 1.482 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 7,883.70 283.90 7,883.70 91.47 10,744.61 1.475 Clearance Factor Pass - Plan: MPU M -21i P2 - M -21i Phase 2 - M -21i P2 wp02 411.00 244.29 411.00 240.60 410.90 66.375 Centre Distance Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 433.70 244.30 433.70 240.49 433.01 64.224 Ellipse Separation Pass - Plan: MPU M -21i P2 - M -21i Phase 2 - M -21i P2 wp02 7,733.70 1,079.59 7,733.70 887.28 10,219.65 5.614 Clearance Factor Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 336.00 173.02 336.00 169.75 335.90 52.902 Centre Distance Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 383.70 173.15 383.70 169.62 382.32 49.110 Ellipse Separation Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 708.70 201.28 708.70 196.01 687.41 38.158 Clearance Factor Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 433.70 153.36 433.70 150.20 433.60 48.518 Centre Distance Pass - Plan: MPU M-231 - Slot 22 - M -23i - M -23i wp03 458.70 153.37 458.70 150.08 458.60 46.507 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 733.70 176.24 733.70 171.47 718.60 36.907 Clearance Factor Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 433.70 138.25 433.70 134.44 433.60 36.324 Centre Distance Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 458.70 138.28 458.70 134.34 458.15 35.083 Ellipse Separation Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 658.70 156.16 658.70 151.16 645.53 31.190 Clearance Factor Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 361.46 124.04 361.46 121.08 361.36 41.877 Centre Distance Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 383.70 124.05 383.70 120.95 383.41 40.064 Ellipse Separation Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 633.70 146.94 633.70 142.35 616.22 31.971 Clearance Factor Pass - 29 October, 2019 - 18:32 Page 4 of 8 COMPASS Hilcorp Alaska, LLC HALLI BU RTON Milne Point Anticollision Report for Plan: MPU M-1 9i - MPU M-1 9i wp08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i wp08 Scan Range: 33.70 to 9,035.42 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24K 311.46 127.99 311.46 124.85 311.36 40.773 Centre Distance Pass - Plan MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P, 333.70 127.99 333.70 124.73 333.38 39.290 Ellipse Separation Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P, 558.70 143.37 558.70 138.92 543.56 32.191 Clearance Factor Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 433.70 128.07 433.70 124.70 433.60 37.961 Centre Distance Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 458.70 128.09 458.70 124.58 458.60 36.484 Ellipse Separation Pass - Plan MPU M -25i - Slot 18 - M -25i - M -25i wp03 708.70 151.06 708.70 146.19 701.32 31.022 Clearance Factor Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 261.46 138.09 261.46 135.22 261.36 48.025 Centre Distance Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 283.70 138.10 283.70 135.11 283.36 46.173 Ellipse Separation Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 558.70 159.89 558.70 155.45 537.86 35.998 Clearance Factor Pass - Plan: MPU M-26 - Slot 10 - M-26 - M-26 wp04 - lower 1 261.46 153.49 261.46 151.05 261.36 62.825 Centre Distance Pass - Plan: MPU M-26 - Slot 10 - M-26 - M-26 wp04 - lower 1 283.70 153.50 283.70 150.94 283.34 59.996 Ellipse Separation Pass - Plan: MPU M-26 - Slot 10 - M-26 - M-26 wp04 - lower 1 633.70 190.83 633.70 186.42 600.00 43.324 Clearance Factor Pass - Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: 261.46 89.83 261.46 86.95 261.36 31.240 Centre Distance Pass - Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: 283.70 89.83 283.70 86.84 283.47 30.032 Ellipse Separation Pass - Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: 533.70 103.45 533.70 99.14 523.18 24.004 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-1 433.70 218.56 433.70 215.10 433.60 63.171 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M 1 483.70 218.67 483.70 214.95 483.60 58.765 Ellipse Separation Pass - Plan: MPU M-58(IRA)- Slot 28- MPU M -58 - MPU M= 1,083.70 281.64 1,083.70 274.40 1,081.41 38.903 Clearance Factor Pass - Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 261.46 179.99 261.46 177.11 261.36 62.594 Centre Distance Pass - Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 308.70 180.10 308.70 176.98 307.24 57.826 Ellipse Separation Pass - Proposal: MPU M-05DSW - Slot 3 - MPU M-05 (Beaur 958.70 268.18 958.70 261.40 900.00 39.551 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 1,083.70 36.72 1,083.70 29.76 1,090.25 5.278 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 1,108.56 36.05 1,108.56 29.22 1,113.61 5.279 Ellipse Separation Pass - Proposal: MPU M-09DSW - AP Hill - M-09DSW -AP H 912.31 210.39 912.31 204.34 961.46 34.786 Ellipse Separation Pass - Proposal: MPU M-09DSW-APHill -M-09DSW-APH 1,083.70 226.69 1,083.70 219.58 1,118.92 31.861 Clearance Factor Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 906.09 263.29 906.09 257.24 862.70 43.494 Centre Distance Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 933.70 263.42 933.70 257.17 889.11 42.178 Ellipse Separation Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 1,083.70 271.78 1,083.70 264.54 1,000.00 37.567 Clearance Factor Pass - M Pt N Pad 29 October, 2019 - 18:32 Page 5 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-1 9i - MPU M-1 9i wp08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i wp08 Scan Range: 33.70 to 9,035.42 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft From To Survey/Plan Survey Tool (usft) (usft) 33.70 9,035.42 MPU M-1 9i wp08 3 MWD+IFR2+MS+Sag 9,035.42 17,448.32 MPU M-191 wp08 3_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 29 October, 2019 - 18:32 Page 6 of 8 COMPASS MALLIBURTON Project: Milne Point J REFERENCE INFORMATION WELL DEIAILS:P1an: MPUM-19i NAD1927(NADCONCONUS) Alaska Zone04 Conrdii a l VD) Reference: Well Plan: MPU M-1 9i, 13 @ NOM Reference: MPU M-19 Ranned RKB @ V. 25 10 Site: M Pt Moose Pad Sperry Ori111nB Well: Plan: MPU M -19i _d Npth W.WusR Measured Depth Ra/erenca: MPU M-19 Ranned RKB @ 58.&lusR +N/ -S +E/ -W Northing Fasting IatilNde LonpNde Wellbore: MPU M -19i c.1 -bb— Manod: Minimum curvatura 0.00 0.00 6027765.55 533513.82 70° 29' 12.796 N 149° 43' 33.890 Plan: MPU M -19i wp08 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering criteria Date: 2019-02-25700:00:00 Validated: Yes Version: FTM 33.70 To 17448.66 Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool 33.70 9035.42 MPUM-19iwp08(MPUM-19i) 3_MWD+IFR2+MS+Sa CASING DETAILS TVD TVDSS MD Size Name SH (1 of 2) 903542 1744832 MPUM-19iwp08(MPUM-19i) 3 MWD+IFR2+MS+Sag 3655.00 3596.20 9035.42 9-5/8 95/8".c 121/4" 3782.00 3723.20 17448.66 4-1/2 41/2"z81/2" F150.00 -- N J Al� I i � ' I O 0120.00 ro 11 P M-1�i P2. C ig M -26P xp04 Co 90.00- -- — QOT MPU M,18 KupS Early KOP- 60.00— 0.00 M-18 M-18 wp03 M-07VVSVVI Wp02 Kup S1 WpO 1--- 08DSW wp02-McLlws c30.00UMV a) Kup S3 Early KOF - 62 deg S ail 0.00 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 Measured Depth (950 usfUin) 4.00 - 16 3.00 Co tL I l I c i i Collision Risk Procedures Req, I I 2.00 Collision Avoidance Req. .00 1.00- No -Go Zone - Stop Drilling 0.00 0.00 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 Measured Depth (950 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -19i MPU M -19i MPU M -19i wP08 Sperry Drilling Services Clearance Summary Anticollision Report 29 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i wp08 Well Coordinates: 6,027,765.55 N, 533,513.82 E (70° 29' 12.80" N, 149° 43' 33.89" W) Datum Height: MPU M-19 Planned RKB @ 58.80usft Scan Range: 9,035.42 to 17,448.66 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: = Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -19i - MPU M -19i wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 729.74 Reference Design: M Pt Moose Pad - Plan: MPU M -19i - MPU M -19i - MPU M -19i wp08 267.39 Scan Range: 9,035.42 to 17,448.66 usft. Measured Depth. 1.578 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M PJ -20 - M PJ -20A - M PJ -20A MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23A- MPJ -23A MPJ -23 - MPJ -23L1 - MPJ -231-1 MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -241-1 - MPJ -241-1 MPJ -24 - MPJ -24L1 - MPJ -241-1 MPJ -24 -MPJ -241-1 -MPJ-24L1 MPJ -24 - MPU J-24 - MPJ -24 MPJ -24 - MPU J-24 - MPJ -24 MPJ -24 - MPU J-24 - MPJ -24 MPJ -27 - MPJ -27 - MPJ -27 MPJ -27 - MPJ -27 - MPJ -27 M Pt M Pad M-01 - M -01A - M -01A M-01 - M-01 A- M-01 A M Pt Moose Pad MPU M -17i - MPU M -17i - MPU M -1 7i 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-18PB2 - MPU M-18PB2 MPU M-18 -MPU M-18PB2 - MPU M-18PB2 MPU M-20 - MPU M-20 - MPU M-20 17,446.66 729.74 17,448.66 267.39 11,176.00 1.578 Clearance Factor Pass - Pass - 17,448.66 773.13 17,448.66 140.07 10,935.14 1.221 Clearance Factor Pass - Pass - 17,448.66 524.53 17,448.66 51.27 10,973.37 1.108 Clearance Factor Pass - Pass - 17,448.66 - 766.53 17,448.66 199.40 10,981.05 1.352 Clearance Factor Pass- Pass - 15,746.38 1,320.92 15,746.38 726.09 12,115.00 2.221 Centre Distance Centre Distance Pass - Pass - 15,810.42 1,322.48 15,810.42 723.75 12,115.00 2.209 Ellipse Separation Pass - 10,810.42 15,860.42 1,325.84 15,860.42 724.99 12,115.00 2.207 Clearance Factor Pass - 11,258.18 16,127.31 939.17 16,127.31 242.99 11,975.00 1.349 Centre Distance Pass - 12,210.42 16,210.42 942.84 16,210.42 235.63 11,975.00 1.333 Ellipse Separation Pass - 9,035.42 16,235.42 945.33 16,235.42 235.81 11,975.00 1.332 Clearance Factor Pass - 16,261.77 140.06 16,261.77 66.19 12,353.44 1.896 Centre Distance Pass - LI 15 9,035.42 1,071.62 9,035.42 895.33 6,300.00 6.079 Ellipse Separation Pass - 9,485.42 1,384.23 9,485.42 1,140.62 6,530.74 5.682 Clearance Factor Pass - 17,448.66 1,494.84 17,448.66 999.45 16,681.12 3.017 Clearance Factor Pass - 17,160.42 749.78 17,160.42 318.28 16,731.00 1.738 Clearance Factor Pass - 17,174.64 749.65 17,174.64 319.29 16,731.00 1.742 Centre Distance Pass - 10,312.76 845.14 10,312.76 630.47 9,863.19 3.937 Centre Distance Pass - 10,810.42 850.27 10,810.42 608.49 10,361.00 3.517 Clearance Factor Pass - 11,258.18 829.00 11,258.18 596.78 10,809.69 3.570 Centre Distance Pass - 12,210.42 834.65 12,210.42 564.99 11,767.00 3.095 Clearance Factor Pass - 9,035.42 1,080.40 9,035.42 866.04 12,050.44 5.040 Clearance Factor Pass - 29 October, 2019 - 18:33 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -19i - MPU M -19i wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-191 - MPU M-191 - MPU M-191 wp08 Scan Range: 9,035.42 to 17,448.66 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPU M-20- MPU M-20PB1 - MPU M-20PB1 9,035.42 1,080.40 9,035.42 866.05 12,050.44 5.040 Clearance Factor Pass - MPU M-20.- MPU M-20PB2 - MPU M -20P82 9,035.42 1,080.40 9,035.42 866.04 12,050.44 5.040 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 17,160.42 761.90 17,160.42 295.79 16,490.99 1.635 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 17,180.07 761.70 17,180.07 296.06 16,500.00 1.636 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 9,035.42 1,053.90 9,035.42 813.47 11,513.24 4.383 Clearance Factor Pass - M Pt N Pad MPN-01 -MPN-01 -MPN-01 17,448.66 1,265.24 17,448.66 1,155.77 3,777.80 11.558 Clearance Factor Pass - MPN-0I-MPN-01A-MPN-01A 17,448.66 1,499.15 17,448.66 1,391.03 3,221.28 13.866 Clearance Factor Pass - MPN-0I-MPN-01B-MPN-01B 17,448.66 1,383.03 17,448.66 1,244.39 3,447.84 9.975 Clearance Factor Pass - From To Survey/Plan (usft) (usft) 33.70 9,035.42 MPU M-19iWp08 9,035.42 17,448.32 MPU M -19i Wp08 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 Tool 3 MWD+IFR2+MS+Sag 3_M WD+IFR2+M S+Sag 29 October, 2019 - 18:33 Page 3 of 5 COMPASS NALLIBLiFiTON Project: Milne Point REFERENCE INFORMATION WELLDETAILSTIan:MPUM49i NAD1927(NADCONCONUS) Alaska Zone04 Coordinate (NIE) Reference: M11 Plan: MPU M ,True NaRM1 Vertical (TVD) Reference: MPU M-19 Planned Ft @ 5a.e0usft 25.10 Site: M Pt Moose Pad Sperry Orilring Well: Plan: MPU M -19i Measured De th Reference: MPU M-19 Planned RKB 56.90usft +N/ -S +F}_W NOrtlting Fyy�N IaBINd< Longitude 0.00 0.00 8 149"43'33.890 Wellbore: MPU M -19i cal—U., MaMed: Minimum Curvature 6027765.55 533513.82 70'29'12,796N Plan: MPU M-1 9i wp08 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection d littering criteria Date: 2019-02-25700:00:00 Validated: Yes Version: 33.70 To 17448.66 Ladder/S.F.Plots Depth From Depth To Survey/Plan Tool CASING DEIA11,S 33.70 9035.42 MPUM-19i wp08(MPUM-19i) 3_MWD+IFR2+MS+Sag TVD TVDSS MD Size Name Phi (2 of 2) 9035.42 17448.32 MPU M -19i wp08 (MPU M -19i) 3_MWD+IFR2+MS+Sag 3655.00 3596.20 9035.42 9-5/8 9 5/8" x 12 1/4" 3782.00 3723.20 17448.66 4-1/2 4 1/2" x 8 1/2" X150.00 � I i I i ' o 0120.00 co � o I � I 90.00 ---!---- - -- - U U 0.00 60,00- 0 U I 30.00 U I I 0.00 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 13500 13950 14400 14850 15300 15750 16200 16650 17100 17550 Measured Depth (900 usft/in) 4.00 - -- --- ! I � 3.00 .— L i Collision Risk Procedures R q. j 2.00 � m I co Collision Avoidance Req. 1.00 - No -Go Zone - Stop Drilling ! I NOERRORS 0.00 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 13500 13950 14400 14850 15300 15750 16200 16650 17100 17550 Measured Depth (900 usft/in) Schwartz, Guy L (CED) From: Joseph Engel <jengel@hilcorp.com> Sent: Monday, November 25, 2019 7:27 AM To: Schwartz, Guy L (CED) Subject: RE: [EXTERNAL] M-19 INJECTOR PTD 219-154 Morning Guy — Talking with Kevin, J-27 is a lateral producer in the Schrader Bluff NB sand and it is ^'140' TVD above the OA sand where M-19 will be. That's why it wasn't on the AOR. Please let me know if you have any other questions. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Joseph Engel Sent: Friday, November 22, 2019 4:49 PM To:'Schwartz, Guy L (CED)' <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] M-19 INJECTOR PTD 219-154 I'll get with Kevin and get back to you next week. Finally out of well control school ... Thanks, Guy Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Schwartz, Guy L (CED)[mailto:guy.schwartz@alaska.Rov] Sent: Thursday, November 21, 2019 1:46 PM To: Joseph Engel < engel@hilcorp.com> Subject: [EXTERNAL] M-19 INJECTOR PTD 219-154 Joe, I was looking at the AOR map and see J-27 not shown. Somehow is was missed in the spreadsheet list. Can you add it? I assume J-27 is a OB producer otherwise you would not be drilling right by it. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office From: Joseph En cieI To: Boyer, David L (CED) Subject: Re: [EXTERNAL] MPU M-19 Injector Date: Wednesday, November 6, 2019 12:02:14 PM David, M-19 will not be preproduced. Please let me know if you have any more questions. Thanks -Joe On Nov 6, 2019, at 9:24 AM, Boyer, David L (CED) <david.boyer2@alaska.gov<mailto:david.bover2;'rr?alaska.gov>> wrote: Hi Joe, I forgot to ask, since M-19 is a water injector, will it be preproduced? If so, for how long? 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. 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Transform Points Source coordinate system State Plane 1927 - Adaska Zone 4 Datum: mpa - N-Iq NAD 1327 - North America Datum of 1927 (Mean) 91 M Target coordinate system Albers Equal Area 050) Datum: NAD 1927 - North America Datum of 1927 (Mean) Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctrl+C to copy and CtH+Vto paste. Then click on the appropriate arrow button to transform the points to the desired coordinate "em. OR < Back Finish Cancel L_ Help -11-1 TRANSMITTAL LETTER CHECKLIST WELL NAME: M Pu( PTD: Z G q I "[ Development V Service Exploratory Stratigraphic Test _ Non -Conventional FIELD: 1" 1 1 E'i PO 1 h+ POOL: 5�C Ayad e_4_ 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. (ComyM 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 (Co ppny 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 PTD#:2191540 Company H lcorp Alaska LLC Initial Class/Type Well Name: MILNE PT UNIT M-19 Program SER _—_ Well bore seg ❑ SER/PEND GeoArea 890_ Unit 11328 On/Off Shore On _ Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Leasenumberappropriate---------------------------------- -- Yes------------------------------ -------------------------------- - 3 Unique well name and number Yes 4 Well located in a_defined pool Yes 15 Well located proper distance from drilling unit boundary Yes 16 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 11/6/2019 I14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For Yes AIO No. 10-B 15 All wells -within 1/4_mi1_earea of review identified (For service well only) - - - - - Yes - 16 Pre -produced injector: duration of pre production Less_ than 3 months_ (For service well only) Yes MPU M-1.9 will not be pre -produced._ 17 Nonconven. gas conforms to AS31.05.030(j.1_.A),(j.2_.A-D) NA 18 Conductor string provided Yes 20" conductor_ set_ at 113 ft Engineering 19 Surface casing protects all -known_ USDWs _ NA_ 20 CMT vol adequate to circulate on conductor _& surf csg Yes 9 5/8"_ casing will be fully cemented ,. Using 2 stage cement with ES 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 23 Casing designs adequate for C, T, B & permafrost Yes BTC calc provided._ 24 Adequate tankage or reserve pit - No Doyon 14 has steel pits. 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Close crossing with J-27 but will pass over in OA sand 0-27 in OB ) 27 If diverter required, does it meet regulations_ Yes Appr Date 28 Drilling fluid- program schematic & equip list adequate Yes Max formation pressure = 1609 psi (8.5 ppg EMW) Drilling with 8.9-9.5 ppg mud GLS 11/21/2019 29 BOPEs, do they meet_ regulation - - - Yes Doyon 14 has 13 5/8" BOPE 5000 psi WP 30BOPE press rating appropriate; test to _(put psig in comments) Yes MASP = 1243 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 I34 Mechanical condition of wells within AOR verified (For service well only) Yes AOR completed ... No- issues 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 Seismic analysis of shallow gas zones NA_ DLB 11/6/2019 '38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA_ Geologic Engineering Public Schrader Bluff OA sand injector. Commissioner: Date: Commissioner: Date Commissioner Date
