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219-125
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, November 24, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-17 MILNE PT UNIT M-17 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 11/24/2023 M-17 50-029-23648-00-00 219-125-0 W SPT 3741 2191250 1500 690 688 688 687 4YRTST P Guy Cook 10/10/2023 Testing completed with a Little Red Services pump truck and calibrated gauges. Mono-bore 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-17 Inspection Date: Tubing OA Packer Depth 201 1705 1642 1622IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC231009152433 BBL Pumped:2.8 BBL Returned:2.8 Friday, November 24, 2023 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191250 Well Name/No. MILNE PT UNIT M-17 MD 16900 TVD 3830 Completion Date 10/15/2019 REQUIRED INFORMATION Mud Log No Operator Hilcorp Alaska LLC API No. 50-029-23648-00-00 Completion Status 1WINJ Current Status 1WINJ UIC Yes Samples No ✓ Directional Survey Yes VI DATA INFORMATION List of Logs Obtained: ROP/ABG/DGR/EWR/ADR 2"/5" MD ... ABG/DGR/EWR/ADR 2"/5" TVD Well Log Information: Log/ Electr (from Master Well Data/Logs) Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 31448 Digital Data 105 16900 11/22/2019 Electronic Data Set, Filename: MPU M-17 LWD Final.las ED C 31448 Digital Data 7230 16862 11/22/2019 Electronic Data Set, Filename: MPU M-17 ADR Quadrants All Curves.las ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final MD.cgm ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final TVD.cgm ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17i_Definitive Survey Report.pdf ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-1 7i—Definitive Survey Report.txt ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final MD.emf ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final TVD.emf ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 Geosteering.dlis ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 Geosteering.ver ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final MD.pdf ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final TVD.pdf ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final MD.tif ED C 31448 Digital Data 11/22/2019 Electronic File: MPU M-17 LWD Final TVD.tif ED C 31448 Digital Data 11/22/2019 Electronic File: EMFView3_1.zip ED C 31448 Digital Data 11/22/2019 Electronic File: Readme.txt Log 31448 Log Header Scans 0 0 2191250 MILNE PT UNIT M-17 LOG HEADERS AOGCC Page 1 of 2 Wednesday, March 18, 2020 DATA SUBMITTAL COMPLIANCE REPORT 3/18/2020 Permit to Drill 2191250 Well Name/No. MILNE PT UNIT M-17 Operator Hilcorp Alaska LLC MD 16900 TVD 3830 Completion Date 10/15/2019 Completion Status 1WINJ Current Status 1WINJ Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report/ Y ) Production Test Information Y� Geologic Markers/Tops YO COMPLIANCE HISTORY Completion Date: 10/15/2019 Release Date: 9/24/2019 Description Comments: Compliance Reviewed API No. 50-029-23648-00-00 UIC Yes Directional / Inclination Data Mud Logs, Image Files, Digital Data Y /6 Core Chips Y /�D Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files 0 Core Photographs Y /CT) Daily Operations Summary 0 Cuttings Samples Y & Laboratory Analyses Y / lA Date Comments Date: AOGCC Page 2 of 2 Wednesday, March 18, 2020 MEMORANDUM State of Alaska 556 Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Wednesday, November 20, 2019 , / ���jq �I(�tj�/ SUBJECT: Mechanical Integrity Tests P.I. Supervisor (6 Hilcorp Alaska LLC 1583 M-17 FROM: Jeff Jolles MILNE PT UNIT M-17 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry ��— NON-CONFIDENTIAL Comm I Well Name MILNE PT UNIT M-17 Insp Num: mitJJ191117155856 Rel Insp Num: API Well Number 50-029-23648-00-00 Permit Number: 219-125-0 Packer Depth Well M-17 Type Inj w' TVD PTD 2191250 -Type Test' SPT Test psi BBL I -- — — Pumped: 3.1 BBL Returned: Inspector Name: Jeff Jones Inspection Date: 10/25/2019 Pretest Initial 15 Min 30 Min 45 Min 60 Min 556 556 1500 r IA — 3 OA 556 556 47 1651 1583 1564 3741 Tubing 1500 r IA — 3 OA Intervals INITAL P/F P Notes: Monobore injector; no OA. I well inspected, no exceptions noted. L SPA No kZS2419 Wednesday, November 20, 2019 Page I of 1 lfilriirp : htpka, 1.11: Date: 11/20/2019 D,=—, -a Oudean Hilcorp Alaska, LLL GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 CD 1 : HALLIBURTON FINAL DATA LAS PDF TIFF _Log Viewers CGM Definitive Survey EMF 1112,0/2019 1:03 PM File folder 10/25/2019 6:30 PM Filefolder 1 1/211/201 9 1:04 PM Filefolder 11/20./20191:04 PM Filefolder 11/20jM91:04 PM Filefolder 11/20/20191:06PM Filefolder 11/20/2019 PM Filefolder 219125 3 144 8 O"CFIV D NUV t 0 "'0i9 A®GCC Please acknowledge receipt by sig.Qing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: _ /(. Il( U /' r/ v 1 . Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION nL;%.fQ1 V QLJ NOV 0 7 2019 WELL COMPLETION OR RECOMPLETION REPORT AND 1 a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑., WAG[] WDSPL ❑ No. of Completions: 1 Service ❑� Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 10/15/2019 219-125 ' 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 September 26, 2019 50-029-23648-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: ' 4914' FSL, 531' FEL, Sec 14, T13N, R9E, UM, AK - October 9, 2019 MPU M-17 Top of Productive Interval: 9. Ref Elevations: KB: 58.9' 17. Field / Pool(s): Milne Point Field 174' FNL, 1752' FWL, Sec 24, T13N, R9E, UM, AK GL: 24.9' BF: 24.9' ' Schrader Bluff Oil Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: • , 484' FNL, 1024' FEL, Sec 30, T13N, R1 OE, UM, AK 16,900' MD / 3,830' TVD ADL025514, ADL025515, ADL025517 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 533633 y- 6027765 Zone- 4 16,900' MD / 3,830' TVD LONS 16-004 TPI: x- 535944 y- 6022687 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 543713 y- 6017140 Zone- 4 N/A 2,209' MD / 1,838' 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) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 2"/5" TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER CASING FT SETTING DEPTH MD SETTING DEPTH TVD GRADE AMOUNT HOLE SIZE CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20" 215# X-52 Surface 113' Surface 113' 42" ±270 ft3 9-5/8" 40# L-80 Surface 7,277' Surface 3,755' 12-1/4" Stg 1 L - 650 sx / T - 400 sx Stg 2 L - 400 sx / T - 270 sx 170 bbls 3-1/2" 9.2# L-80 Surface 7,112' Surface 3,734' Tieback Tieback Tubing 4-1/2" 13.5# L-80 1 7,095' 11,900' 3,732 3,830' 8-1/2" Injection Liner w/ ICDs & Swell Packers 24. Open to production or injection? Yes Q 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" 7,112' 7,095' MD / 3,732' TVD *" Please see attached schematic for ICD and Swell Packer Detail '* Liner Top Packer Liner run on 10/12/19 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. COMPLETION DTE 1S 20/1 Was hydraulic fracturing used during completion? Yes ❑ No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED VERIF ED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: N/A Test Period Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 Submit ORIGINIAL or �ao ��<� ROMS._._ NOV 0 8 2019 V� 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No 0 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 2,209' 1,838' ' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 7,353' 3,762' information, including reports, per 20 AAC 25.071. SV5 1,368' 1,307' SV1 2,275' 1,864' Ugnu LA3 5,210' 3,072' SB NA 6,439' 3,578' SB OA 7,210' 3,747' Formation at total depth: SB OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cclln er I111Cor .cont Authorized Contact Phone: 777-8389 Signature: Date: % . z 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 Hileorp Alaska, LLC Orig. KB Elev.: 58.9'/ GL Elev.: 24.9' aya"'ES Cementer @ ±2,508' NU 4/5 9-5/8" 4-1/2" r See ICD & Swel I Packer Detail 1�? TD =16,900' (MD) / TD = 3,83Y(TVD) PBTD =16,900' (MD) / PBTD = 3,83U(TVD) Schematic Milne Point Unit Well: MPU M-17 PTD: 219-125 API: 50-029-23648-00-00 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 OPEN HOLE/ CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4" Stg 1—Lead 650 sx / Tail 400 sx Top Stg 2 —Lead 400 sx / Tail 270 sx 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34" Conductor (Insulated) 215.5 / X-42 / Weld N/A Surface 114' N/A 9-5/8" Surface 40 / L-80 / TXP 8.679" Surface 7,277' 0.0758 4-1/2" Liner 13.5 / L-80 / Hyd 625 3.795" 7,095' 16,900' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / E U E 8 R D 1 2.867" 1 Surf 7,112' 0.0870 WELL INCLINATION DETAIL KOP @ 400' Hole Angle @ XN = 66° Hole Angle @ Liner Top = 82' Max Hole Angle = 95° @ 13,056' MD JEWELRY DETAIL No Top =MDItem: ID Upper Completion 1 2,509' 3.5" X Nipple (2.813" Packing Bore) 2.813" 2 6,193' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) 2.750" 3 6,435' 3.5" Gauge Mandrel SGM-XPQG w/ %" Wire 2.896" 4 7,101' 8.26" No Go Locater w/ 7.375" Seal Assembly 2.992" 5 7,095' 7.375" Tieback above the SLZXP Liner Top Packer 2.992" Lower Completion 6 7,095' ZXP Liner Top Packer - Depth Depth MD TVD ICD/Swell Packer Detail See Page 2 GENERAL WELL INFO AP1#: 50-029-23648-00-00 Completed by Doyon 14: 10/15/19 Revised By: CJD 10/24/2019 Depth MD Depth ND ICD/Swell Packer Detail 7,291' 3,756' Tendeka Water Swell Packer 7,353' 3,762', Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,462' 3,769' Tendeka Water Swell Packer 7,896' 3,783' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,298' 3,779' Tendeka Water Swell Packer 8,691' 3,772' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,011' 3,776' Tendeka Water Swell Packer 9,361' 3,787' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,762' 3,797' Tendeka Water Swell Packer 10,201' 3,806' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,602' 3,811' Tendeka Water Swell Packer 10,997' 3,818' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,399' 3,816' Tendeka Water Swell Packer 11,712' 3,808' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,155' 3,813' Tendeka Water Swell Packer 12,384' 3,816' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,866' 3,808' Tendeka Water Swell Packer 13,135' 3,788' Tendeka Water Swell Packer 13,447' 3,788' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 13,888' 3,802' Tendeka Water Swell Packer 14,075' 3,808' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 14,351' 3,808' Tendeka Water Swell Packer 14,789' 3,803' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 15,102' 3,802' Tendeka Water Swell Packer 15,371' 3,801' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 15,648' 3,812' Tendeka Water Swell Packer 15,959' 3,827' Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 16,358' 3,826' Tendeka Water Swell Packer 16,624' 3,830'. Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge Hilcorp Energy Company Composite Report Well Name: MP M-17 Field: Milne Point Unit County/State: , Alaska (LAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1913622D MPU M-17 Drilling Contractor Doyon 14 AFE #: AFE $: Aetivrty Rate:. ops summary 9/25/2019 Move from M-06 to M-17. See M-06 report for details.; Connect rig floor mud, choke, air, water & steam lines. Spot fuel trailer, rock washer, 5 -star trailer, mud man & MWD shacks. Speed head, diverter tee & diverter installed prior to rig move. N/U surface riser and diverter Iine.;Remove 4" valve from MPD head & rotate BOP stack on pedestal for 90' mousehole. Prepare mud pits for fluid. Work on rig acceptance checklist.; Tighten diverter line bolts. Diverter distances: 206' total, 202' from rig, 157' to nearest ignition source. Fill pits with 100 bbis water and 290 bbis 8.8 ppg spud mud. Load BHA into pipe shed, load & tally 15 joints 5" drill pipe & 17 joints of HWDP.; Preliminary diverter function: 13 sec. knife valve open & 20 sec. annular close.;lnstall new top drive saver sub. 9/26/2019 PJSM, Slip and cut 30' drilling line, re -calibrate block height. Work on rig acceptance checklist. Rig accepted @ 06:00;Set mouseholes, M/U 5 stds 5" DP, 5 stds HWDP and jar std and rack in derrick. Totco rep perform pre spud inspection, Put rig on Hi Line @ 09:00.7Perform diverter function test on S' DP. Test. gas alarms and PVT sys. Closest ignition source 157' away, Test witnessed waived by AOGCC rep Austin McLeod @ 12:52 am, 9/26/2019 Knife valve opened in 14 seconds & annular closed in 35 seconds.;Accumulator initial 3000 PSI, 1825 PSI after closure, 38 sec, to attain 200 PSI, full recharge in 162 sec. 6 bottle average = 1970 psi.;Conduct pre spud meeting with all parties involved.;M/U new 12-114" Kymera bit, 8", mud motor set at 1.5°, XO sub and stand of 5" HWDP. RIH, tag bottom at 112'.;Flood lines and pressure test to 3500 PSI - good test, completing last item on acceptance checklist. Conduct pre spud meeting with oncoming crew.;Clean out conductor t/ 114', drill 12-1/4" surface hole to 220'. 450 GPM, 460 PSI, 30 RPM, 1 K TO, 3K WOB. Swap to 8.8 spud mud on the fly @ 125'. PU 50K / SO 50K / ROT 50K.;CBU @ 450 GPM - 460 psi. Back ream 1 std @ 40 RPM t/ 127'. BD TD, POOH on elevators t/ Motor @ 33'.;M/U Remaining Directional BHA #1 with DGR, EWR, DM, PWD, HCIM, TM Collar & UBHO, Carry Scribe and upload MWD. P/U 3 NMFC & bottle neck XO, RIH to 180'. R/U Gyro while uploading MWD. Wash down from 180' to 220' with 450 GPM, 1010 PSI, 40 RPM, 1 K TQ.;Drill 12-1/4" surface hole f/ 220't/ 622', 402' drilled, 807hr AROP. 450 GPM, 1260 PSI, 40 RPM, 4K TO, 8-15K WOB, 9.0 ppg MW, 220 vis, 9.6 ECD. PU 77K / SO 77K / ROT 79K. Began 3°/100' build at 400'.;Drill 12-1/4" surface hole ft 622't/ 1187', 565' drilled, 94'/hr AROP. 450 GPM, 1450 PSI, 40 RPM, 4-6K TO, 3-15K WOB, 9.1 ppg MW, 150 vis, 9.9 ECD. PU 86K / SO 85K / ROT 85K.;Clear of any interference, rigged down gyro at 1027', no gyro surveys were required. Build rate increased to 4°/100' at 650', sliding 60' per stand avg. Last survey atl157.15' MD / 1040.01' TVD, 23.02° inc, 160.32° azm, 3.91' from plan, 2.12' high, 3.29' right.;Hauled 0 bbls H2O from L -Pad Lake for total = 0 bbls Hauled 0 bbls H2O from A -Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 0 bbis Hauled 174 bbls cuttings/mud/cement = 174 bbis Daily (midnight) losses = 0 bbls, cumulative losses = 0 bbis 9/27;2019 Drill 12-1/4" surface hole f/ 1187't/ 1880'. 693' drilled, 115.5'/hr AROP. 475 GPM, 1490 PSI, 50 RPM, 4-9K TO, 1 OK WOB, 9.2+ ppg MW, 161 vis, 10.3 ECD. PU 96K / SO 93K / ROT 95K. Continue to build 4°/100' to 65 inc, slide first 60' avg on ea. stand, BR 30' on connections.; Drill 12-1/4" surface hole f/ 1880' U 2640', 760' drilled, 126.7'/hr AROP. 500 GPM, 1480 PSI, 60 RPM, 8K TO, 5-10K WOB, 9.3 ppg MW, 132 vis, 10.3 ECD. PU 102K /SO 88K / ROT 90K.;Continue to build 4°/100' to 65 inc at 2190', drill tangent section, slide as needed to maintain 65 deg inc, BR 30' on connections. Pump 30 bbl hi vis sweep @ 2355', back on time w/ 50°% increase. BPF came in @ 2209' MD, 1839' TVD with max gas 126.; Drill 12-1/4" surface hole f/ 2640' t/ 3306', 666', 111'/hr AROP. 500 GPM, 1530 PSI, 80 RPM, 10K TO, 10K WOB, 9.2 ppg MW, 90 vis, 10.3 ECD. PU 110K / SO 82K / ROT 100K. Pumped 30 bbl hi vis sweep @ 2926' back 150 stks late w/ 50% increase.;Drill 12-1/4" surface hole f/ 3306't/ 3877, 571' drilled, 95.17hr AROP. 550 GPM, 1940 PSI, 80 RPM, 12K TQ, 1-14K WOB, 9.2 ppg MW, 189 vis, 10.7 ECD. PU 120K / SO 80K / ROT 102K.;ECD's spiked to 11.4 @ 3592', back ream full stand & ECD down to 10.8. Pumped 30 bbl hi vis sweep @ 3627back 200 stks late w/40% increase. Last survey @ 3723.84' MD / 2457.31' TVD, 66.04° inc, 160.59° azm, 8.95' from plan, 8.87' low & 1.23' left. Daily losses = 0 bbls, cumulative losses = 0 bbls. 9/28/2019 Drill 12-1/4" surface hole f/ 3877't/ 4546', 669' drilled, 1115/hr AROP. 575 GPM, 2150 PSI, 80 RPM, 15-20K TO, 10K WOB, 9.2 ppg MW, 144 vis, 10.4 ECD. PU 140K / SO 85K / ROT 105K.;Pump 30 bbl hi vis sweep @ 4168', 500 stks late with minimal increase, Drill tangent Maintaining 65 deg inc.;Drill 12- 1/4" surface hole f/ 4546't/ 5386', 840' drilled, 140'/hr AROP. 575 GPM, 2250 PSI, 80 RPM, 18K TO, 13K WOB, 9.2 ppg MW, 108 vis, 10.4 ECD. PU 160K / SO 90K / ROT 115K;Pump 30 bbl hi vis sweep @ 4834', back 1000 stks late with no increase. 5211' ECD climbed to 11.4 ppg, BR full stand before connection lowering to 10.4 ppg. Continue to maintain 65 deg inc.;Drill 12-1/4" surface hole f/ 5386't/ 6093', 707' drilled, 117.87hr AROP. 575 GPM, 2240 PSI, 80 RPM, 22K TO, 15-25K WOB, 9.3 ppg MW, 75 vis, 10.3 ECD. PU 178K / SO 92K / ROT 123K. Pumped hi vis sweeps @ 5402', 800 stks late w/ no increase.;The sweep pumped @ 5972' was not seen due to slowing the pumps down.;Stopped drilling at 6093', shaker screens blinded off with heavy oil from the Ugnu MB. Pump fluid back from rock washer to the mud pits across the shakers. Change shaker screens from 140 API to 120 API & stage flow rate up to 450 GPM. Adding 0.25°% ScreenKleen in the suction pit & into the flow Iine.;Drill 12-1/4" surface hole f/ 6093't/ 6218', 125 drilled, 62.57hr AROP. 575 GPM, 2250 PSI, 80 PRM, 20-25K TO, 3-8K WOB. PU 190K / SO 85K / ROT 120K Began 4°/100' build & turn @ 6163'. Last survey @ 6105.27' MD / 3453.37' TVD, 65.01' inc, 160.41' azm, 11.76' from plan, 0.85' high, 11.73' right.;Shakers blinded off again with heavy oil from the Ugnu MB & filled the rock washer. Shut down & rack a stand back. Clean screens & pump fluid from rock washer back to the pits. Service top drive, blocks & drawworks.;Finish cleaning screens & continue to transfer fluid from the rock washer. Load water into pit #5 and build 200 bbis mud volume. Pump 2 BPM, blinding off screen. R/U line to pump ScreenKleen directly to flow line to aid in keeping screens clean.;Hauled 4290 bbls H2O from L -Pad Lake for total = 4290 bbls Hauled 0 bbls H2O from A -Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 0 bbls Hauled 4059 bbis cuttings/mud/cement = 4233 bbls Daily losses: 0 bbls, cumulative losses: 0 bbls. 9/29/2019 With shakers blinding off continue to pump 2 bpm, 280 psi, reciprocate pipe f/ 6215', increase screen kleen content f/ .25% to .5%, screen down fl 120# mesh to 80# mesh on all shakers.;Drill 12-1/4" surface hole f/ 6218't/ 6498', 280' drilled, 707hr AROP. 575 GPM, 2250 PSI, 80 PRM, 25-28K TQ, 10-15K WOB. MW 9.2 ppg, vis 75, ECD 9.9, Max gas 693u PU 195K / SO 89K / ROT 125K.;BR full stand @ 6257' before connection then BR 30' on connections. At 6350' add 4 drums low tork increasing lubes to .25% reduce torque f/ 28k to 25k. Encountered fault @ 6233' md, 3505' tvd.;Drill 12-1/4" surface hole f/ 6498't/ 7284' MD / 3754' TVD (TD of surface hole), 786' drilled, 112.3'/hr AROP. 575 GPM, 2330PSI, 80 PRM, 26K TQ, 5-14K WOB. MW 9.35 ppg, vis 56, ECD 10.4, Max gas 83u PU 190K / SO 90K / ROT 125K Continue to build and turn 4"/100'.;Schrader Bluff NA at 6439' MD / 3578' TVD. Schrader Bluff OA1 at 7210' MD / 3748' TVD. TD called by geologist 6' TVD into OA1. Last survey @ 7226.54' MD / 3749.37' TVD, 83.87° inc, 124.97° azm, 4.98' from plan, 4.91' high & 0.85' Ieft.;Obtain final survey and pump 30 bbl hi vis sweep w/ nut plug marker. Back 500 strokes early with no increase. 575 GPM, 2150 PSI, 80 RPM, 25K TQ. Rack back a stand after a bottoms up. Circulated a total of 2.25 BU. YP at 20. Perform 10 min flow check - static. TIH f/ 7118' t/ 7283'.;BROOH f/ 7283' t/ 4355' at 5 min/stand. 575 GPM, 1750-2050 PSI, 80 RPM, 20-21 K TQ. Slowed to 10 min/std f/ 6101't/ 5852' then 15 min/std t/ 5681' in the Ugnu L&M-sands due to torque, no pressure or overpull observed. No losses.; Hauled 925 bbls H2O from L-Pad Lake for total = 5215 bbls Hauled 0 bbls H2O from A-Pad for total = 0 bbis Hauled 0 bbls Source Water from G&I = 0 bbis Hauled 1607 bbls cuttings/mud/cement = 5840 bbls Daily losses = 0 bbls, cumulative losses = 0 bbis. 9/3012019 BROOH f/ 4355' t/2642 ' at 5 min/stand. 575 GPM, 1750-1550 PSI, 80 RPM, 14-20K TQ. Slow pulling speed to 20 min std f/ 3575' to 3510' thru UG4A mid coal due to hi TQ 29K, pull slow from 2738' TO 2725' due to slight packing off issues.;BROOH f/ 2642't/ 737' at HWDP 5 min/stand, 575 GPM, 1550-1350 PSI, 80 RPM, 14k TQ. Slow down pulling speed thru BPF @ 2209', Hole unloaded @ 1940' slow pulling speed and let cleanup before continuing, Seen 1280u gas spike @ 1500', flow check well for 5 minl, static. 23.5 bbls total losses BROOH.; Flow check well for 10 min, static. attempt to pull on elevators, 20k overpull, attempt to pump out with same results, BROOH f/ 730' to 623' at 575 gpm, 1300 psi, 60 rpm, 1-3k torque, seeing large amount of wood at shakers,;Orient to hi side, shut off pumps, RIH to 730', BROOH 500 gpm, 1050 psi, 60 rpm, 1-3k torque. hole unloading, pull slow until clean.;POOH on elevators from 623' to 178'. UD three 8" flex drill collars & UBHO sub to 87'. Read MWD tools - 100% data recovery. UD MWD collars, mud motor & bit from 87'. Bit graded: 1-1-WT-A-F-I-NO-TD. Failed bearing on cone. Wear on uphole side of 2 motor stabilizer blades. Clear & clean rig floor.;PJSM. R/U to run 9- 5/8" casing. M/U Doyon Volant casing running tool w/ cement swivel. R/U bail extensions, elevators, back-up strap tongs and 350T slips. Load 1 st row of 9-5/8" casing in the pipe shed.;M/U 9-5/8" shoe track to 118': Float shoe, shoe joint, Baker-Loc joint, float collar & float collar joint. Fill casing & install bypass baffle. Check floats - good. M/U baffle adapter & baffle adapter joint to 159'. Baker-Loc first 4 con nections.;9-518"x12-1 /4" Expand-O-Lizer centralizer placement:2 on shoe joint w/ 4 stop rings, 1 on Baker-Loc joint free floating and 1 each w/ 2 each stop rings on float collar & baffle adapter joints.; Run 9-5/8" 40# L-80 TXP-BTC casing f/ 159' t/ 1244' (joint #31) @ 15'/min. Torque to 20,960 ft/lbs w/ the Volant tool. Install one 9-5/8"x12-1/4" Expand-O-Lizer centralizer on joints #5-25, then every other joint #27-31. Fill pipe on the fly & top off every 10 joints. 5 bbls losses to this depth.;Hauled 775 bbis H2O from L-Pad Lake for total = 5990bbls Hauled 0 bbis H2O from A-Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 0 bbis Hauled 986 bbis cuttings/mud/cement = 6644 bbis Daily losses = 23.5 bbls, Cumulative losses = 23.5 bbis. 10/1/2019 Run 9-5/8" 40# L-80 TXP-BTC casing f/ 1244't/ 2387' @ 15'/min jt TQ to 20,960 ft/lbs w/ the Volant tool. Install one 9-5/8"x12-1/4" Expand-O-Lizer every other joint #27-60. Fill pipe on the fly & top off every 10 joints. 5.6 BBL losses at this point.;Below BPF at 2387' Fill pipe, slowly stage pump f/ 1/2 bpm to 5 bpm, 150 psi, reciprocate pipe 30', at BU seeing fair amount sand at returns, circulate 1.5 BU total until clean 9.5 BBL losses circulating. P/U 125K, S/O 95K.;Continue Run 9-5/8" casing ft 2387' t/ 4751' @ 157min jt, TQ to 20,960 ft/lbs Install one 9-5/8"x12-1/4" Expand-O-Lizer every other joint #62-101. then every jt from 116-120. Fill pipe on the fly & top off every 10 joints.; Inspect ESC and verify pinned f/ 3300 psi, M/U @ Per HES rep to 4782' with 1 ea centralizer installed on pup joints above and below ESC. Place ES Cementer between joints #120 & 121.;Continue Run 9-5/8" casing f/ 4751' t/ 6167' installing 9-5/8"x12- 1/4" Expand-O-Lizer every jt from 121-125, then every other jt from 127.;Circ & condition staging up pumps to 6 bpm @ 160 psi. UP/ DN 275/100K. 7 bbls lost while circulating.;Continue to RIH with 9 5/8 Casing F/ 6167'T/ 7225'. Wash down F/ 7225' to 7277'w/ 2 BPM, 190 psi. Filling on the fly with Volant and breaking circ every 10 joints. Tq to 20,960 ft/lbs w/ Volant. Centralizer on every other joint to #181. Total of 183 joints, 104 centralizers & 12 stop rings ran.;Stage up pumps F/ 2 BPM, 130 psi T/ 6 BPM, 190 psi while reciprocating pipe F/ 7278'T/ 7264'. Rotate 5 RPM w/ 21 K torque. Circulated 1.5 bottom up. 25 bbis losses while circulating. Total 74 bbls loss during casing run.;Blow down TopDrive. R/U cement lines and clear floor. Continue conditioning mud while ROT & RECIP pipe. total 2x BU pumped. PJSM w/ Doyon, Halliburton, M-1 and Peak.;Hauled 125 bbls H2O from L-Pad Lake for total = 6115 bbis Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 640 bbis Source Water from G&I = 640 bbls Hauled 471 bbls cuttings/mud/cement = 7115 bbis Daily losses = 50.5 bbls, Cumulative losses = 74 bbis. 10/2/2019 Continue conditioning mud while ROT & RECIP pipe F/ 7278' T! 7264', 4 BPM, 100 PSI, 1-2 RPM, 15-17K torque. MW 9.2, vis 61, YP 17, Shutdown pump, break out volant tool, inspect and dope cup, M/U same. 25 BBL losses while circulating. P/U 305K, S/O 120K.; Flood the lines with 5 bbls of water. PT lines to 1240/4000 psi for 5 min each (good test). Line up, mix & pump 60 bbl 10 ppg tuned spacer w/red die & pol-e-flake in the first 10 bbls 3 bpm, 110 psi. Drop the bypass plug. Line up, mix & pump 270 bbls 12 ppg lead cement (650 sacks) 5 bpm, 295 psi.;Mix & pump 82 bbls 15.8 ppg tail cement (400 sacks) 4.7 bpm, 700 psi. Drop the closing plug. HES pumped 20 bbls fresh water. Line up to the rig and start displacement,;With rig pump 322 tools 9.2 ppg mud 5 bpm, 140 ✓ ICP, HES pump 80 bbls 9.4 ppg tuned spacer, with rig displace with 119.8 bbls mud, slow to 3 bpm @ 4286 stks, FCP 600 psi, bumped plug @ 4375 stks, 11 stks early f/ calculated @ 4386 stks.;CIP @ 11:30, pressure to 1100 psi, hold 5 min, bleed off pressure, pressure to 2880 psi, shifting cementer open. Reciprocate and rotate 1-3 rpm, 20k torque throughout the job until last 15 bbls before bumping plug. No losses while pumping and displacing cement.; Circulate hole from ESC up @ 2510' 6 bpm, 300 psi. 1980 stks away dump contaminated mud, 2200 stks away spacer returns, 2900 stks away contaminated mud, 3900 stks take good mud to pits 115 bbls contaminated mud and 80 bbls spacer dumped to rock washer.; Continue to circulate thru ESC 6 bpm, 230 psi and prep for 2nd stage while WOC to reach 100 psi compressive strength in 8 hrs and cement crew rest. Submit 24 hr BOP test notification.; Hold PJSM with all parties. HES batch up while continue to circulate through ES Cementer, 6 BPM.;PT lines w/ H2O U 4000 psi. Pump 60 bbl of 10 ppg tuned spacer with 4# red dye and 0.5 ppb Poly flake in the 1st 10 bbls at 4 BPM 260 psi. Pump 314 bbls of 10.7# lead Perm L Cmt. (400 SX), at 6 BPM 695 psi . �9 Pump 56.2 bbl of 15.8 Tail cmt. (270 SX) at 4.7 BPM 750 psi.;Drop closing plug. Pump 20 bbis H2O. Line up to rig for displacement Pump 1595 strokes at 6 BPM then slow to 2 BPM. Shift ES cementer closed and bump plug eleven strokes early at 1678 stks & Pressure up to 1150 psi over FCP at 370 psi. Hold 1520 psi. Bleed down. No flow.;Got good mud push back with 300 bbls Lead pumped and good cement back before swapping to Rig for mud displacement. No losses on second stage. No clobbered up issues on second stage. CIP at 22:41 with 170 bbl total good lead cmt back at surface.; Disconnect knife valve, drain stack and flush with black water, functioning bag several times. Flush all surface equip with black water. N/D diverter line, lift 20" diverter equip. Install casing slips as per wellhead rep. with 110K on slips. Cut casing. L/D cut it. (20.24' total cut).;N/D Surface stack, Riser and Diverter Tee.;Mobilize Well head equipment to Cellar. N/U T103 Mandrill, test Mandrill 250/2400 psi for 5/15 min.;Hauled 250 bbls H2O from L -Pad Lake for total = 6365 bbls Hauled 0 bbls H2O from A -Pad for total = 0 bbls Hauled 280 bbls Source Water from G&I = 930 bbls Hauled 1745 bbls cuttings/mud/cement = 8860 bbis Daily losses = 63.5 bbls, Cumulative losses = 137.5 bbls. 10/3,2019 Finish Installing wellhead and tbg spool, test void to to 500 psi for 5 min and 5000 psi for 15 min @ per WH rep, prep spacer spool and BOP for install. Cleaning in pits;PJSM, N/U BOP stack, hook up accumulator lines, N/U kill and choke lines.;lnstall trip nipple, load shed with test joints, mobilize test plug, wear bushing and split bushings to rig floor. Start opening upper ram doors.;lnstall test plug, C/O UPR ft 4 1/2" x 7" VBR to 2 7/8" x 5" VBRs, leave 3 1/2" x 6" VBRs in LPR, install turn buckles on stack. SimOps: grease choke valves, ready rig floor for testing BOPs.;Missing stud for flange on 4" MPD air actuated valve on RCD head, remove riser to access valve, remove valve, install stud, M/U valve and riser.; PJSM, M/U 5" test joint, flood stack and shell test BOP to 3000 psi. Rig electrician test rig gas alarms.***AOGCC rep Adam Earl waived witness for BOP test (ca 11:23 hrs 10/3/19`*".:Test BOP equipment as per PTQ & AOGCC requirements. All tests performed to 250 PSI low / 3000 PSI high. All tests held for 5 min. each. All tests performed w/ fresh water against test plug.;#1: Upper 2-7/8"x5" VBR on 5" test joint, choke valves 12,13,14, 3" kill Demco & upper IBOP. #2: Choke valves 1, 9,11, HCR kill & lower IBOP. #3: Choke valves 5,8,10, manual kill & 5" TIW #1.;#4: Choke valves 4,6,7 & 5" TIW #2, #5: Choke valve 2 & 5" dart valve. #6: Lower 3-1/2"x6" VBR on 5" test joint, 4" TIW;Alerted of a Code 99 in the field. Muster all personnel at Primary point and perform head count. All personnel accounted for. All clear given while at Muster.; Continue testing BOPE #7: Upper 2-7/8"x5" VBR on 4.5" test joint, choke valve 3, 4" dart valve #8: Lower 3-1/2"x6" VBR on 4.5" test joint. #9: Annular on 3.5" test joint, HCR choke #10 Upper 2-7/8"x5" VBR on 3.5" test joint & manual choke.;#11 Lower 3-1/2"x6" VBR on 3.5" test joint. #12: Blind rams #13: Hyd choke "A" #14: Man choke "B" C/O leaking Whity valve on choke manifold Accum test: 3000 PSI system pressure, 1700 PSI after closure. 43 sec for 200 PSI recharge, 197 sec full PSI recharge. 2033 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 3 NM flex collars to 124'. TIH with 5" HWDP & jars f/ 124' t/ 680'.;Trip in the hole w/ stands 5" drill pipe from the Derrick f/ 680' U 2394'. 10/4/2019 At 2394' M/U top drive, fill pipe, wash and ream down 200 gpm, 350 psi, 30 rpm, 5k tq, tag TOC @ 2498', cleanout soft cement tag ESC on depth @ 2505'. PU 105K, SO 85K, ROT 95K,;Drill plugs and ECS f/ 2505' to 2512' pumping 400 gpm, 850 psi, 40 rpm, 7k tq, 10-12k WOB, back ream 3 times and cleanup same, pass thru w/ rotary off with no issues. BDTD.;TIH on elevators f/ 2583' to 7061', M/U TD wash down 3 bpm, 390 psi to 7152' w/ 8k set down, tagging TOC just above the BA, fill pipe @ 6000', BD TD. PU 225K, SO 70K.;CBU @ 7152' pumping 450 gpm, 850 psi, 30 rpm 25-26k torque reciprocating pipe . shut down pumps, L/D single to 7120', BD TD.;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 v' pressure, open UPR. 6.5 bbls pumped, 6.5 bbls bled back.;M/U single, drill cement and F/E from 7152' to 7277' at 450 GPM, 1250 psi, 30 RPM = 26K torque, 7-11 K WOB. Cleanout rat hole from 7277' to 7284'. Drill 20' of new formation to 7304'. Seen 500u gas spike after drilling shoe. PU 240K, SO 60K, ROT 120K,;Pull into 9 5/8 casing @ 7250', circulate and condition mud for FIT, 450 GPM, 1300 PSI, 30 RPM, 28K torque, reciprocate pipe, until good 9.2 MW in/out.;Parked @ 7247', R/U test equipment, close UPR, purge air from lines, Perform FIT to 12 ppq with existing 9.2 ppq MW, apply 547 psi, bleed off / pressure, open UPR, R/D test equipment. Good test. 1.6 BBLS pumped, 1.6 bbls bled back.;Flow check well, static. POOH f/ 7251't/ 6775'. Correct hole fill observed. Pump dry job and continue to POOH on elevators to 775'.;Lay down 15 its 5" HWDP, Rack jar stand in Derrick and continue laying down the 8-1/2" clean-out assembly. The used tri -cone bit graded the same at is went in the hole: 1 -1 -WT -A -E -1 -NO -BHA. No losses on trip out of hole.;Clear and clean the rig floor, Mobilize RSS BHA components to the rig floor. Hold PJSM on making up BHA. Monitor well, circulating over top of hole via trip tank. No losses observed.;M/U 8-1/2" production drilling BHA to 84': SK616MJ1 D bit, NRP sleeve, Geo -Pilot, MWD (ADR/ILS/DGR/PWD/DM/TM) then initialize tools. M/U 2 float subs then TIH 3 NM flex collars, HWDP & jars to 275'. Pulse test MWD 400 GPM, 720 PSI - good.;Trip in the hole with 5" drill pipe from the Derrick f/ 275' t/ 2180'. Lubricate RSS seals and fill pipe. 10/5/2019 Finish breaking in geo-pilot, test geo-span to 3000 psi., BD TD, TIH f( 2180' slowing down before ESC @ 2507tagging same w/ 10k set down.;M/U TD, wash and ream cleaning up ESC @ 450 GPM, 900 PSI, 30 RPM, ream and cleanup same, pass thru with pumps off, no issues.;Continue to TIH f/ 2558' to 6877', fill pipe @ 4465' and 6400'. Correct displacement on TIH.;Monitor well with trip tank, PJSM, remove trip nipple, install RCD bearing as per MPD rep.;Single in with f/ 6877' to 7304' at TD, M/U TD on last single and break circulation., P/U to 7287'. PU 230K, SO 55K.;PJSM, wash to TD, Line up pits and trucks for displacement. Pump 30 bbl hi vis spacer, Displace w/ 520 bbls 8.8 ppg flow pro NT mud 300 gpm, 600 psi, with mud out bit, PIU into 9 518" casing rotate 30 rpm, 19k tq working pipe, dump spud mud returns to rock washer. Obtain new SPRs.;P/U to 7222' set 1 std DP in mouse hole, PJSM, install FOSV and 5' pup jt, slip and cut 70' drilling line, inspect saver sub and backup dies. UD FOSV and pup jt. Clean pill pit, offload remaining new flo-pro mud to pits.;Calibrate block height. Mix dilution fluid for drilling. Make connection and wash/ream down f/ 7278' t/ 7304', 80 RPM - 25k Tq, 450 GPM - 1000 psi. Tag on depth.; Drill 8-1/2" production lateral f/ 7304't/ 7867', 563' drilled, 94'/hr AROP. 550 GPM, 1570 PSI, 120 RPM, 24-25K TO, 7-10K WOB. 200K PU / 64K SO / 115K ROT, 9.1 ppg MW, 45 vis, 10.4 ECD, 292u max gas. Entered OA-2 at 7423' MD / 3767' TVD & OA-3 at 7590' MD / 3775' TVD.;MPD chokes full open while drilling, closed on connections with no pressure observed. Added 0.5% Lo-Torq Torque down t/ 24K f( 28K.;Drill 8-1/2" production hole f/ 7867't/ 8650' (3770' TVD), 783' drilled, 130'/hr AROP. 550 GPM, 1820 PSI, 120 RPM, 27K TO, 10-12K WOB. 220K PU / OK SO ( 115K ROT. 8.9 MW, 44 vis, 10.47 ppg ECD, 1970u max gas. Entered OA-2 @ 8222' MD / 3782' TVD & OA-1 @ 8389' MD / 3776' TVD.;Added 0.5% Lo-Torq Torque down t/ 26K f/ 29K. MPD chokes full open while drilling, closed on connections w/ no pressure observed. Pumped 30 bbls hi vis sweep at 8558', 30% increase seen at shakers. Drilled 5 concretions for a total thickness of 17' (1.3% of the lateral).;Last survey @ 8481.82' MD / 3776.866' TVD, 91.49° inc, 126.82° azm, 19.5' from plan, 19.28' high & 2.94' right.; Losses today to hole= 0 bbls. Total losses for interval= 24 Hauled 450 bbls H2O from L-Pad Lake for total = 6965 bbls Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 280 bbls Source Water from G&I = 930 bbls Hauled 1019 bbls cuttings/mud/cement = 10154 bbls 10/6/2019 Drill 8-1/2" production hole f/ 8650't/ 9160' (3779' TVD), 51 O' drilled, 857hr AROP. 550 GPM, 1800 PSI, 120 RPM, 23K TO, 10-15K WOB. 165K PU ( 75K SO / 113K ROT. 8.9 MW, 40 vis, 10.5 ppg ECD, 628u max gas. Hold the OA-1, formation dip 89.5°-90°.;MPD choke fully open drlg w/ 60 psi line pressure, closed choke on connections w/ no pressure increase. Tq increasing to 28-29k, add 2 drums 776 lube to sys, increase lubes f/ 1 % tol.5% lowering tq to 20-24k and S/O wt back @ 75k. Pump hi vis sweep at 9020', 100 stks late w/ 25% increase.;Drill 8-1/2" production lateral f/ 9160' t/ 9921' (3806' TVD), 761' drilled, 1277hr AROP. 550 GPM, 1820 PSI, 120 RPM, 27K TO, 15K WOB. 173K PU / 75K SO / 109K ROT. 8.9 ppg MW, 45 vis, 10.70 ECD, 429u max gas.;MPD choke fully open drig w/ 60 psi line pressure, closed choke on connections w/ no pressure increase. Pump hi vis sweep at 9507', back 100 stks late w/ 25% increase Undulate down with 86° inc, Entered OA-2 @ 9713' MD / 3793' TVD, OA-3 @ 9807" MD / 3800' TVD.;Drill 8-1/2" production lateral f! 9921' U 10689' (3812' TVD), 768' drilled, 1287hr AROP. 550 GPM, 1880 PSI, 120 RPM, 27K TO, 10-11 K WOB. 161 K PU / 70K SO / 106K ROT. 8.9 ppg MW, 45 vis, 10.92 ECD, 459u max gas.;MPD choke fully open drlg w/ 60 psi line pressure, closed choke on connections w/ no pressure increase. Pump hi vis sweep at 10078', back 100 stks late w/ 25% increase, 10650', back 100 stks late w/ 20% increase. Drilled 87' of the OA-4, from 9924' to 10,011' then maintain the OA-3.;Drill 8- 1/2" production lateral f/ 10689't/ 11316' (3825' TVD), 627' drilled, 1047hr AROP. 550 GPM, 1840 PSI, 120 RPM, 27K TO, 10-15K WOB. 165K PU / 70K SO / 112K ROT. 8.95 ppg MW, 45 vis, 10.9 ECD, 2835u max gas. Maintain the OA-3.;MPD choke fully open drlg w/ 60 psi line pressure, closed choke on connections w/ no pressure increase. Drilled 18 concretions for a total thickness of 79' (2.1 % of the lateral). Last survey @ 11247.39' MD / 3821.79' TVD, 90.81 ° inc, 128.31' azm, 29.15' from plan, 28.11' high and 7.72' Ieft.;Losses today to hole= 0 bbls. Total losses for interval= 24 Hauled 750 bbls H2O from L-Pad Lake for total = 7715 bbis Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 280 bbls Source Water from G&I = 930 bbls Hauled 986 bbls cuttings/mud/cement = 11140 bbls 10/7/2019 Drill 8-1/2" production lateral F/ 11316'- T/ 11980' (3809' TVD), 664' drilled, 11 V/hr AROP. 550 GPM, 1910 PSI, 125 RPM, 22K TO, 10-15K WOB. 160K PU ! 70K SO / 106K ROT. 8.95 ppg MW, 45 vis, 11 ECD, 765u max gas. 30 bbl hi vis / (5 bbl 776) lube pill @ 11575'- Yielded slight drop in tq (2-4k).;Verify digital tq displayed on driller's console and Totco. Found tq was reading 7-1 Ok higher than manual tq gauge w/ load cell. Actual drilling tq 18-20k ft/lbs. Continued drilling ahead with new tq parameters without issue. Will address digital tq displayed at earliest opportunity.; Drill 8-1/2" production lateral F/ 11980' - T/ 12268' (3819' TVD), 288' drilled, 83'/hr AROP, 550 GPM, 1950 PSI, 125 RPM, 22K TO, 10-15K WOB, 160K PU / 70K SO / 106K ROT. 9 ppg MW, 45 vis, 11.1 ECD, 504u max gas. Pump 30 bbl hi vis sweep @ 12081', back on time, 25% increase.;Service rig while C/O sprocket slip card on MP #1.;Drill 8-1(2" production lateral f/ 12268't/ 12461' (3816' TVD), 193' drilled, 97'/hr AROP. 550 GPM, 1910 PSI, 120 RPM, 21 K TO, 12K WOB. 165K PU / 59K SO / 106K ROT. 8.9 ppg MW, 45 vis, 11.16 ECD, 240u max gas.;Changed out digital torque gauge. New gauge getting proper voltage and display correct torque. MPD choke fully open drlg w/ 60 psi line pressure, closed choke on connections w/ no pressure increase.;Drill 8-1/2" production lateral f/ 12461' t/ 13030' (3795' TVD), 569' drilled, 957hr AROP. 505 GPM, 1900 PSI, 120 RPM, 21 K TO, 10K WOB. 8.9 ppg MW, 45 vis, 11.47 ECD, 311 u max gas. 165K PU / 50K SO 105K ROT. Pump 30 bbl hi vis sweep @ 12652', back on time, 25% increase.;Added 3 sacks/hr (9 sxs each) f/ 12,700't/ 12950' of Safe-Carbs 40, 250, & 500 proactively for potential losses at projected fault. MPD choke fully open drlg, closed choke on connections w/ 30 psi pressure build.;Crossed fault #1 (7' DTN) @ 12535' f/ OA-1 to OA-2, Built inc U 92° in anticipation of fault #2, exited the top of OA package at 12842'. Fault #2 (65' DTN) @ 12875' out of shale above OA-1 to shale below OA-4.; Drill 8-1/2" production lateral f/ 13030't/ 13687' (3794' TVD), 657' drilled, 109.57hr AROP. 505 GPM, 1808 PSI, 130 RPM, 21 K TO, 10K WOB. 9.0 ppg MW, 48 vis, 11.35 ECD, 391 u max gas. 160K PU / 60K SO / 105K ROT Built up to 95" inc. Base OA4 at 13155' and OA-3 at 13186'.;MPD choke fully open drlg, closed choke on connections w/ 30 psi pressure build. Pump 30 bbl hi vis sweep @ 13127', 100 stks late, 10% increase.; Drilled 32 concretions for a total thickness of 129' (2.1% of the lateral). Last survey @ 13532.61 MD / 3791.60' TVD, 88.16° inc, 124.25' azm, 22' from plan, 21.95' high and 1.48' right.;Losses today to hole= 0 bbls. Total losses for interval= 24 Hauled 450 bbls H2O from L-Pad Lake for total = 6965 bbls Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 280 bbls Source Water from G&I = 930 bbls Hauled 1019 bbls cuttings/mud/cement = 10154 bbls 10/8/2019 Drill 8-1/2" production lateral f/ 13687' t/ 14230' (3813' TVD), 543' drilled, 907hr AROP. 530 GPM, 2050 PSI, 130 RPM, 24K TQ, 15K WOB. 9.1 ppg MW, 43 vis, 11.47 ECD, 602u max gas. 165K PU / 45K SO / 105K ROT.;MPD choke fully open drlg , closed choke on connections 35 psi pressure increase. Pump 30 bbl hi vis sweep @ 13687, back on calculated stks w/ no increase.;Drill 8-1/2" production lateral f/ 14230' t/ 14364' (3807' TVD), 134' drilled, 1347hr AROP. 515 GPM, 2040 PSI, 120 RPM, 23K TQ, 15K WOB. 9.0 ppg MW, 43 vis, 11.29 ECD, 670u max gas. 170K PU / 40K SO / 106K ROT No down wt at 14364'.;Re-Torque TopDrive quill/Upper IBOP connection after it backed out at the compression ring while breaking out of the string during a connection. Inspect Saver Sub.;Drill 8-1/2" production lateral f( 14364't/ 14688' (3806' TVD), 324' drilled, 1087hr AROP. 515 GPM, 2040 PSI, 1230 RPM, 23K TQ, 15K WOB. 9.0 ppg MW, 46 vis, 11.40 ECD, 448u max gas. 193K PU / 40K SO / 105K ROT. MPD choke fully open drig , closed choke on connections 35 psi pressure increase.;Drill 8-1/2" production lateral fl 14688't/ 15468' (3802' TVD), 780' drilled, 1307hr AROP. 515 GPM, 2070 PSI, 110 RPM, 25K TQ, 15K WOB. 9.0 ppg MW, 43 vis, 11.38 ECD, 571 u max gas. 190K PU / 40K SO / 106K ROT. MPD choke fully open drlg , closed choke on connections 35 psi pressure increase.;Drill 8-1/2" production lateral f/ 15468't/ 16168'(3832" TVD), 700 drilled, 1177hr AROP. 515 GPM, 2130 PSI, 110 RPM, 25K TQ, 12K WOB. 9.1 ppg MW, 39 vis, 11.44 ECD, 890u max gas. 185K PU / 40K SO / 108K ROT MPD choke fully open drlg , closed choke on connections 35 psi pressure increase.; Drilled 46 concretions for a total thickness of 208' (2.4% of the lateral). Last survey @ 16099.05 MD / 3828.07' TVD, 90.63° inc, 126.11' azm, 8.93' from plan, 8.62' low and 2.32' right.;Losses today to hole= 0 bbis. Total losses for interval= 24 Hauled 825 bbls H2O from L-Pad Lake for total = 9225 bbls Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 0 bbls Source Water from G&I = 930 bbls Hauled 1152 bbls cuttings/mud/cement = 13394 bbls 10/9/2019 Drilo-1/2" production lateral f/ 16168't/ 16900' (3829" TVD the TD of the well). 732 drilled, 113/hr AROP. 510 GPM, 2210 PSI, 110 RPM, 25K TQ, 15K WOB. 9.0 ppg MW, 40 vis, 11.50 ECD, 724u max gas. 207K PU / 40K SO / 106K ROT MPD choke fully open drlg, closed choke on connections w/ 45 psi.;Last survey at 16827.72' MD / 3830.47' TVD, 90.56° inc, 126.25° azm, 13.24' from plan, 12.91' low and 2.92' left. 53 concretions were drilled in the lateral, for a total thickness of 240' (2.5%).; Pump low vis sweep followed by a high vis sweep. no increase of cutting observed, 200 stks late. 550 GPM, 2500 PSI, 100 RPM, 23K TQ, 11.01 ECD. Continue to circulate 4 bottoms up while preparing mud pits for SAPP pills & brine displacement. Rack back a stand every bottoms up f/ 16900't/ 16551'.;Wash back to bottom after 4x BU, 300 GPM — 980 psi, 30 RPM — 20k Tq. Continue circulating while prep for displacement. Rot & Recip ft 16900' t/ 16835', 100 RPM — 21 k Tq. Hold PJSM for Displacing 47 bbls mud loss while circulate and condition.;Pump SAPP pill treatment: 30 bbl hi-vis spacer, 40 bbls seawater, 30 bbls SAPP #1, 40 bbls seawater, 30 bbls SAPP #2, 40 bbls seawater, 30 bbls SAPP #3, 40 bbls seawater, 30 bbls hi-vis spacer.; Displace w/ 8.45 ppg 4% lube viscosified brine 5 BPM, 720 PSI ICP, 740 PSI FCP, 80 RPM, 21k Tq start-15K Tq final. Good PST tests: 10.25 sec avg x 3 tests in & 8.88 sec avg x 3 tests out. 180K PU (190K pumps off), 60K SO after displacement.; Monitor well with MPD closed choke. Bleed off and monitor for 5 min. Initial pressure build to 69psi, final build to 42 psi. BROOH f/ 16900't/ 16638' at 6 min/std 520 GPM,1780 psi, 100 RPM, 15K Tq 12 BPH loss.;BROOH f/ 16638't/ 14518' at 5 min / stand. 520 GPM, 1780 psi start / 500 GPM, 1590 psi end, 100-110 RPM, 15K Tq start, 16K Tq end. 160K PU / 75K SO ! 115 ROT. 10 BPH loss average. MPD choke fully open backreaming, closed choke on connections w/ 75 psi.;Hauled 825 bbls H2O from L-Pad Lake for total = 10050 bbls Hauled 0 bbls H2O from A-Pad for total = 0 bbls Hauled 0 bbls Source Water from G&I = 930 bbls Hauled 2092 bbls cuttin s/mud/cement = 15486 bbls Hilcorp Energy Company Composite Report Well Name: MP M-17 Field: Milne Point Unit County/State: , Alaska (LAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1913622C MPU M-17 Completion Contractor AFE #: AFE $: Activity Date Ops Summary 10/10/2019 BROOH f/ 14518't/ 12750' at 5-6 min / stand. 500 GPM 1590 psi start, 450 GPM 1400 psi end. 100-110 RPM, 15K Tq. 160K PU / 75K SO / 115 ROT. 9 BPH loss average. MPD choke fully open backrearning, closed choke on connections w/ 75 psi. Reduce flow from 500 GPM to 450 GPM at 12895' to slow loss rate.,Lost Hi -Line power at 11:20am. On Rig Gen power at 11:30am.,BROOH f/ 12750' t/ 7227' at 5-6 min / stand. 500 GPM 1450 psi, 100 RPM, 9K Tq. 145K PU / 100K SO / 100 ROT. 9 BPH loss average. MPD choke fully open backreaming, closed choke on connections w/ 60 psi.,Obtain directional survey at 7321' Total 190 bbis lost on BROOH Rig back on HI -Line power @ 18:30.,Pump 30 bbl hi -vis sweep at 540 GPM, 60 RPM, 5k Tq, Reciprocation f/ 7270't/ 7227'. Sweep back on calculated strokes with 30% increase in cuttings. Continue circulate until shakers clean. 8176 stks pumped.,Shut down pumping, open MPD choke and bled off pressure to 11 PSI, close choke and pressure built to 37 psi and held after 6 minutes. Open MPD choke and bled off pressure again to 11 PSI, close choke and pressure built to 24 psi in 5 minutes and held.,Weight up from 8.6 ppg to 9.0 ppg from 7277'. 9.5 BPM, 780 PSI, 30 RPM, 5.5K Tq.,Perform kick while tripping drill. Well secure and all hands respond in 2 min 42 sec. Hold PJSM, Slip and cut 92' of drilling line. Service TopDrive & Drawworks. SimOps: Monitor well at trip tank, drop from 2 BPH to static in 10 minutes. Line up and circulate through injection line across the top of hole to monitor well while Slip and Cut. 5.2 BPH losses recorded. Service TopDrive and Drawworks.,Cumulative Mud losses to formation = 71 bbls. Daily (midnight) Viscosified, 4% lubed Brine losses to formation = 178 bbis cumulative losses for interval = 190 bbls.,Hauled 275 bbis H2O from L -Pad Lake for total = 10325 bbis Hauled 0 bbls H2O from A -Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 930 bbis Hauled 829 bbis cuttings/mud/cement = 16315 bbis Ria fuel allons : Rec'd=0 Used=618 On hand=9468 10/11/2019 PJSM w/ Beyond and Doyon. Remove MPD RCD and install trip nipple., Drop 2.35" drift w/ 1 00'tail & POOH on elevators f/ 7277't/ 6751'. Good displacement. Pump dry job and blow down TopDrive.,POOH f/ 6751't/ 275' racking 39 stands 5" drillpipe in Derrick. UD 5" drillpipe singles f/ 3512't/ 275'. 3.25 BPH losses.,UD jars, HWDP & drill collars to 86'. Read MWD tools - 100% recovery of data. UD remainder of BHA f/ 89'. Bit graded 2 -1 -CT -N -X -1 -NO -TD. Wear observed on all wear bands and stabilizers. 28.4 bbis loss on 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 tongs. 2 BPH loss average.,PJSM. M/U 4-1/2" shoe & float collar joints: Innovex float shoe w/ ports welded closed, tubing joint w/ 2 each 7.1" centralizers, 4-1/2" float collar, tubing joint w/ 2 each 7.1" centralizers. Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 85' t/ 2532'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 3.0 BPH avg. Iosses.,Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 2532' U 7434'. PU- 99k, SO- 75k prior to exit shoe Torque to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 2.0 BPH avg. Iosses.,Cumulative Mud losses to formation = 71 bbls. Daily (midnight) KCL viscosified brine w/ 4% lube losses to formation = 62 bbls cumulative losses for interval = 240 bbis., Hauled 0 bbis H2O from L -Pad Lake for total = 10325 bbis Hauled 0 bbis H2O from A -Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 930 bbls Hauled 182 bbis cuttings/mud/cement = 16497 bbis Rig fuel (gallons): Rec'd=0, Used=516, On hand=8952. 10/12/2019 Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner ue to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 1.5 BPH avg. Iosses.,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 9909', 130K PU / 80K SO. Obtain parameters: Pump 3 BPM - 300 psi, 1 BPM - 100 psi, 10 RPM - 4K TQ.P/U 106K S/O 80K ,ROT 85K.,RIH w/ 4-1/2" injection liner on 5" DP stands f/ 9909't/ 13150'. Fill pipe on the fly and top off every 5 stands. P/U 140k, S/O 85k.,RIH w/ 4-1/2" injection liner on 5" HWDP singles f/ 13150't/ 16817'( 119 jts HWDP ) M/U std DP, tag TD on depth @ 16900', set down 15k to verify on bottom. Drop 29/32" phenolic ball, M/U top drive, PU to 220k putting string in tension. Top off every 3 stands. PU 225K, SO 130K. 43 bbl total losses running liner.,R/U test pump and chart recorder. Pump down at 3 BPM, 660 PSI. Slow to 1.6 BPM, 310 PSI for last 500 strokes. Ball on seat at 961 strokes. Pressure up to 2500 psi and set packer. Pressure to 2800 psi hold 5 min. Continue to pressure up to 3750 psi with rig pumps then swap over to test pump.,Pressure up & neutralize pusher tool @ 4420 PSI w/ test pump. Pressure bleed off indicating tool neutralized and ball seat sheared as same time. Bleed off shut in pump pressure and pick up 5' to confirm release. Break over w/ 190K PU. Close upper pipe rams & test annulus x 7x 9-5/8" packer to 1700 psi for 10 min. - good test. TOL @ 7094'.,Rack 1 stand 5" DP back & UD 2 singles 5" HWDP, blow down injection line & TopDrive, R/D test equipment. POOH f/ 6976't/ surface, racking 5" DP & HWDP in Derrick. Inspect & L/D running tool, ball seat was sheared along with rupture disk. Push tool was neutralize, HRD was hydraulically released & dog sub was sheared. 19 bbl loss on trip out of hole.,M/U 3 1/2" perforated clean-out tool with 8.25" no-go and XO, TIH with stands 5" DP t/ 3349' then 5" HWDP t/ 6676'. 2.5 bbis loss on trip in hole., Cumulative Mud losses to formation = 71 bbis. Daily (midnight) KCL viscosified brine w/ 4% lube losses to formation = 50.5 bbis cumulative losses for interval = 290.5 bbis., Hauled 35 bbis H2O from L -Pad Lake for total = 10360 bbis Hauled 0 bbis H2O from A -Pad for total = 0 bbis Hauled 0 bbis Source Water from G&I = 930 bbis Hauled 0 bbls cuttings/mud/cement = 16497 bbls Rig fuel (gallons): Rec'd=0, Used=695, On hand=8257 10/13/2019 Run in hole with 3-1/2" wash tool and 8.25" no-go on 5" HWDP f/ 6676' V 6959'. M//U TopDrive to a stand of 5" DP. RIH tag up no-go at 7094'w/ 5k. PU 185K, SO 165K.,Pump 30 bbl hi vis spacer, displace w/ 488 bbis clean 9.0 ppg brine 12.5 bpm, 2200 psi. 10 rpm, 4k torque reciprocating pipe, take dirty returns to rock washer, pumped 30 bbis over calculated displacement until clean returns.,Flow check well, Blow down TopDrive. POOH UD 5" HWDP f/ 7091' t/ 5841' Loss rate 3 bph. PU 165K, SO 150K.,Service Topdrive, Drawworks and Iron Roughneck. Continue to POOH UD 5" HWDP f/ 5841' V 3349' & 5" DP from 3349't/ surface. Break down and UD wash tool and no-go. 20 bbls total loss on trip out of hole. PU 165K, SO 150K.,Pull wear bushing. Install XO on FCSV. R/U 3-1/2" elevators, slips and hydraulic double stack tongs. Mobilize Schlumberger equipment to the rig floor. Hang sheave and R/U TEC wire. Static losses at 1 BPH.,PJSM with all parties involved. P/U and run Baker bullet seal assembly, 21 jts, of 3-1/2" tubing to 656'. Torque to 3100 ft/lbs with Doyon double stack tongs. Install SLB gauge and pressure test to 5200 PSI for 5 min.- good test. 1 BPH Iosses.,Run 3-1/2" 9.3# L-80 EUE tubing f/ 656' V 4201' as per tally. Torque to 3100 ft/lbs with Doyon double stack tongs. Install cross coupler Cannon clamp on every joint to secure TEC wire. Continuous monitoring of gauge while running. 1 BPH losses., Cumulative Drilling Mud (8.9 ppg FloPro) losses to formation for interval = 71 bbis. Daily (midnight) KCL viscosified brine w/ 4% lube losses to formation = 12 bbis cumulative losses for interval = 303 bbis. Daily (midnight) 2% KCL brine losses to formation = 29 bbis cumulative losses for interval = 29 bbls.,Hauled 0 bbls H2O from L -Pad Lake for total = 10360 bbis Hauled 320 bbis H2O from B -Pad Creek for total = 320 bbis Hauled 0 bbis Source Water from G&I = 930 bbis Hauled 1328 bbls cuttings/mud/cement = 17825 bbis Rig fuel (gallons): Rec'd=0, Used=564, On hand=7693. 10/14/2019 Run 3-1/2" 9.3# L-80 EUE tubing F/ 4201' T/ 5990' as per tall . Torque to 3100 ft/lbs with Doyon double stack tongs. Install cross coupler Cannon clamp on every joint to secure TEC wire -Service Rig., Run 3-1/2" 9.3# L-80 EUE tubing F/ 5990' T/ 7094' as per tally. Tag on no go. Set down 5K twice. Saw good indication of seals engaging. Space out. UD 3 joints and M/U space out pups. 8.31, 4.07, 2.15. M/U joint 227 & RIH. up/dn 79/70K with blocks at 40K.,M/U hanger and landing joint. RIH & Land hanger. Verify hanger landed and mark pipe. P/U hanger out of profile. Close annular and pressure up to 400 psi. P/U until pressure dumps plus 6".,PJSM, Reverse circulate 262 bbl of 2% concor 303 in 9.0 brine 35 KCL. Chase with 192 bbl of diesel. 4 BPM, ICP 470 psi, FCP 760 psi.,Slack off and engage seals in liner top. Drain BOP stack and open annular. Land hanger with 31 k on Hanger. RILDS.,R/D lines f/ pump in sub and XO, R/U test equipment, pre-injection MIT 3 1/2" x 9 5/8" annulus with diesel to 2500 psi for 30 charted min. good test. bleed off pressure. AOGCC representative Matt Herrera waived witness of the test.,R/D test equipment, blow down choke and kill lines, back out and UD landing jt, WH rep install BPV and dart. Pull and lay down mouse holes.,PJSM with Crew and Doyon safety rep. Nipple down BOP stack and rack on moving stump. Set adapter flange and tree on wellhead, SLB rep terminate tech wire to adapter flange, take final reading, ( pressure 1574.94 psi, temp 71.64° ) NIU adapter flange and tree, WH rep test hanger void to 500 psi f/ 5 min, 5000 psi f/ 15 min.,RIU test equipment, test tree with diesel to 250/5000 psi 5 min each. Rig down test equipment and rig up to freeze protect 3-1/2" tubing.,Cumulative Drilling Mud (8.9 ppg FloPro) losses to formation for interval = 71 bbls. Daily (midnight) KCL viscosified brine w/ 4% lube losses to formation = 12 bbls cumulative losses for interval = 303 bbls. Daily (midnight) 2% KCL brine losses to formation = 18 bbls cumulative losses for interval = 47 bbls.,Hauled 0 bbls H2O from L -Pad Lake for total = 10360 bbis Hauled 0 bbis H2O from B -Pad Creek for total = 320 bbis Hauled 0 bbis Source Water from G&I = 930 bbis Hauled 475 bbis cuttings/mud/cement = 18300 bbls Rig fuel (gallons): Rec'd=0, Used=750, On hand=6943. 10!15/2019 Bullhead 44 bbl diesel down tubing through BPV. @ 2 bpm. ICP 140 & FCP 1040psi.,Flush MP & lines with water and deep clean pill. Blow down all lines. P_0� idrillingreport R/D & secure the tree & cellar. Close SSV as per wellhead rep. Tubing = 0 PSI and IA = 0 PSI. Rig release to M-21 at 0800 .,Move rig to M-21. See M-21 for details. H i (corp Alaska, LLC Milne Point M Pt Moose Pad MPU M -17i 500292364800 Sperry Drilling Definitive Survey Report 14 October, 2019 HALLIBURTON Sperry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -17i Wellbore: MPU M -17i Design: MPU M -17i Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M -17i TVD Reference: MPU M-17 Actual RKB @ 58.90usft MD Reference: MPU M-17 Actual RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M -17i Well Position +N/ -S 0.00 usft Northing: 6,027,765.65 usfl +E/ -W 0.00 usft Easting: 533,633.87 usfl Position Uncertainty 0.00 usft Wellhead Elevation: usfl Wellbore MPU M -17i Magnetics Model Name Sample Date Declination (1) BGGM2018 9/18/2019 16.45 Latitude: Longitude: Ground Level: Dip Angle (1) 80.95 70° 29' 12.792 N 149° 43'30.357 W 24.90 usft Field Strength (nT) 57,413.47746579 Design MPU M -17i Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 34.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I 34.00 0.00 0.00 125.79 Survey Program Date 10/14/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 158.51 7,226.54 MPU M-17 MWD+IFR2+MS+Sag (1) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 09127/2019 7,321.17 16,827.72 MPU M-17 MWD+IFR2+MS+Sag (2) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 10/07/2019 Survey 10/14/2019 12.59.17PM Page 2 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (I N (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 34.00 0.00 0.00 34.00 -24.90 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 UNDEFINED 158.51 0.20 283.25 158.51 99.61 0.05 -0.21 6,027,765.70 533,633.66 0.16 -0.20 2_MWD+IFR2+MS+Sag (1) 212.71 0.06 178.63 212.71 153.81 0.04 -0.30 6,027,765.69 533,633.57 0.41 -0.27 2_MWD+IFR2+MS+Sag (1) 306.02 0.25 268.22 306.02 247.12 -0.01 -0.51 6,027,765.64 533,633.36 0.28 -0.40 2_MWD+IFR2+MS+Sag (1) 399.14 0.57 186.72 399.14 340.24 -0.48 -0.76 6,027,765.17 533,633.11 0.63 -0.34 2_MWD+IFR2+MS+Sag(1) 491.53 2.45 160.93 491.49 432.59 -2.80 -0.17 6,027,762.85 533,633.71 2.11 1.50 2_MWD+IFR2+MS+Sag (1) 582.94 6.17 158.22 582.63 523.73 -9.21 2.29 6,027,756.45 533,636.20 4.07 7.25 2_MWD+IFR2+MS+Sag (1) 676.58 9.46 158.12 675.38 616.48 -21.03 7.03 6,027,744.66 533,640.99 3.51 18.00 2_MWD+IFR2+MS+Sag (1) 772.23 12.25 158.93 769.31 710.41 -37.80 13.61 6,027,727.92 533,647.65 2.92 33.14 2_MWD+IFR2+MS+Sag (1) 866.93 16.31 159.50 861.07 802.17 -59.63 21.88 6,027,706.12 533,656.02 4.29 52.62 2_MWD+IFR2+MS+Sag (1) 961.74 19.80 159.55 951.20 892.30 -87.16 32.15 6,027,678.65 533,666.41 3.68 77.05 2_MWD+IFR2+MS+Sag (1) 1,057.15 23.02 160.32 1,040.01 981.11 -119.87 44.09 6,027,645.99 533,678.49 3.39 105.87 2_MWD+IFR2+MS+Sag (1) 1,151.91 27.28 162.42 1,125.77 1,066.87 -158.04 56.89 6,027,607.88 533,691.47 4.59 138.57 2_MWD+IFR2+MS+Sag (1) 10/14/2019 12.59.17PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -17i Project: Milne Point TVD Reference: MPU M-17 Actual RKB @ 58.90usft Site: M Pt Moose Pad MD Reference: MPU M-17 Actual RKB @ 58.90usft Well: MPU M -17i North Reference: True Wellbore: MPU M -17i Survey Calculation Method: Minimum Curvature Design: MPU M -17i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°} (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,248.23 32.78 161.31 1,209.13 1,150.23 -203.82 71.92 6,027,562.18 533,706.71 5.74 177.54 2 MWD+IFR2+MS+Sag(1) 1,343.46 36.61 161.46 1,287.41 1,228.51 -255.18 89.22 6,027,510.90 533,724.24 4.02 221.61 2_MWD+IFR2+MS+Sag (1) 1,439.67 38.53 159.31 1,363.67 1,304.77 -310.42 108.93 6,027,455.76 533,744.19 2.42 269.90 2_MWD+IFR2+MS+Sag (1) 1,534.85 41.90 162.09 1,436.35 1,377.45 -368.42 129.19 6,027,397.86 533,764.71 4.01 320.25 2_MWD+IFR2+MS+Sag (1) 1,629.15 44.83 161.31 1,504.89 1,445.99 -429.88 149.53 6,027,336.49 533,785.33 3.16 372.69 2_MWD+IFR2+MS+Sag (1) 1,724.76 48.43 159.34 1,570.54 1,511.64 -495.30 172.96 6,027,271.19 533,809.05 4.05 429.95 2_MWD+IFR2+MS+Sag (1) 1,819.83 50.44 159.61 1,632.36 1,573.46 -562.93 198.27 6,027,203.68 533,834.67 2.13 490.04 2_MWD+IFR2+MS+Sag (1) 1,916.22 52.73 157.82 1,692.26 1,633.36 -633.29 225.70 6,027,133.45 533,862.41 2.79 553.44 2_MWD+IFR2+MS+Sag (1) 2,011.45 57.68 157.50 1,746.58 1,687.68 -705.59 255.43 6,027,061.29 533,892.46 5.21 619.84 2_MWD+IFR2+MS+Sag (1) 2,106.87 62.59 158.31 1,794.08 1,735.18 -782.25 286.53 6,026,984.78 533,923.90 5.20 689.89 2_MWD+IFR2+MS+Sag (1) 2,202.40 65.58 158.81 1,835.83 1,776.93 -862.22 317.93 6,026,904.96 533,955.66 3.17 762.13 2_MWD+IFR2+MS+Sag (1) 2,297.11 68.44 160.37 1,872.82 1,813.92 -943.92 348.32 6,026,823.40 533,986.42 3.38 834.56 2_MWD+IFR2+MS+Sag (1) 2,391.86 67.06 159.95 1,908.69 1,849.79 -1,026.41 378.08 6,026,741.06 534,016.55 1.51 906.95 2_MWD+IFR2+MS+Sag (1) 2,487.41 65.97 160.92 1,946.77 1,887.87 -1,108.98 407.43 6,026,658.63 534,046.27 1.47 979.04 2_MWD+IFR2+MS+Sag (1) 2,582.98 68.70 160.95 1,983.59 1,924.69 -1,192.33 436.23 6,026,575.42 534,075.44 2.86 1,051.15 2_MWD+IFR2+MS+Sag (1) 2,677.78 67.58 161.39 2,018.89 1,959.99 -1,275.60 464.63 6,026,492.29 534,104.21 1.26 1,122.88 2_MWD+IFR2+MS+Sag (1) 2,773.25 68.89 160.86 2,054.29 1,995.39 -1,359.49 493.31 6,026,408.53 534,133.28 1.47 1,195.21 2_MWD+IFR2+MS+Sag (1) 2,868.47 69.65 158.11 2,088.00 2,029.10 -1,442.89 524.52 6,026,325.29 534,164.86 2.82 1,269.30 2_MWD+IFR2+MS+Sag (1) 2,963.68 68.19 158.16 2,122.25 2,063.35 -1,525.33 557.61 6,026,243.00 534,198.31 1.53 1,344.35 2_MWD+IFR2+MS+Sag(1) 3,056.79 67.05 157.90 2,157.70 2,098.80 -1,605.18 589.82 6,026,163.31 534,230.88 1.25 1,417.17 2_MWD+IFR2+MS+Sag (1) 3,153.44 65.49 158.72 2,196.59 2,137.69 -1,687.39 622.52 6,026,081.26 534,263.95 1.79 1,491.78 2_MWD+IFR2+MS+Sag (1) 3,248.46 62.81 158.79 2,238.02 2,179.12 -1,767.08 653.50 6,026,001.72 534,295.29 2.82 1,563.52 2_MWD+IFR2+MS+Sag (1) 3,343.45 61.99 159.35 2,282.03 2,223.13 -1,845.70 683.57 6,025,923.24 534,325.72 1.01 1,633.89 2_MWD+IFR2+MS+Sag (1) 3,438.75 59.50 159.07 2,328.59 2,269.69 -1,923.43 713.08 6,025,845.65 534,355.57 2.63 1,703.28 2_MWD+IFR2+MS+Sag (1) 3,532.44 61.48 160.67 2,374.74 2,315.84 -1,999.98 741.13 6,025,769.24 534,383.96 2.58 1,770.80 2_MWD+IFR2+MS+Sag (1) 3,629.01 65.15 161.41 2,418.11 2,359.21 -2,081.57 769.15 6,025,687.78 534,412.35 3.86 1,841.25 2_MWD+IFR2+MS+Sag (1) 3,723.84 66.04 160.59 2,457.29 2,398.39 -2,163.22 797.27 6,025,606.27 534,440.83 1.23 1,911.80 2_MWD+IFR2+MS+Sag (1) 3,819.09 65.94 161.53 2,496.05 2,437.15 -2,245.52 825.51 6,025,524.11 534,469.44 0.91 1,982.84 2_MWD+IFR2+MS+Sag (1) 3,915.21 65.69 161.57 2,535.42 2,476.52 -2,328.69 853.26 6,025,441.07 534,497.56 0.26 2,053.99 2_MWD+IFR2+MS+Sag (1) 4,010.08 65.43 161.65 2,574.68 2,515.78 -2,410.65 880.51 6,025,359.24 534,525.18 0.28 2,124.02 2_MWD+IFR2+MS+Sag (1) 4,104.48 65.90 162.25 2,613.58 2,554.68 -2,492.43 907.15 6,025,277.59 534,552.20 0.76 2,193.47 2_MWD+IFR2+MS+Sag (1) 4,200.23 66.45 160.01 2,652.26 2,593.36 -2,575.31 935.48 6,025,194.85 534,580.90 2.22 2,264.91 2_MWD+IFR2+MS+Sag(1) 4,295.08 65.62 160.53 2,690.78 2,631.88 -2,656.89 964.75 6,025,113.41 534,610.52 1.01 2,336.36 2_MWD+IFR2+MS+Sag(1) 4,390.83 66.32 159.88 2,729.77 2,670.87 -2,739.17 994.36 6,025,031.27 534,640.51 0.96 2,408.51 2_MWD+IFR2+MS+Sag (1) 4,486.06 66.77 159.33 2,767.68 2,708.78 -2,821.06 1,024.81 6,024,949.53 534,671.32 0.71 2,481.09 2_MWD+IFR2+MS+Sag (1) 4,581.15 66.49 158.47 2,805.40 2,746.50 -2,902.49 1,056.23 6,024,868.25 534,703.11 0.88 2,554.20 2_MWD+IFR2+MS+Sag (1) 4,676.12 65.12 158.75 2,844.32 2,785.42 -2,983.15 1,087.82 6,024,787.74 534,735.07 1.47 2,627.00 2_MWD+IFR2+MS+Sag (1) 4,772.10 64.68 159.23 2,885.03 2,826.13 -3,064.29 1,118.99 6,024,706.76 534,766.59 0.64 2,699.73 2_MWD+IFR2+MS+Sag (1) 4,867.42 64.67 159.31 2,925.81 2,866.91 -3,144.87 1,149.48 6,024,626.32 534,797.45 0.08 2,771.59 2_MWD+IFR2+MS+Sag (1) 4,962.56 64.26 159.96 2,966.82 2,907.92 -3,225.35 1,179.36 6,024,545.98 534,827.69 0.75 2,842.89 2_MWD+IFR2+MS+Sag (1) 101141201912:59:17PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -17i Wellbore: MPU M -17i Design: MPU M -17i Survey MD Inc Azi (usft) (°) (°) 5,058.14 64.96 159.90 5,153.62 64.87 160.27 5,248.50 65.21 5,343.96 64.82 5,439.54 63.75 5,534.41 64.56 5,629.85 65.09 5,724.68 66.08 5,819.74 65.30 5,914.67 65.18 6,010.12 63.16 6,105.27 65.01 6,199.45 66.96 6,295.18 68.73 6,389.62 69.88 6,485.68 70.88 6,580.91 72.82 6,676.62 74.50 6,771.83 76.99 6,867.39 77.44 6,962.78 80.14 7,058.23 81.94 7,153.36 82.69 7,226.54 83.87 7,321.17 84.14 7,344.85 84.82 7,441.12 87.24 7,535.31 87.17 7,630.09 87.29 7,725.65 87.85 7,821.18 89.89 7,915.58 89.76 8,010.16 88.96 8,105.94 89.82 8,201.47 92.73 8,293.82 91.86 8,388.45 92.29 8,481.82 91.49 8,577.71 89.51 8,676.86 89.95 160.56 160.70 161.39 160.91 162.04 159.71 159.85 159.45 159.91 160.41 158.06 153.73 149.98 145.60 143.77 141.70 137.81 133.37 131.55 128.12 125.15 124.97 125.78 125.65 126.92 126.98 126.86 125.95 125.69 125.35 125.32 126.27 126.47 126.38 126.89 126.82 125.78 124.42 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M -17i TVD Reference: MPU M-17 Actual RKB @ 58.90usft MD Reference: MPU M-17 Actual RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Vertical Section (ft) Survey Tool Name 2,914.36 2_MWD+IFR2+MS+Sag (1) 2,985.80 2_MWD+IFR2+MS+Sag (1) 3,056.58 2_MWD+IFR2+MS+Sag (1) 3,127.60 2_MWD+IFR2+MS+Sag (1) 3,197.92 2_MWD+IFR2+MS+Sag (1) 3,267.55 2_MWD+IFR2+MS+Sag (1) 3,337.70 2_MWD+IFR2+MS+Sag (1) 3,408.36 2_MWD+IFR2+MS+Sag(1) 3,480.19 2_MWD+IFR2+MS+Sag (1) 3,551.77 2_MWD+IFR2+MS+Sag (1) 3,623.09 2_MWD+IFR2+MS+Sag(1) 3,693.72 2_MWD+IFR2+MS+Sag (1) 3,765.50 2_MWD+IFR2+MS+Sag (1) 3,842.19 2_MWD+IFR2+MS+Sag (1) 3,921.54 2_MWD+IFR2+MS+Sag (1) 4,005.41 2_MWD+IFR2+MS+Sag (1) 4,091.02 2_MWD+IFR2+MS+Sag (1) 4,178.87 2_MWD+IFR2+MS+Sag(1) 4,268.40 2_MWD+IFR2+MS+Sag (1) 4,360.20 2_MWD+IFR2+MS+Sag (1) 4,453.13 2_MWD+IFR2+MS+Sag (1) 4,547.16 2_MWD+IFR2+MS+Sag (1) 4,641.41 2_MWD+IFR2+MS+Sag (1) 4,714.08 2_MWD+IFR2+MS+Sag (1) 4,808.19 2_MWD+IFR2+MS+Sag (2) 4,831.76 2_MWD+IFR2+MS+Sag (2) 4,927.79 2_MWD+IFR2+MS+Sag (2) 5,021.85 2_MWD+IFR2+MS+Sag (2) 5,116.50 2_MWD+IFR2+MS+Sag (2) 5,211.97 2_MWD+IFR2+MS+Sag (2) 5,307.47 2_MWD+IFR2+MS+Sag (2) 5,401.87 2_MWD+IFR2+MS+Sag (2) 5,496.44 2_MWD+IFR2+MS+Sag (2) 5,592.21 2_MWD+IFR2+MS+Sag (2) 5,687.70 2_MWD+IFR2+MS+Sag (2) 5,779.97 2_MWD+IFR2+MS+Sag (2) 5,874.53 2_MWD+IFR2+MS+Sag (2) 5,967.83 2_MWD+IFR2+MS+Sag (2) 6,063.71 2_MWD+IFR2+MS+Sag (2) 6,162.85 2_MWD+IFR2+MS+Sag (2) 10/14/2019 12:59:17PM Page 4 COMPASS 5000.15 Build 91 Map Map TVD TVDSS +N/ -S +E/ -W Northing Easting DLS (usft) (usft) (usft) (usft) (ft) (ft) (°/100') 3,007.80 2,948.90 -3,306.45 1,208.99 6,024,465.02 534,857.68 0.73 3,048.28 2,989.38 -3,387.76 1,238.45 6,024,383.86 534,887.50 0.36 3,088.32 3,029.42 -3,468.80 1,267.28 6,024,302.96 534,916.70 0.45 3,128.64 3,069.74 -3,550.43 1,295.98 6,024,221.47 534,945.76 0.43 3,170.11 3,111.21 -3,631.87 1,323.95 6,024,140.16 534,974.10 1.29 3,211.47 3,152.57 -3,712.67 1,351.54 6,024,059.50 535,002.05 0.97 3,252.07 3,193.17 -3,794.57 1,378.98 6,023,977.73 535,029.86 1.21 3,291.27 3,232.37 -3,876.14 1,407.27 6,023,896.30 535,058.52 2.47 3,330.40 3,271.50 -3,957.43 1,437.22 6,023,815.15 535,088.82 0.83 3,370.16 3,311.26 -4,038.25 1,467.19 6,023,734.47 535,119.16 0.40 3,411.75 3,352.85 -4,118.81 1,497.03 6,023,654.05 535,149.36 2.16 3,453.33 3,394.43 -4,199.31 1,526.07 6,023,573.69 535,178.76 2.00 3,491.66 3,432.76 -4,279.74 1,556.58 6,023,493.42 535,209.63 3.08 3,527.78 3,468.88 -4,360.63 1,592.80 6,023,412.70 535,246.21 4.58 3,561.16 3,502.26 -4,438.51 1,634.47 6,023,335.02 535,288.23 3.91 3,593.43 3,534.53 -4,515.04 1,682.69 6,023,258.72 535,336.80 4.42 3,623.09 3,564.19 -4,588.86 1,735.00 6,023,185.13 535,389.44 2.74 3,650.02 3,591.12 -4,661.95 1,790.62 6,023,112.31 535,445.37 2.72 3,673.47 3,614.57 -4,732.35 1,850.23 6,023,042.18 535,505.30 4.75 3,694.63 3,635.73 -4,798.90 1,915.43 6,022,975.94 535,570.79 4.56 3,713.17 3,654.27 4,862.05 1,984.45 6,022,913.10 535,640.09 3.39 3,728.04 3,669.14 -4,922.43 2,056.84 6,022,853.06 535,712.75 4.02 3,740.77 3,681.87 -4,978.68 2,132.49 6,022,797.16 535,788.64 3.19 3,749.33 3,690.43 -5,020.43 2,191.98 6,022,755.68 535,848.31 1.63 3,759.22 3,700.32 -5,074.91 2,268.71 6,022,701.55 535,925.29 0.90 3,761.49 3,702.59 -5,088.67 2,287.85 6,022,687.88 535,944.48 2.92 3,768.16 3,709.26 -5,145.50 2,365.26 6,022,631.40 536,022.14 2.84 3,772.75 3,713.85 -5,202.05 2,440.44 6,022,575.20 536,097.57 0.10 3,777.33 3,718.43 -5,258.92 2,516.13 6,022,518.68 536,173.50 0.18 3,781.38 3,722.48 -5,315.58 2,592.97 6,022,462.37 536,250.59 1.12 3,783.27 3,724.37 -5,371.48 2,670.41 6,022,406.83 536,328.28 2.15 3,783.56 3,724.66 -5,426.32 2,747.24 6,022,352.34 536,405.35 0.39 3,784.61 3,725.71 -5,481.02 2,824.39 6,022,298.00 536,482.74 0.85 3,785.63 3,726.73 -5,537.03 2,902.08 6,022,242.34 536,560.67 1.34 3,783.51 3,724.61 -5,593.66 2,978.97 6,022,186.07 536,637.81 3.05 3,779.81 3,720.91 -5,648.45 3,053.22 6,022,131.62 536,712.30 0.95 3,776.38 3,717.48 -5,704.88 3,129.10 6,022,075.54 536,788.43 0.70 3,773.30 3,714.40 -5,760.86 3,203.77 6,022,019.91 536,863.35 0.86 3,772.47 3,713.57 -5,817.62 3,281.05 6,021,963.50 536,940.87 2.33 3,772.93 3,714.03 -5,874.63 3,362.16 6,021,906.87 537,022.23 1.44 Vertical Section (ft) Survey Tool Name 2,914.36 2_MWD+IFR2+MS+Sag (1) 2,985.80 2_MWD+IFR2+MS+Sag (1) 3,056.58 2_MWD+IFR2+MS+Sag (1) 3,127.60 2_MWD+IFR2+MS+Sag (1) 3,197.92 2_MWD+IFR2+MS+Sag (1) 3,267.55 2_MWD+IFR2+MS+Sag (1) 3,337.70 2_MWD+IFR2+MS+Sag (1) 3,408.36 2_MWD+IFR2+MS+Sag(1) 3,480.19 2_MWD+IFR2+MS+Sag (1) 3,551.77 2_MWD+IFR2+MS+Sag (1) 3,623.09 2_MWD+IFR2+MS+Sag(1) 3,693.72 2_MWD+IFR2+MS+Sag (1) 3,765.50 2_MWD+IFR2+MS+Sag (1) 3,842.19 2_MWD+IFR2+MS+Sag (1) 3,921.54 2_MWD+IFR2+MS+Sag (1) 4,005.41 2_MWD+IFR2+MS+Sag (1) 4,091.02 2_MWD+IFR2+MS+Sag (1) 4,178.87 2_MWD+IFR2+MS+Sag(1) 4,268.40 2_MWD+IFR2+MS+Sag (1) 4,360.20 2_MWD+IFR2+MS+Sag (1) 4,453.13 2_MWD+IFR2+MS+Sag (1) 4,547.16 2_MWD+IFR2+MS+Sag (1) 4,641.41 2_MWD+IFR2+MS+Sag (1) 4,714.08 2_MWD+IFR2+MS+Sag (1) 4,808.19 2_MWD+IFR2+MS+Sag (2) 4,831.76 2_MWD+IFR2+MS+Sag (2) 4,927.79 2_MWD+IFR2+MS+Sag (2) 5,021.85 2_MWD+IFR2+MS+Sag (2) 5,116.50 2_MWD+IFR2+MS+Sag (2) 5,211.97 2_MWD+IFR2+MS+Sag (2) 5,307.47 2_MWD+IFR2+MS+Sag (2) 5,401.87 2_MWD+IFR2+MS+Sag (2) 5,496.44 2_MWD+IFR2+MS+Sag (2) 5,592.21 2_MWD+IFR2+MS+Sag (2) 5,687.70 2_MWD+IFR2+MS+Sag (2) 5,779.97 2_MWD+IFR2+MS+Sag (2) 5,874.53 2_MWD+IFR2+MS+Sag (2) 5,967.83 2_MWD+IFR2+MS+Sag (2) 6,063.71 2_MWD+IFR2+MS+Sag (2) 6,162.85 2_MWD+IFR2+MS+Sag (2) 10/14/2019 12:59:17PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU N4 -17i Project: Milne Point TVD Reference: MPU M-17 Actual RKB @ 58.90usft Site: M Pt Moose Pad MD Reference: MPU M-17 Actual RKB @ 58.90usft Well: MPU M -17i North Reference: True Wellbore: MPU M -17i Survey Calculation Method: Minimum Curvature Design: MPU M -17i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E1 -W Northing Easting DLS Section (usft) (1) V) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,771.70 89.57 124.15 3,773.33 3,714.43 -5,928.05 3,440.52 6,021,853.80 537,100.83 0.49 6,257.65 2 MWD+1FR2+MS+Sag (2) 8,867.30 89.33 124.58 3,774.25 3,715.35 -5,982.01 3,519.43 6,021,800.21 537,179.97 0.52 6,353.22 2_MWD+IFR2+MS+Sag (2) 8,961.33 88.71 123.64 3,775.86 3,716.96 -6,034.73 3,597.27 6,021,747.84 537,258.04 1.20 6,447.19 2_MWD+IFR2+MS+Sag (2) 9,058.08 88.90 124.15 3,777.87 3,718.97 -6,088.68 3,677.56 6,021,694.27 537,338.57 0.56 6,543.87 2_MWD+IFR2+MS+Sag (2) 9,152.82 87.53 126.45 3,780.82 3,721.92 -6,143.39 3,754.84 6,021,639.91 537,416.08 2.82 6,638.55 2_MWD+IFR2+MS+Sag (2) 9,248.27 87.85 126.74 3,784.67 3,725.77 -6,200.25 3,831.41 6,021,583.40 537,492.90 0.45 6,733.92 2_MWD+IFR2+MS+Sag (2) 9,341.81 88.77 126.77 3,787.43 3,728.53 -6,256.20 3,906.32 6,021,527.80 537,568.06 0.98 6,827.40 2_MWD+IFR2+MS+Sag (2) 9,438.46 89.14 127.93 3,789.19 3,730.29 -6,314.82 3,983.14 6,021,469.53 537,645.13 1.26 6,924.00 2_MWD+IFR2+MS+Sag (2) 9,532.77 90.57 128.06 3,789.43 3,730.53 -6,372.88 4,057.46 6,021,411.82 537,719.71 1.52 7,018.23 2_MWD+IFR2+MS+Sag (2) 9,629.27 88.65 126.67 3,790.09 3,731.19 -6,431.43 4,134.15 6,021,353.61 537,796.65 2.46 7,114.69 2_MWD+IFR2+MS+Sag (2) 9,724.36 85.99 126.37 3,794.53 3,735.63 -6,487.96 4,210.48 6,021,297.44 537,873.23 2.82 7,209.66 2_MWD+IFR2+MS+Sag (2) 9,817.70 86.42 126.61 3,800.71 3,741.81 -6,543.34 4,285.36 6,021,242.40 537,948.35 0.53 7,302.79 2_MWD+IFR2+MS+Sag (2) 9,912.87 87.04 126.36 3,806.14 3,747.24 -6,599.84 4,361.75 6,021,186.25 538,024.99 0.70 7,397.79 2_MWD+IFR2+MS+Sag (2) 10,009.62 90.76 127.88 3,808.00 3,749.10 -6,658.20 4,438.86 6,021,128.24 538,102.36 4.15 7,494.48 2_MWD+IFR2+MS+Sag (2) 10,104.55 90.94 128.10 3,806.59 3,747.69 -6,716.63 4,513.67 6,021,070.16 538,177.42 0.30 7,589.33 2_MWD+IFR2+MS+Sag (2) 10,200.87 89.08 126.44 3,806.57 3,747.67 -6,774.95 4,590.32 6,021,012.19 538,254.32 2.59 7,685.61 2_MWD+IFR2+MS+Sag (2) 10,296.20 89.95 125.25 3,807.38 3,748.48 -6,830.77 4,667.59 6,020,956.73 538,331.84 1.55 7,780.93 2_MWD+IFR2+MS+Sag (2) 10,391.21 89.14 125.32 3,808.13 3,749.23 -6,885.65 4,745.14 6,020,902.20 538,409.63 0.86 7,875.94 2_MWD+IFR2+MS+Sag (2) 10,486.30 89.27 124.86 3,809.45 3,750.55 -6,940.31 4,822.94 6,020,847.90 538,487.67 0.50 7,971.01 2_MWD+IFR2+MS+Sag (2) 10,581.18 88.96 124.30 3,810.92 3,752.02 -6,994.16 4,901.05 6,020,794.42 538,566.01 0.67 8,065.86 2_MWD+IFR2+MS+Sag (2) 10,676.00 88.22 124.08 3,813.25 3,754.35 -7,047.42 4,979.46 6,020,741.51 538,644.65 0.81 8,160.61 2_MWD+IFR2+MS+Sag (2) 10,771.35 89.21 124.13 3,815.39 3,756.49 -7,100.87 5,058.39 6,020,688.43 538,723.81 1.04 8,255.89 2_MWD+IFR2+MS+Sag (2) 10,867.00 88.90 124.23 3,816.97 3,758.07 -7,154.60 5,137.50 6,020,635.06 538,803.17 0.34 8,351.49 2_MWD+IFR2+MS+Sag (2) 10,961.41 89.33 124.96 3,818.43 3,759.53 -7,208.20 5,215.21 6,020,581.82 538,881.11 0.90 8,445.87 2_MWD+IFR2+MS+Sag (2) 11,056.70 88.90 125.43 3,819.90 3,761.00 -7,263.11 5,293.07 6,020,527.27 538,959.21 0.67 8,541.14 2_MWD+IFR2+MS+Sag (2) 11,151.86 88.77 125.91 3,821.83 3,762.93 -7,318.59 5,370.36 6,020,472.14 539,036.74 0.52 8,636.28 2_MWD+IFR2+MS+Sag (2) 11,247.39 90.81 128.31 3,822.18 3,763.28 -7,376.22 5,446.54 6,020,414.86 539,113.17 3.30 8,731.78 2_MWD+IFR2+MS+Sag(2) 11,342.14 93.16 129.21 3,818.90 3,760.00 -7,435.50 5,520.37 6,020,355.93 539,187.26 2.66 8,826.33 2_MWD+IFR2+MS+Sag (2) 11,437.81 92.23 128.58 3,814.40 3,755.50 -7,495.50 5,594.75 6,020,296.27 539,261.90 1.17 8,921.76 2_MWD+IFR2+MS+Sag (2) 11,533.64 92.60 128.04 3,810.37 3,751.47 -7,554.85 5,669.87 6,020,237.26 539,337.29 0.68 9,017.41 2_MWD+IFR2+MS+Sag(2) 11,627.74 89.69 127.35 3,808.49 3,749.59 -7,612.37 5,744.31 6,020,180.08 539,411.98 3.18 9,111.43 2_MWD+IFR2+MS+Sag (2) 11,723.06 89.70 128.45 3,808.99 3,750.09 -7,670.93 5,819.52 6,020,121.88 539,487.45 1.15 9,206.68 2_MWD+IFR2+MS+Sag (2) 11,818.91 89.76 128.99 3,809.44 3,750.54 -7,730.88 5,894.30 6,020,062.27 539,562.49 0.57 9,302.40 2_MWD+IFR2+MS+Sag (2) 11,914.14 88.59 128.69 3,810.82 3,751.92 -7,790.60 5,968.47 6,020,002.89 539,636.92 1.27 9,397.49 2_MWD+IFR2+MS+Sag (2) 12,009.50 90.63 128.81 3,811.46 3,752.56 -7,850.28 6,042.83 6,019,943.55 539,711.54 2.14 9,492.71 2_MWD+IFR2+MS+Sag (2) 12,104.18 88.65 129.35 3,812.06 3,753.16 -7,909.96 6,116.33 6,019,884.21 539,785.30 2.17 9,587.23 2_MWD+IFR2+MS+Sag (2) 12,200.16 88.22 126.38 3,814.68 3,755.78 -7,968.85 6,192.06 6,019,825.67 539,861.29 3.13 9,683.10 2_MWD+IFR2+MS+Sag (2) 12,294.90 89.58 124.35 3,816.50 3,757.60 -8,023.67 6,269.30 6,019,771.21 539,938.77 2.58 9,777.81 2_MWD+IFR2+MS+Sag (2) 12,388.79 90.87 124.49 3,816.13 3,757.23 -8,076.74 6,346.75 6,019,718.49 540,016.45 1.38 9,871.67 2_MWD+IFR2+MS+Sag (2) 12,482.81 90.07 123.69 3,815.36 3,756.46 -8,129.43 6,424.61 6,019,666.16 540,094.54 1.20 9,965.65 2_MWD+IFR2+MS+Sag (2) 101141201912:59:17PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M -17i Project: Milne Point TVD Reference: MPU M-17 Actual RKB @ 58.90usft Site: M Pt Moose Pad MD Reference: MPU M-17 Actual RKB @ 58.90usft Well: MPU M -17i North Reference: True Wellbore: MPU M -17i Survey Calculation Method: Minimum Curvature Design: MPU M -17i Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 12,580.07 89.45 123.62 3,815.77 3,756.87 -8,183.33 6,505.57 6,019,612.63 540,175.73 0.64 10,062.84 2 MWD+IFR2+MS+Sag (2) 12,674.61 91.93 123.70 3,814.63 3,755.73 -8,235.72 6,584.24 6,019,560.60 540,254.64 2.62 10,157.30 2_MWD+IFR2+MS+Sag (2) 12,769.84 91.68 123.59 3,811.63 3,752.73 -8,288.46 6,663.48 6,019,508.23 540,334.11 0.29 10,252.41 2_MWD+IFR2+MS+Sag (2) 12,866.38 92.17 123.94 3,808.39 3,749.49 -8,342.08 6,743.69 6,019,454.97 540,414.55 0.62 10,348.84 2_MWD+IFR2+MS+Sag (2) 12,960.66 94.65 123.78 3,802.78 3,743.88 -8,394.52 6,821.84 6,019,402.90 540,492.92 2.64 10,442.89 2_MWD+IFR2+MS+Sag (2) 13,056.50 95.14 125.56 3,794.60 3,735.70 -8,448.83 6,900.37 6,019,348.94 540,571.69 1.92 10,538.36 2_MWD+IFR2+MS+Sag (2) 13,151.30 94.02 125.22 3,787.03 3,728.13 -8,503.56 6,977.41 6,019,294.57 540,648.97 1.23 10,632.85 2_MWD+IFR2+MS+Sag (2) 13,246.68 90.56 124.36 3,783.22 3,724.32 -8,557.93 7,055.66 6,019,240.56 540,727.46 3.74 10,728.13 2_MWD+IFR2+MS+Sag (2) 13,342.78 88.15 123.87 3,784.30 3,725.40 -8,611.82 7,135.21 6,019,187.04 540,807.25 2.56 10,824.17 2_MWD+IFR2+MS+Sag (2) 13,438.11 87.22 123.42 3,788.15 3,729.25 -8,664.59 7,214.51 6,019,134.63 540,886.77 1.08 10,919.36 2_MWD+IFR2+MS+Sag (2) 13,532.69 88.16 124.25 3,791.96 3,733.06 -8,717.21 7,293.00 6,019,082.37 540,965.50 1.33 11,013.80 2_MWD+IFR2+MS+Sag (2) 13,627.42 87.66 124.64 3,795.42 3,736.52 -8,770.76 7,371.07 6,019,029.18 541,043.80 0.67 11,108.44 2_MWD+IFR2+MS+Sag (2) 13,722.20 88.90 125.53 3,798.26 3,739.36 -8,825.21 7,448.59 6,018,975.09 541,121.56 1.61 11,203.17 2_MWD+IFR2+MS+Sag (2) 13,818.54 88.34 125.42 3,800.58 3,741.68 -8,881.10 7,527.03 6,018,919.55 541,200.24 0.59 11,299.48 2_MWD+IFR2+MS+Sag (2) 13,910.77 88.59 124.89 3,803.06 3,744.16 -8,934.19 7,602.41 6,018,866.81 541,275.85 0.64 11,391.67 2_MWD+IFR2+MS+Sag (2) 14,008.29 87.66 125.00 3,806.25 3,747.35 -8,990.02 7,682.30 6,018,811.35 541,355.99 0.96 11,489.13 2_MWD+IFR2+MS+Sag (2) 14,103.22 88.03 126.08 3,809.82 3,750.92 -9,045.16 7,759.49 6,018,756.57 541,433.42 1.20 11,583.99 2_MWD+IFR2+MS+Sag (2) 14,199.04 90.26 126.21 3,811.25 3,752.35 -9,101.66 7,836.85 6,018,700.42 541,511.03 2.33 11,679.79 2_MWD+IFR2+MS+Sag (2) 14,293.55 91.18 124.58 3,810.06 3,751.16 -9,156.40 7,913.89 6,018,646.04 541,588.30 1.98 11,774.28 2_MWD+IFR2+MS+Sag (2) 14,388.06 91.30 125.16 3,808.01 3,749.11 -9,210.42 7,991.41 6,018,592.37 541,666.06 0.63 11,868.76 2_MWD+IFR2+MS+Sag (2) 14,483.03 91.68 125.77 3,805.54 3,746.64 -9,265.50 8,068.73 6,018,537.64 541,743.62 0.76 11,963.70 2_MWD+IFR2+MS+Sag (2) 14,578.68 89.76 126.44 3,804.34 3,745.44 -9,321.86 8,146.00 6,018,481.64 541,821.14 2.13 12,059.33 2_MWD+IFR2+MS+Sag (2) 14,672.26 89.76 127.16 3,804.73 3,745.83 -9,377.91 8,220.93 6,018,425.93 541,896.31 0.77 12,152.90 2_MWD+IFR2+MS+Sag (2) 14,766.53 91.37 129.20 3,803.80 3,744.90 -9,436.18 8,295.03 6,018,368.01 541,970.66 2.76 12,247.07 2_MWD+IFR2+MS+Sag (2) 14,863.15 89.76 127.40 3,802.85 3,743.95 -9,496.05 8,370.84 6,018,308.48 542,046.74 2.50 12,343.59 2_MWD+IFR2+MS+Sag (2) 14,958.63 90.38 124.05 3,802.73 3,743.83 -9,551.79 8,448.34 6,018,253.10 542,124.49 3.57 12,439.05 2_MWD+IFR2+MS+Sag (2) 15,053.32 90.19 124.29 3,802.26 3,743.36 -9,604.98 8,526.69 6,018,200.28 542,203.06 0.32 12,533.70 2_MWD+IFR2+MS+Sag (2) 15,148.91 89.82 124.06 3,802.25 3,743.35 -9,658.67 8,605.77 6,018,146.95 542,282.38 0.46 12,629.25 2_MWD+IFR2+MS+Sag (2) 15,243.96 90.75 125.91 3,801.78 3,742.88 -9,713.17 8,683.64 6,018,092.81 542,360.49 2.18 12,724.29 2_MWD+IFR2+MS+Sag (2) 15,338.95 89.82 123.90 3,801.31 3,742.41 -9,767.52 8,761.54 6,018,038.82 542,438.62 2.33 12,819.26 2_MWD+IFR2+MS+Sag (2) 15,434.11 88.71 122.52 3,802.53 3,743.63 -9,819.63 8,841.14 6,017,987.07 542,518.45 1.86 12,914.31 2_MWD+IFR2+MS+Sag (2) 15,528.70 87.29 123.42 3,805.83 3,746.93 -9,871.07 8,920.45 6,017,935.99 542,597.98 1.78 13,008.73 2_MWD+IFR2+MS+Sag (2) 15,622.83 86.12 123.78 3,811.24 3,752.34 -9,923.08 8,998.72 6,017,884.35 542,676.48 1.30 13,102.63 2_MWD+IFR2+MS+Sag (2) 15,718.56 85.25 124.82 3,818.44 3,759.54 -9,976.87 9,077.58 6,017,830.92 542,755.57 1.41 13,198.05 2_MWD+IFR2+MS+Sag (2) 15,814.33 87.79 126.77 3,824.26 3,765.36 -10,032.77 9,155.10 6,017,775.37 542,833.34 3.34 13,293.64 2_MWD+IFR2+MS+Sag (2) 15,909.63 89.02 127.42 3,826.91 3,768.01 -10,090.23 9,231.09 6,017,718.26 542,909.58 1.46 13,388.87 2_MWD+IFR2+MS+Sag (2) 16,003.85 88.77 127.29 3,828.73 3,769.83 -10,147.39 9,305.97 6,017,661.45 542,984.71 0.30 13,483.04 2_MWD+IFR2+MS+Sag (2) 16,099.05 90.63 126.11 3,829.23 3,770.33 -10,204.28 9,382.29 6,017,604.91 543,061.28 2.31 13,578.22 2_MWD+IFR2+MS+Sag (2) 16,194.29 90.75 125.48 3,828.08 3,769.18 -10,259.98 9,459.54 6,017,549.57 543,138.77 0.67 13,673.45 2_MWD+IFR2+MS+Sag (2) 16,288.77 90.56 125.45 3,827.00 3,768.10 -10,314.79 9,536.48 6,017,495.11 543,215.96 0.20 13,767.92 2_MWD+IFR2+MS+Sag (2) 10/1412019 12:59:17PM Page 6 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M -17i Wellbore: MPU M -17i Design: MPU M -17i Survey MD Inc Azi TVD TVDSS +N/ -S (usft) (') (1) (usft) (usft) (usft) 16,384.92 89.26 125.24 3,827.15 3,768.25 -10,370.41 16,479.73 89.45 125.22 3,828.22 3,769.32 -10,425.10 16,574.28 88.65 126.06 3,829.78 3,770.88 -10,480.19 16,669.95 89.52 126.00 3,831.31 3,772.41 -10,536.45 16,765.80 90.32 125.75 3,831.45 3,772.55 -10,592.62 16,827.72 90.56 126.25 3,830.97 3,772.07 -10,629.02 16,900.00 90.56 126.25 3,830.26 3,771.36 -10,671.75 Local Co-ordinate Reference: Well MPU M -17i TVD Reference: MPU M-17 Actual RKB @ 58.90usft MD Reference: MPU M-17 Actual RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Map Map Vertical +E/ -W Northing Easting DLS Section (usft) (ft) (ft) V/1001) (ft) Survey Tool Name 9,614.91 6,017,439.85 543,294.63 1.37 13,864.07 2 MWD+IFR2+MS+Sag (2) 9,692.35 6,017,385.51 543,372.30 0.20 13,958.87 2_MWD+IFR2+MS+Sag (2) 9,769.18 6,017,330.78 543,449.37 1.23 14,053.40 2_MWD+IFR2+MS+Sag (2) 9,846.53 6,017,274.87 543,526.98 0.91 14,149.06 2_MWD+IFR2+MS+Sag (2) 9,924.20 6,017,219.06 543,604.89 0.87 14,244.91 2_MWD+IFR2+MS+Sag (2) 9,974.29 6,017,182.90 543,655.14 0.90 14,306.83 2_MWD+IFR2+MS+Sag (2) 10,032.58 6,017,140.43 543,713.62 0.00 14,379.10 PROJECTED to TD Digill',ig-d by Chelsea Ben aurin Hand Oigilllysig-d by Benjamin Hand Checked By: Chelsea Wright Wdghlu,9.i0.4,i.42.44-oe00 Approved By: J Date: 20,9.,0.,414:,3:44-08-00' Date: 10-14-2019 10/142019 12:59:17PM Page 7 COMPASS 5000.15 Build 91 Lease & Well No. County TF) 799Ann Hilcorp Energy Company CASING & CEMENTING REPORT MP M-17 State Alaska Supv. CASING RECORD Surface cr,. nom,- 7 077 nn Date Run 1 -Oct -19 1. Yessak / C. Demoski / J. Vanderpo Csg Wt. On Hook: 150,000 Type Float Collar: Innovex No. Hrs to Run: 25.5 Csg Wt. On Slips: Casing (Or Liner) Detail Rotate Csg X Yes No Recip Csg X Yes _ No Ft. Min. 9.2 PPG Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 TXP BTC -SR Innovex 1.60 7,277.00 7,275.40 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 76.50 7,275.40 7,198.90 1 Float Collar 103/4 40.0 TXP BTC -SR Innovex 1.30 7,198.90 7,197.60 1 Casing 95/8 50.0 L-80 TXP BTC -SR Tenaris 39.19 7,197.60 7,158.41 1 Baffle Adapter 103/4 40.0 Density (ppg) 9.2 Rate (bpm): 5 Volume (actual / calculated): 441.8/442.98 TXP BTC -SR HES 1.47 7,158.41 7,156.94 117 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 4,630.93 7,156.94 2,526.01 1 1 Pup Joint 95/8 1 40.0 L-80 I TXP BTC -SR Tenaris 15.49 2,526.01 2,510.52 1 ESC II 103/4 40.0 Sacks: 04 Yield: 4.41 TXP-BTC-SR HES 2.85 2,510.52 2,507.67 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 13.56 2,507.67 2,494.11 62 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,442.94 2,494.11 51.17 1 Cut Joint of Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.41 1 51.17 32.76 -No 22:41 Date: 10/2/2019 Estimated TOC: 34 Method Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 439.5 Total Volume cmt Pumped: 722.2 Cmt returned to surface: Csg Wt. On Hook: 150,000 Type Float Collar: Innovex No. Hrs to Run: 25.5 Csg Wt. On Slips: 110,000 Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes _ No Ft. Min. 9.2 PPG Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner top Packer?: No Liner hanger test pressure: _Yes _ Floats Held X Yes No Centralizer Placement: _ 104 each 9-5/8" x 12-1/2" Expand-o4zer centralizers ran. 2 each with 4 stop rings on joint #1. 1 free floating on joint #2. 1 each on joint #3 & 4 with 4 stop rings. 1 each on joints #5 to #25 then every other joint to #101. Every joint from #116 to 9125. 1 each with 1 stop ring on each pup joint above and below ESIPC between joints #120 & #121. Every otherjoint from #127 to #181. CEMENTING REPORT Shoe @ 7277 FC @ 7,199.00 Top of Liner Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Lead Sacks:650 Yield: 2.35 Density (ppg) 12 Volume pumped (BBLs) 270 Mixing / Pumpi a (bpm): 5 Tail Slurry w Type: Tail Sacks: 400 Yield: 1.16 F Density (ppg) 15.8 Volume pumped (BBLs) 82 Mixing / Pumpi at. (bpm): 4.7 y r - Post Flush (Spacer) x Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.2 Rate (bpm): 5 Volume (actual / calculated): 441.8/442.98 FCP (psi): 600 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1100 Casing Rotated? X Yes _ No Reciprocated? X Yes -No % Returns during job 100 Cement returns to surface? Yes X No Spacer returns? X Yes _ No Vol to Surf. 0 Cement In Place At: 11:30 Date: 10/2/2019 Estimated TOC: 2,528 Method Used To Determine TOC: Calculated & Spacer returns to surface from ESC II Stage Collar @ 2510 Type ESC II Closure OK Y Preflush (Spacer) Type: Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry 0 Type: Permafrost L Sacks: 04 Yield: 4.41 Density (ppg) 10.7 Volume pumped (BBLs) 314 -Mixing/Pumping m): 6 Tail Slurry w r, Type: Tail Sacks: 270 Yield: 1.17 y Density (ppg) 15.8 Volume pumped (BBLs) 56.2 Mixing / Pumpin a (bpm): 4.7 z Post Flush (Spacer) Q0 Type: Density (ppg) Rate (bpm): Volume: w Displacement: Type: Spud Mud Density (ppg) 9.2 Rate (bpm): 6 Volume (actual / calculated): 169.48/170.64 FCP (psi): 370 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1520 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes -No Spacer returns? X Yes Vol to Surf: 170 Cement In Place At: -No 22:41 Date: 10/2/2019 Estimated TOC: 34 Method Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 439.5 Total Volume cmt Pumped: 722.2 Cmt returned to surface: 170 Calculated cement left in wellbore: 552.2 OH volume Calculated: 400 OH volume actual: 512.4 Actual % Washout: 28.1 www.wellez.net WellEz Information Management LLC ver 04818br 4N tit -(7 Regg, James B (CED) Z lel' From: Sent: To: Subject: Attachments: Brooks, Phoebe L (CED) Wednesday, October 16, 2019 3:19 PM Regg, James B (CED) FW: [EXTERNAL] RE: MIT MPU M-17 10/14/2019 MIT MPU M-17 10-14-19 .xlsx Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law, if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brookstu)alaska.gov. From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Wednesday, October 16, 2019 2:53 PM To: Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL] RE: MIT MPU M-17 10/14/2019 That is correct. Thanks. From: Brooks, Phoebe L (CED)[mailto:phoebe.brooks@alaska.gov] Sent: Wednesday, October 16, 2019 11:13 AM To: Sloan Sunderland <ssunderland@hilcorD.com> Subject: [EXTERNAL] RE: MIT MPU M-17 10/14/2019 Sloan, Should the Type Inj be "N"? Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooksCa;alaska.gov. From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Tuesday, October 15, 2019 3:10 PM To: Regg, James B (CED) <jim.re E_@alaska.gov>; Brooks, Phoebe L (CED) <phoebe. brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe. bay@alas)<a.gov>; Wallace, Chris D (CED) <chris.waIlace @alasl<a.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com> Subject: MIT MPU M-17 10/14/2019 See attached Pre MIT for M-17. Thanks Sloan Sloan Sunderland Hilcorp North Slope Sr Drilling Forman Office 907-670-3090 Cell- 907-715-0591 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.reoa()alaska.aow A013CC.Inspectors0alaska.gov: phoebe. brooks(rDalaska.cov OPERATOR: Hilcorp Alaska LLC FIELD / UNIT / PAD: Milne Point, MPU, M Pad DATE: 10/14/19 OPERATOR REP: Sloan Sunderland AOGCC REP: chhs.wallace(dlalaska. cov 1� l�� �`1 Well M-17 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, S = Slurry PTD 219-125 Type Inj N Tubing 0 0 0 0 0 0 Type Test P Packer TVD 3675 - BBLPump 6.0 IA 0 2625 2525 J 2700 - 2675 - 2660 - Interval 0 Test psi 1500 BBL Return 6.0 - OA Result P Notes: - Witness waived by Matt Herrera on 10/13/2019 at 0540. Initial, pre-injection MIT -IA performed on the ng. Pressure bumped up to 2700 psi at 30 min to restart/finish test above 2500 psi. Monobore injector, no OA. 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 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 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: 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 10-426 (Revised 01/2017) MIT MPU M-17 10-14-19_ THE STATE GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-17 Hilcorp Alaska, LLC Permit to Drill Number: 219-125 Surface Location: 5914' FSL, 531' FEL, SEC. 14, TI 3N, R9E, UM, AK Bottomhole Location: 486' FNL, 1025' FEL, SEC. 30, T13N, R10E, 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, Daniel T. Seamount, Jr. Commissioner l DATED this 4 qday of September, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 SEP 0 9 2019 A �"%cc 1 a. Type of Work: 1b.. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑Q - Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑� ` Single Zone ❑✓ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU M-17 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 16,888' TVD: 3,754' ' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4914' FSL, 531' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL025515, ADL025517 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 104' FNL, 1653' FWL, Sec 24, T13N, R9E, UM, AK LONS 16-004 9/22/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 486' FNL, 1025' FEL, Sec 30, T13N, R10E, UM, AK 7659 5175' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.6 15. Distance to Nearest Well Open Surface: x-533633 • y- 6027765 ' Zone -4 GL / BF Elevation above MSL (ft): 24.9 to Same Pool: 800' to MPJ -20A 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: 1654 Surface: 1276 • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 113' Surface Surface 113' 113' -270 ft3 Stg 1-L-1514ft3/T- 458ft3 12-1/4" 9-5/8" 40# L-80 TXP 7,218' Surface Surface 7,218' , 3,754' Stg2-L-1937ft3/T-314ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 9,820' 1 7,068 3,736' 16,888 3,754' Cementless Injection Liner ICDs Tieback 3-1/2" 9.3# L-80 TUE 8RD 7,068' Surface Surface 1 7,068' 3,736' Tieback 9. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No Q 20. Attachments: Property Plat ❑ BOP Sketch B Drilling Program Time v. Depth Plot ❑ e Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirementse 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'gn gl hllCOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: yn[ cy ate: ( f ZD Iq Co mission Use Only Permit to Drill / API Number: '�''"� Permit Appro See cover letter for other Number: Z/��C �� 50- 0��•—•�_3 `"ZZ Date: requirements. Conditions of approval : If box is checked, well maynotbe used to explore for, test, or produce coalbe methane„gas hydrates, or gas contained in shales: [� Other: ( �5 L � � e5 ! Samples req'd: Yes El No [/ Mud log req'd: Yes H2Smeasures: Yes E]No [�. Directional svy req'd: Yes ❑ PNoo Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes o 9' Post initial injection MIT req'd: Yes 0 No ❑ APPROVED BY / Approved COM IS O E T E O MISSION ��� Date: j �} Submit Form and 40* agJ�ggyi;e�1�5/2�17 / This permit is valid for 24 month t e a p 0 AAC 25.005( Att�h/�},ents in uplicate e Area of Review MPM-11 CBL Top of CBL Top of Top of SB Top of SB Cement Cement Schrader OA PTD API WELL STATUS OA (MD) OA (TVD) (MD) (TVD) status Zonal Isolation 183-182 50-029-24057-00-00 MPM-01 P&A'd 4,613' 3,763' Surface Surface Closed Well fully P&A'd with cement to surface 184-033 50-029-24057-01-00 MPM-01A P&A'd 4,989' 3,676' Surface Surface Closed Well fully P&A'd with cement to surface 219-061 50-029-23631-00-00 MPM-16 SB Producer 6,651' 3,809' Surface Surface Open Open to injection support 219-070 50-029-23632-00-00 MPM-18 SB Producer 7,988' 3,717' Surface Surface Open Open to injection support 207-014 20-029-23343-00-00 Liviano 01 P&A'd 3,948' 3,819' Surface Surface Closed Well fully P&A'd with • cement to surface 207-021 50-029-23343-01-00 Liviano 01A P&A'd 3,892' 3,823' Surface Surface Closed Well fully P&A'd with cement to surface Surface casing was run to 8,664' MD and cemented back to surface. 200-149 50-029-22976-00-00 MPJ -24 P&A'd 8,253' 3,852' Surface Surface Closed Lateral was drilled in SB and sand later abandoned. Retainer set at 7,576' MD and pump 193 sx / 46 bbls of cement thru. Well was sidetracked directl after abandonement. Surface casing was run to 8,664' MD 200-150 50-029-22976-60-00 MPJ -24L1 P&A'd 8,253' 3,852' Surface Surface Closed and cemented back to surface. Lateral was drilled in SB OB sand. Long Term Shut -In produced water injector with an MBE to J-23. Had a passing MIT -IA on 6/3/2006. 7" casing 200-185 50-029-22832-01-00 MPJ -20A Shut in SB WINJ 10,896' 3,787' Surface Surface Open was cemented to surface with 618 bbls cement, 84 bbls excess to surface. 4.5" Liner cemented with 126 bbls cement. HILCORP ALASKA LLC 15 w 03\ \ \\ \ MILNE POINT FIELD \ \ \ \\\\ p \\ // \\\ AOR MAP M-17 Injector (Proposed) 2.000 3 MO MA3 I \ \ \\\� \\ \�\ FEET - I - i \\ \\ � \ \ \ \ \ �/ \\\ • � � WELLSYMBOLS M-01 SM \ REMMNS Well Symbols et top of Schrader Bluff OA Sand \ ` LIVI / 1 Black e of proposed M 7 dill wellldiu OA send in heel I\Ma18 \ 1 y� v v ss,>ns \ 1 LIVIAI'1A I // vv� vvvf vv vv �v vv vv \q -18\V X15 \` M-21 W IZ \ \ �J-24L1 \\\\ — — — — — y --- _� --,j�o9 -A8a \ IV J -20A KPAR K ER J 24 v J -09A U U R UNIT J-17 \ J-23 _J-22 l J -231L1 N-01 B' % Hilcorp Alaska, LLC Milne Point Unit (MPU) M-17 Drilling Program Version 1 9/5/2019 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 NIU 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP NIU and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................37 18.0 RDMO............................................................................................................................................38 19.0 Doyon 14 Diverter Schematic.......................................................................................................39 20.0 Doyon 14 BOP Schematic.............................................................................................................40 21.0 Wellhead Schematic......................................................................................................................41 22.0 Days Vs Depth................................................................................................................................42 23.0 Formation Tops & Information...................................................................................................43 24.0 Anticipated Drilling Hazards.......................................................................................................44 25.0 Doyon 14 Layout............................................................................................................................47 26.0 FIT Procedure................................................................................................................................48 27.0 Doyon 14 Choke Manifold Schematic..........................................................................................49 28.0 Casing Design.................................................................................................................................50 29.0 8-1/2" Hole Section MASP............................................................................................................51 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 31.0 Surface Plat (As Built) (NAD 27).................................................................................................53 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................54 33.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................55 Hilcorp E -w C -P -Y 1.0 Well Summary Milne Point Unit M-17 SB Injector Drilling Procedure Well MPU M-17 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 16,887' MD / 3,753' TVD PBTD, MD / TVD 16,877' MD / 3,753' TVD Surface Location (Governmental) 4914' FSL, 53 P FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533,633.87, Y= 6,027,765.65 Top of Productive Horizon (Governmental) 104' FNL, 1653' FWL, Sec 24, T13N, R9E, UM, AK TPH Location (NAD 27) X= 535,844 Y= 6,022,757 BHL (Governmental) 486' FNL, 1025' FEL, Sec 30, T13N, R10E, UM, AK BHL (NAD 27) X= 543,712 Y=6,017,138 AFE Number 1913622M (D,C,F) AFE Drilling Days 20 days AFE Completion Das 4 days AFE Drilling Amount $4,507,305 AFE Completion Amount $1,656,047 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1276 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1654 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 24.8 ft = 58.5 ft GL Elevation above MSL: 24.8 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 HilmTEnergy Company 2.0 Milne Point Unit M-17 SB Injector Drilling Procedure Management of Change Information 11 Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: 9/5/2019 Subject: Changes to Approved Permit to Drill for MPU M-17 File #: MPU M-17 Drilling and Completion Program Any modifications to MPU M-17 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: Prepared: Page 3 Drilling Manager Drilling Engineer Date Date Milne Point Unit M-17 SB Injector Hilco+rn�+ Drilling Procedure Energy Company 3.0 Tubular Program: Hole Section, 01) (in) ID : (in) Drift (in) Conn OD , (in) Wt I (#/ft)(psi) Grade Conn Burst Collapse (psi) Tension (k -lbs) Cond 20" 19.25" - - - X-52 Weld Min Max(k-lbs 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 8-1/2" 4-1/2" 3.96" 3.795" 4.714" 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2" 2.992" 1 2.867" 1 4.500" 9.3 L-80 EUE 8Rn 9289 7399 163 4.0 Drill Pipe Information: Hole OD ID, ,I TJ ID TJ OD Wt Grade C nn M/U M/U Tension Section in in in #/ft Min Max(k-lbs Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Hilcorp E ... Sy Company 5.0 Internal Reporting Requirements Milne Point Unit M-17 SB Injector Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolinighilcorp.com, mmyers e,hilcor)_ jengelghilcorp.com and cdin erghilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mm, ers o,hilcorp,com jen el o,hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers(c�r�,hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 ien�el@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 ff xilcorp E—W C..woy 6.0 Planned Wellbore Schematic Ctg. KB Eev.: 5&,5/GL Eev.:2A_51 TD=1£ALW{MD}/TD=4758 q PBTD=143V {tu0} / P5rD=3,75d'{TW} Page 6 Milne Point Unit M-17 SB Injector Drilling Procedure Milne Point unit Well: MPU M-17 Proposed Schematic PTD: TBD API: TBD ------ --- ------------- - -- -- -- --- ------------------ TREE &WELLHEAD Tree Cameron 31/&" SM w/41/15" SM Cameron WL Wahead Carneran i 1" SK x Wjpl{ AX bcetom w/ 121 2-1/i5' SK cuts ---------------------------------------------------------------------------- OPEN HOLE/ CEMENT DETAIL 42" SO bbl% (10 Yards ZkVZ4trdumped dawn backsidel 12-if4" �1-Lead 1514U12.0ppg./Tail 458R315.8OM Sig 2 -Lead 1937 ft310.7 ga/ Tail 314 ft315.9 8gg 6-1/2" 1 CCVXA1gM Injection Liner in 8-1/2" hale CASING DETAIL Size Type Wt Grade/Conn DriRiO Top gn 6PF 2SYk Candunarllnsulatedl 215.5/X-12/'Well N/A Surface 114' , WA 9-5/6" Surface 40 / L-80 / T) P &679" Surface 7,218' . 0.0759 4-1/2" Liner 13S/L-60/ 525 3.795" 7,068' 16,6&6 0.0149 5 17,068' TUBING DETAIL 2.592" Lower Comp tan 3-1/2" 1 Tubin 93 L-80 EUE 8RD 1 2.867' 1 Sud 1 7 C68 OA670 WELL INCLINATION DETAIL KOP @4W IWeAn Ie@XN=TBD IWeAn a@Liner Top =TLID Max lime Angle =TBD U«_Ih U,v I Ml) I ND TBE T96 GENERAL WELL INFO APIA_ TBO Completed by Cu .m I& Future 0 JEWELRY DETAIL No Top MO I 'tem ID Upper Camp etian 1 22,352' 3.5" X Nipple 12.613" Packin Bnrej 2.1313" 2 15,500' 3.5" XN Mp a 2.813" Packs Bore; 275" No -Go 2.750" 3 17,009 3.T'Gauge Wndrel5GM-XPQG w/ 3G" Wire IM, 4 17',056' 8.26" No Go Lacaterw/ 7.375` Seal Aasembly 2.992" 5 17,068' 7.375" Tieback abcue the 5LZXP Liner Top Packer 2.592" Lower Comp tan 6 27,068' ZKP Liner Top Packer - 7 16,683" VAV INA an Seat/Closedl I - U«_Ih U,v I Ml) I ND TBE T96 GENERAL WELL INFO APIA_ TBO Completed by Cu .m I& Future 0 Milne Point Unit M-17 SB Injector E—HyHiHilco+TT�+I Drilling Procedure l Company 7.0 Drilling / Completion Summary MPU M-17 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-17 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 August 20, 2019, pending rig schedule. Surface casing will be run to 7,218 MD / 3,753' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP. Install MPD Riser 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner. 6. Run 3-1/2" tubing. 7. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: ; 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Milne Point Unit M-17 SB Injector Hilcot+�t+� Drilling Procedure Energy Company 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-17. 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 Summary of BOP Equipment & Notifications Milne Point Unit M-17 SB Injector Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diver -ter w/ 16" Diver -ter 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" 0 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: jimxegg(a,alaska. og_v Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: g_uuy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppgalaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorskalaska.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 9.0 RX and Preparatory Work Milne Point Unit M-17 SB Injector Drilling Procedure 9.1 M-17 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 (<807). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 ff Hilcorp Energy Company 10.0 NX 21-1/4" 2M Diverter System Milne Point Unit M-17 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 Milne Point Unit M-17 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: • May change on location 75' Radius Clear of ignition Sources -�- Qiverter Line MPU M -Pad *Drawing Not To Scale Page 12 SEC- 13 $EC_ 1414 M-10 ■ I U-11 ■ I ■ I N-17 ■ t ■ N—a4 u-20 ■ I ■ N—as I f1 -� 4r M-17 75' Radius Clear of ignition Sources -�- Qiverter Line MPU M -Pad *Drawing Not To Scale Page 12 Hilcorp Energy C..p—y 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-17 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. i 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. ---- Page 13 Hilcorp Energy, Milne Point Unit M-17 SB Injector Drilling Procedure J 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: M-01 is an abandoned MPU appraisal well. Any collision risk is minimal as the well is plugged and abandoned. - 11.4 12-1/4" hole mud program summary: Page 14 • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. 4 Depth Interval MW (ppg) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. - Milne Point Unit M-17 SB Injector Hilco}rp Drilling Procedure Energy Company • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point I API FL pH I Tem Surface 1 8.8-9.8-1 75-175 1 20-40 1 25-45 1 <10 1 8.5-9.0 1 <70F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme LTL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 1 55 1 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 15 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-17 SB Injector Drilling Procedure 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 PIU shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar 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 En=u r=paRY 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ALAID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Section 5 Page 17 "A Overall Length B Mr. ID After Drlllout C Max. Tool OD D Opening Seat ID E Closing Seat ID Plug Set Part No. SO 4 Closing Piu% U— Opening Plug OD OD Shut-off Plug OD Bypass Plug cif used) OD Milne Point Unit M-17 SB Injector Drilling Procedure i Hikmp ES41 Running Order ES4I Cementer Shat Off Plug Baffle Adapter By -Vass Rug By Pass Baffle Float Collar Float sloe i Milne Point Unit M-17 SB Injector Hilcor P 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 jts (Top of Ugnu) Utilize a collar clamp until weight is sufficient to keep slips set properly. Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 Milne Point Unit M-17 SB Injector Hilco Drilling Procedure Energy c—� TXPG BTC Outside Diameter 9-625 :n. Min_ Wall 87.5% PERFORMANCE Thickness r +int2 Wd Strength l') Grade LSO 1111111111111116,Type Its 1 Compression SuenTzh WallThi_.knoss 0-395 n. Connection OD REGULAR Its Option COUPLING PIPE BODY Body: Red IstBand: Red Jrad= LSO Type: 1' Drift API Standard 1st Sand: Brown 2nd Band: 2nd Band: - Brown Type Casing 3rd Band: - 3rd Band: - 4th Band: - PIPE BODY DATA GEOMETRY P4cminal00 9.625 in. Nominal lNeight 401ts1ft Drift &.679 it Nominal ID 8.83.', in. V&H Thickne-9s 0.395 in. Plain End Weight 38.97 th-1 OD Too--w7ce AN PERFORMANCE Body'Y-Wd Streng^.h 916 x10D0 lbs lrlema --1 5750 psi SMYS 8@D@@ ps Ccplapse 3090 psi GEOMETRY Connecton OD 10.625 in. Coupling Lerng-lh 10.825 in. Connection ID 11.823 Make-up Loss 4.831 in. Threids per in 5 Connection OD Oplen REGULAR PERFORMANCE Tension Efrx:ienvy 100.0% r +int2 Wd Strength 916.000 x1000 Internal Pressure Capac rj 111 5750.000 psi Its Compression EiFicienc,w 100% Compression SuenTzh 916.000 x1000 Max. Allowable Sending 38 1l100 ft Its Exlemal P essnse Casecity 3090.900 ps MAKE-UPTORQUES ASgdanum 18860 ft -':s Optimum 20960 Nbs Maximum 23060 Nts OPERATION LIMIT TORQUES Operate:^y =q.e 35600 zt-':s Yield Torque 43400 ft -lbs Notes This connection is fully interchangeable with: TXP9, BTC - 9.625 in_ - 36 143-5 147 1 53.5 15$.4 Ibstft [1] Internal Pressure Capacity related to structural resistance only. Intemal pressure leak resistance as per section 10.3 API 5C3 1 150 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. Page 19 Milne Point Unit M-17 SB Injector Hilco`rn�+ Drilling Procedure Ene`gy Compmy 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 Energy Company 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-17 SB Injector Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1St Stage Total Cement Volume: Page 21 '2) C1, -^ Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" _0(6,218' - 2500') x .0558 bpf x 1.3 = 270 1514 Casing Total Lead 270 1514 12-1/4" CH x 9-5/8" (7,218'- 6,218') x .0558 bpf x 1.3 = 72.5 407 — Casing 8" Shoe Track P5/Total 120'x .0758 bpf = 9.1 51.09 Tail 81.6 458 Page 21 '2) C1, -^ Milne Point Unit M-17 SB Injector Hilcoix Drilling Procedure Encrgy Company 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: L 7,098' x.0758 bpf = 538 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 istool & 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 ` 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: L 7,098' x.0758 bpf = 538 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 istool & 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 ff Hilcorp Milne Point Unit M-17 SB Injector Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -Il 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 Second Stage Surface Cement Job: Milne Point Unit M-17 SB Injector Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre -job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd 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 t C) _Sri x,70 s, 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 t C) _Sri x,70 s, Milne Point Unit M-17 SB Injector Hilcot+7�+� Drilling Procedure Energy Company 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 ien elkhilcorp. com and cdin eerrghilcoW.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 14.0 BOP NX and Test Milne Point Unit M-17 SB Injector Drilling Procedure 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/LJ 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5" BOP test plug p� 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 /y • Confirm test pressures with PTD l2 • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) Milne Point Unit M-17 SB Injector Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RX and test casing to 2 si / 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 Milne Point Unit M-17 SB Injector Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg F1oPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 1 15-30 4-6 <10% <8 <1 1.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE -GARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Page 28 V_` Milne Point Unit M-17 SB Injector Hilco Drilling Procedure E -V C.®� 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 0A1 & 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: J-24 — 15,420' MD. J-24 is an abandoned SB OA well, any collision risk is minimal due to the abandoned lateral. J -24A is an active SB NB injector. There is minimal risk with J -24A. J-27 is an active SB NB producer. There is minimal risk with J-27. • Fluid Loss: • Losses have been seen after crossing a fault and drilling into the depleted reservoir near J-24. M-13 will not cross the same fault and losses are not expected. If losses are seen, LCM pills have healed losses. • Schrader Bluff OA Concretions: 5-10% of lateral Page 29 • L-47: 6%, L-50 9.5% Milne Point Unit M-17 SB Injector Drilling Procedure • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • 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 25011 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 Page 30 0 Hilcorp E=rW C=P=Y Milne Point Unit M-17 SB Injector Drilling Procedure 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. / 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..W C..pgy 16.0 Run 4-1/2" Injection Liner (Lower Completion) Milne Point Unit M-17 SB Injector Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: • With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2" and 5" test joints to 250 psi low/3000 psi high. 16.3. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.5. Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-1/2" 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). • 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 1/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-17 SB Injector Drilling Procedure • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 33 For the latest performance data, always visit our website: wv, i,,.tenaris.com Wedge 6256 Milne Point Unit M-17 SB Injector Drilling Procedure 12/04/2{)17 Outside Diameter 4.500 as. Min. Wall 87.5`6 3.849 in_ Make-up Loss 4.830 n Thickness 3.53 (e) Grade LBO REGULAR PERFORMANCE Type 1 Wail Thickness 0290 . Connection OD REGULAR Tension Eincie^,ry 91.0% Joint Yield Brength Option Internal Pressure Capacity COUPLING PIPE BODY Itis Body Red Ist Banc: Red Grade LBO Type 1' I Drift API Standard 1stBand: Brown 2nd Band: 73.7 °71GO It 2n.a Band: - Brown Type Casing Sac Band: - 3: Hand: - 4th Band -- GEOMETRY Nominal 00 4.500 in, Nominal Weitt Nominal IC 3.920 c. Wail Thickness CO Tok-ance AN 13.50 ,v'ft Drift 3.795 fi. 0290 in. Rain £n: Weight 13.05bvft PERFORMANCE Body Y'*ba SGength 307 x10X lbs Internal Yield 9020 pss. SMYS 80000 ps Collapse B!W ps, Connec,on 00 4.714 az. Connemara ID 3.849 in_ Make-up Loss 4.830 n Threads in 3.53 Conne:tim 00 Option REGULAR PERFORMANCE Tension Eincie^,ry 91.0% Joint Yield Brength 279.370 x1 DOD Internal Pressure Capacity 9020.000 psi Itis Compression Efic;rzy 94.5% Compression Strength 290.115 x1OW Max_ Morrable Bending 73.7 °71GO It lbs External Pressure Capacity BWMO psi MAKE-UP TORQUES Minimum BODO Nbs optinwm 9600 £t-Itn Maximacn 12800 fNbs OPERATION LIMIT TORQUES cper—g Torque 12800 Nbs Yield Torcue 15004 Ribs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenwis_com 16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 16.7. RX false rotary and run 2-3/8" 6.4#/ft inner string. Page 34 Milne Point Unit M-17 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. Rig up to pump down the work string with the rig pumps. 16.19. Break circulation and begin displacing wellbore to —9.2 ppg KCl/NaCl (adjust brine weight if needed). Note the large OD on the ICDs. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the -ICDs. Note all losses. Catch mud for future use if feasible. 16.21. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin pumping SAPP pill. 16.22. Mix and pump 3 tandem 40 bbl 10 ppb SAPP pills (120 bbl total SAPP pill) with 100 bbl in between. Keep circulation rate low to keep from packing off around the ICDs. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Page 35 Milne Point Unit M-17 SB Injector Hilco+Tf�+f Drilling Procedure Energy Cowpony 16.23. Repeat pumping SAPP pills as needed until the wellbore is clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Monitor the returned fluids to ensure as much mud and wall cake has been removed from the wellbore as possible so as to not impact wellbore injectivity. 16.24. Displace 1.5 OH & Liner volumes. 16.25. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.26. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.27. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.29. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.30. Displace 2-3/8" x Liner, pump 2 circulations. 16.31. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean outrun 16.32. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.33. Flush liner top at max rate while displacing out well to clean brine. 16.34. POOH LD Remaining 5" DP. Page 36 V/ 17.0 Run 3-1/2" Tubing (Upper Completion) Milne Point Unit M-17 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 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 3-1/2" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-%2" 9.3#/ft, L-80 EUE 8RD tubing • 3-%2" "X -N" nipple at TBD • 3-1/2" 9.34/ft, L-80 EUE 8RD tubing • 3-%2" "X" nipple at TBD MD • 3—%2" 9.3#/ft, L-80 EUE 8RD space out pups • 1 joint 3-I/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. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 37 Milne Point Unit M-17 SB Injector Hilco+{�}+� Drilling Procedure E..W Com, 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 — 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and I% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 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 3 8 19.0 Doyon 14 Diverter Schematic 21-1.14'2M Riser -- 21-1-4' 2M— D"rtes Ir 21-114' 28 Sp— Spur 16-W4. 3M r 2t -114.2M DSA Page 39 Milne Point Unit M-17 SB Injector Drilling Procedure –16' 6u® Opening Knife Valve 16" Dimmer Llm Milne Point Unit M-17 SB Injector Hilco Drilling Procedure �W �m 20.0 Doyon 14 BOP Schematic Kill Line Page 40 2-7/8" x 5" VBR Blind Rams x 5M HCR ,hoke Lina if Gate Valle 2-7/8" x 5" VBR ff HilmT��a�r 21.0 Wellhead Schematic 0 Milne Point Unit M-17 SB Injector Drilling Procedure Vote: Dm- n nal infoaaation reflected on thi: d—.g are eslimat +* ENS only. Page 41 Hfi mE—U Comp 22.0 Days Vs Depth N we AIS r - 8000 0 v 10000 v 12000 .r� Page 42 MPU M-17 SB OA Injector Days vs Depth Milne Point Unit M-17 SB Injector Drilling Procedure jector 0 S 10 15 20 25 30 Days 23.0 Formation Tops & Information Milne Point Unit M-17 SB Injector Drilling Procedure MPU M-17 Formations (Wp05) MD (ft) TVDss ND (ft) (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2284 1785 1843 811 8.46 LA3 5329 3070 3128 1376 8.46 Schrader Bluff NA 6406 3517 3575 1573 8.46 Schrader Bluff OA 7350 3702 3760 1654 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST ss GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS As G a NOTE: See individual Well Program for Ta_ o Gubik specific casing design, depths, sizes, :-uei' 6W weights, grades and connections. Unconsolidated coarse to modWm sand and small gavel with minor siftstone. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' a ARE ENCOUNTERED WHEN DRILLING THE ♦m SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. +Iso• Base permafrost Inlarbeds of sand• clays and slitsrones with occasional 2,000' show of coal. Wath possible sidetracking while waahing7roaeNng. L33 E L-15. Sagaw rktok -4il�ar No hydrates encountered on L -Pad wells drilled to date. ---- continued int rbeds of sand• clays and siRsbnes with occasional shows of coal. Traces of pyrite at -1. 3100 it 3,000- Interval at -7. 3400 it can be sticky and tight (L-01). Clay Intarbeds between 3000 and 4500 It C 3472'. L A 365r tceanes Y UGNU: Series ofcoarsening upward sands which are (-Aa.cAi made up of: (from top to bottom) coarse sand fine sand. silty shale. Better developed Intervening *halos as you UGNU progress Into the L and M (deoper). Ugru and Schrador Stuff. Possible hydrocarbons limited L a rds to S W comer of Mllne development Northem aroa Is (AX) downstructure and wet. •3730• Wands (.A9.CI 4000' (Na) Schrader Bluff Sands: 4,000' (+e.c.o. continued layering coarsening upward sandaasabove -11111011111111 Schrader Bluff: Possible lost circulation EF) except more condensed and with occasional coat. zone whist: drilling long strings and running •4170• oaandh Day rich shate Interval 4300 to 4600 ft Ugnu and Schrader Bluft Possible hydrocarbons limited casing. Recommend deep setting surface (oa (•tiac, to SW comer of Milne development L37 and L-45 are casing for Kuparuk long strings. Also, the b.E•F) completed In the Schrader Bluff sand Northem aroa of Schrader Bluff sands are a potential Schrader L -Pad is downstructure and wet. differential stuck pipe interval if left un -cased Bluff C Surface casing point In shale below for Kuparuk long strings. Sands: r I Schrader Bluff OB *and for longer reach wells. Page 43 24.0 Anticipated Drilling Hazards Milne Point Unit M-17 SB Injector Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. M-13 has a close approach with a potential future well plan, which does not pose any risk. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: % Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 44 Milne Point Unit M-17 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if 142S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 45 Milne Point Unit M-17 SB Injector HilcEnergy Drilling Procedure C2i��ry+ 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: / Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M - Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. There are no wells with a separation factor of <1. Specific AC risk addressed in 8.5" hole section, 15. Page 46 Hil=�W 25.0 D 1 I T uvuu 14 1_.avvut Ln rn Page 47 Milne Point Unit M-17 SB Injector Drilling Procedure N V 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-17 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/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 48 r O N Ya7�7 RIG 14 LEGEND White Handled Valves Normally Open Red Handled Valves Normally Closed Date: 08-22-14 Rev. 3 NOTES: 1) Valve A is a 3-1/16" 5M Remote Operated Hydraulic Choke Valve. 2) Valve B is a 3-1/8" 5M Adjustable Choke Valve. 3) Valve I is a 2-1116" 5M Manual Gate Valve, 4) Valves 2-14 are 3-118" 5M Manual Gate Valves. Divert Line Brom BOP Divert Line .r To Mud/Gas Separator 28.0 Casing Design 11 Calculation & Casing Design Factors xitcorp ` DATE: 9/9/2019 WELL: MPU M-17 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Milne Point Unit M-17 SB Injector Drilling Procedure Drilling Mode MASP: 1276 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1276 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" 6-5/8" Top (MD) 0 7,218 Top (TVD) 0 3,753 Bottom (MD) 7,218 16,887 Bottom (TVD) 3,753 3,753 Length 7,218 91669 Weight (ppf) 40 20 Grade L-80 L-80 Connection TXP H562 Weight w/o Bouyancy Factor (lbs) 288,720 193,380 Tension at Top of Section (lbs) 288,720 193,380 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.17 2.37 Collapse Pressure at bottom (Psi) 1,854 1,854 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.67 1.87 MASP (psi) 1,276 1,276 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 4.51 4.77 Page 50 Milne Point Unit M-17 SB Injector Hilco Drilling Procedure F-- �2 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 Hilcor, 8 1/2" Hole Section F" MPU M-17 Milne Point Unit MD TVD Planned Top: 7218 3753 Planned TD: 16887 3753 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,753 1651 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW ranee Top (TVD) Bottom (TVD) Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore togas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,753 (ft) x 0.78(psi/ft)= 2927 2927(psi) - [0.1(psi/ft)*3753(ft)]= 2552 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 3753 (ft) x 0.44(psi/ft)= 1651 psi 1651(psi) - 0.1(psi/ft)*3753(ft) 1276 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 f Hilcorp aV —P-RY 30.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-17 SB Injector Drilling Procedure Scc 11 LADL388235Sec.17 -` ADL025509 'Sec7 L3AD550 -3• L -0Q - 1526) . ;`� r t♦ ' f , �i ♦ gr, �; mire LASPE� NJ PU -17i < , I':.:'v� �'\ /.+':=f.7r T� f /+J,t� P �♦ ! ..11 ::1 � 1 f ♦ � \ r / Y id ll a PEsi3LC t7 f ``, `>' .._L.3?. ,}/ +r }` 1 F.tS➢ ♦ F.13 `, 1 +� Se. 14 Sec. 13 ' \ r + ' r {630'1'\ + • + `'/ 1,1:1rF91 ' '• S y< + MILNE,POINT NI / ➢ l J aOLD I 551.4 t ?IPL'M- 7i T[E3 �___�- + °`. ADL•45515r r U013N009E i yIp '% , i% +' U013N010E -- ---- - - - -- /�r - ^-+ r -�,l s ".. ,. ..e� ----X14.. + + L 51 1 IRl-➢i / 1 . •'\\ Sec. 22 1 Se 24 Sec. 19 633) {633' JiL, E I + • . . :..1 IlL'z'6:l Tale • -J :t �\�- -fes\ EOUI AENT:PAG A1PU M -I 7a BHL Legend _----------- i ♦ MPV M-1_SHL Otter Surface Holes (SHL) -- - - - - - Jam+ ` T++ I`, MPV M-17i_TPH Otl- Barmen Holes (BHL) ADL025517 Sec_ 30 {G3+Ci} - - - Odw Wed Parks MPV M-17E-BHL ©------ - - - - - - - Oil and Gas Unit Boundary ,._ z^1; — Pad FooIprinq Alask,,a State Plane Zone 4 NAD 1,t7 2 Milne Paint Unit MPU M-17 Well 0 1.000 2,000 Ruo Wfa:492o779 wp 05 Feet Page 52 i ff HilcoN En.W - 31.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-17 SB Injector Drilling Procedure Page 53 12I / THS PROJECT -N- MOOSE L 7 PAD l SEt 12 I SEC. 13 _ _ SEG 1S 14 SCC 14 I M-10 ■ M PAA - 1 B M-11 .+ � ■ a M-13 I ,;DI n • t� M-ts ■ ■ M-14 i 23 19 M-20 ■ Mfg 9iE f ■ M-15 l[I M-21 + J a M 15 VICINITY MAPMAP j I N'IS i1 M-22 + M-17 M-18 I ��•pF q�� IN I `'.)P. INI + M-19 I >: .......... • . M I Im ' F. BOrnhDrt -W ■ 1 200 GRAPHIC SCALEI MOOSE PAD I -.4 0 100 209 000 i N STI t Inch - 200 P. LEGEND: .END: NOTES: SURVEYOR'S__ CERTIFICATE I HEREBY CER FY THAT I AM �Jy AS-BtIL.T CANDttCtIIR t ALASKA STATE RAW COORMATES ARE NA027. Z011E S PROPERLY RE=TERED AM LJCENS D TO PRACTICE LAND SWOTYINO N `ff 2 OEOWTIC P09TKNS ARE NA027. + THE STATE OF ALASKA AND THAT Y ■ FJOSiIN6 GOf10erCY0R 3 BAyg OF HORIZONTAL AND 11:'RTICAL C01TP.O4 IS µADE BY MEL(AUND YY DIRECT 97_ALCAP Sm NE SUPERHS.ON AND THAT ALL 4. NPU MOM A14ACAE PAA SCALE FACTOR IS. 094 WZ. DIMENSIONS AND OTHER DET,&S ARE CORRECT AS OF WAY 1, 2019. S. DATES OF SIIRLEY: MAY 1 @ 16, 2018. 4 FdYEREKCE FIELD BOOK: HGT9-03 POe 14-15 22-2& LOCATED WITHIN PROTRACTED SEC, 14, T, 13 N., R. 9 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR NO. COORDINATES COORDINATES POSITION DMS POSITION(D=) OFFSETS ELEVATION BOX EL. M-17 Y= 6.027,765.65 N- 1,168.00 70'29'12.792' 70.4868866' 4,914' FSL 24. 13' 24.9' X= 533,633.87 • E= 1,635.03 14943'30.357' 149.7250993' 531' FEL M-18 Y= 6,027,765.61 N= 1,167.96 70.29'12.793' 70.4868868' 4,915' FSL 24.6' 24.7' X= 533,60187 E= 1,605.02 149'43'31.240" 149.7253445' 561' FEL M-19 Y= 6,027,765.55 N• 1,167.90 70'29'12.796' 70.4868878' 4,915' FSL 24.9' 25.1' X= 533,513.82 E= 1,514.96 149'43'33.890" 149.7260805' 651' FEL M-21 Y- 6.027,889- 7 N- 1,292.14 70'29'14.007" 70.4872242' 5038' FSL 24,9' 25.0' X= 533,753.82 £= 1,754.99 149'43'26.811" 149.7241143' 411' FEL M-22 Y- 6,027,889.8,3 N= 1,292.20 70'29'14.012' 70.4872255' 5,039' FSL 25.0' 24.9' X= 533,663.95 E- 1,665.11 14943'29.456' 149.7248489' 500' FEL Emmmm Bell M.m RON=,uc muA VAL o am 11- Hilrnrp Alaska aAM NAM ART 0 Rbtl vat PAD 02 MPU MOOSE PAD AS -BUILT CONDUCTORS WELLS WELLS 17,18,19,21,22 1 1 v v asm WAM _ .n m aeau, In Page 53 Milne Point Unit M-17 SB Injector Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, PP8 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 [fill - EO 1500 2000 4= 0 2500 o -W 3500 W1�� 4500 Page 54 MPU L-46 (2015) MPU L-47 (2015) MPU L-48 (2015) - MPU L-49 (2015) MPU L-50 (2015) MPU F-106 (2017) MPU F-107 (2017) MPU F-108 (2017) MPU F-109 (2017) MPU F-110 (2017) Milne Point Unit M-17 SB Injector Drilling Procedure 33.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD In 5.ODO Pipe Body Wall Thickness m 0.362 Pipe Body Grade S-13:5 DrOl Pape Length EE02 Connection GPDS50 Tod Joint OD 6.625 Tool Joint ID I n, 3.250 Pin Tong 19 Box Tong rn: 12 80 % Inspection Class NO, To- mmkmae conneemri operau=21 Iensie, a MUT (r4) - 3T.NQ10(h4asr should be apgle-a. Nominal Weight Designation 19.50 Drill Pipe Approximate Length ;r:; 31.5 SmraothEdge Height (w)l 3132 Raised Tool Joint SPAYS (;w)l 120.000 Upset Type IEU 14ax Upset OD (DTE) on1 5.125 Fraction Factor 11.0 124 N.Y: Tgnq space may h lude 1'1arG,aClrq. Drill Pipe Performance Drill -Pipe Length Rangel Performance of Drill Pipe with Pipe Body at 80 % Insoectlon Class 1--m-143.100 Best Estimates Nominal ew=w CmOgl rWelFfXaer47) tleilt aemr"R 4.11 23.29 .37 0.36 MIMI 0.0085 0.70 0.72 0169 0 0167 0 0172 36,10D Tension �nty 0 560,800 Rerernlm nrur Draft Size 014 3.125 - L--2 32,100 467,400 NOR: On rald aarRl Bawls 42 us gall:ns. Nate: Dnll ppe asserntty'• 1- arc best esbrna s and tray vwj cl T to pipe body mill takerarCe, Irelemal plavlc.'. Q!rnP art] all-er txt_rs. Connection Performance GPOS50 ( 6.625 X1:1 OD x 3.250 - ID ) 120,000 rpm, 100 11 Node: The -1- makeap -41. should L. n0led whey. P -be NO, To- mmkmae conneemri operau=21 Iensie, a MUT (r4) - 3T.NQ10(h4asr should be apgle-a. 80 % Inspection Class Tool Joint Ton;ronalStrenoth m -n-) 171,800 o-, 712,100 560,8W Tool Joint Tensile Strength cosi I 1,250 ODD th4tsl 74,100 Elevator Shoulder Information 58,100 TS'PipeBody Torsional natio SmoothEdge Height 124 3x32 Raised 80% Pipe Torsional Strength x_l- 59,3013 Box OD _lrl 6.812 Burst ipsF 17.105 Elevator Capacity Obsi 165$000 w C r ec3nn Tool Joint Dimensions Balanced OD on 6.435 )6rtrn1 Tod Joxd OD 7ar.APl 5.930 ralgml PkDsass din: ker,- Tod Jgxd t3D mr 5.93 �ComterporcI Elevator OD 3132 Raised 6.812 mr Tool Joint Worn to Bevel Wom to Min TJ OD for DD I Diameter I API Prerniurn Class 521 Noat El-bl- [aWadty t -d- aswmed EL"ad- Hom_, M Liar tactor, and CML -1 sees or f 16,10Cps1. In Assumed Elevator Bore Diameter , Nose. A raked avatar OD Increases elevator [apathy -th-I anectnq -ke-up tafque Pipe Body Slip Crushing Capacity Pipe Body Configuration ( 5 mf OD 0.362 ria Wall S-135) Nominal I 80 % Inspection Class I API Premium Class ISlip Crushing Capacity rbs) 498„3DD 1396.50D 396.50D tYte: Sk0 Ca^. 1 Sip -ring =15 rao-� in! w41f rc 5{x1 -P hall Muatl rt Cam'Vft Cee: We Rpe Assumed Slip Length cd 16.5 Fal to TV up ARI` YYOM M 150 for aro SW lthgA 2W ta.6ellse ram fal1w shah, and I: tr refeurnae a*. up cnah q's co m tem S� the tip deso and o"tion, membem or hetet. 1wrq ami' bare, tt- n Transverse Load f=actor (KI 42 st mllpc�rwapany.am�+.arnmam� . C-AwmtneSAP nnarulaeLrerfttadcrR l rtametbn. Pipe Bodv Performance Pipe BGdy Confguraaian ( 5 - OD 0.362 - Wall S-135) N Y t Grant Page 55 N=e: Namenl Hurst cacuURd al R7.5% RB W per API. Nominal 80 % Inspection Class Apt Premium Class Pilpe Tensile Strength o-, 712,100 560,8W 560.8W Pipe Torsional Strength th4tsl 74,100 58,100 58,100 TS'PipeBody Torsional natio 0.97 124 1.24 80% Pipe Torsional Strength x_l- 59,3013 46.500 46,500 Burst ipsF 17.105 15,638 15,638 collapse _ ,pw, 15,672 10.029 I D,029 Pape OD am 5.ODD 4.855 4.855 Wall Thickness {m1 0.362 0290 0,290 Nontinal Pipe ID om, 4276 4276 4.276 Gross Sectional Area of Pipe Body _ w2l 5275 4.154 4.154 Gross Sectional Area of OD tet^21 19.635 18.514 18.514 Gross Sectional Area of ID 1r,^2,114 .361 14.360 14-360 Section Modulus {m^ar5:708 4.476 14.476 Polar Section Modulus rr,^31 11.415 8.953 18.953 N=e: Namenl Hurst cacuURd al R7.5% RB W per API. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -17i MPU M -17i Plan: MPU M-17 wp05 Standard Proposal Report 04 September, 2019 HALLIBURTON Sperry Drilling Services Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPUM-17i Wellbore: MPU M -17i Design: MPU M-17 wp05 Hilcerp Alaska, LLC Calculation Method: Minimum Curvature DDI = Enor System: ISCWSA Scan Method: Closest Approach 3D Error6,9jQ Surface: Pedal Curve Warning Method: Error Ratio REFERENCE INFORMATION Coordinate (N/E) Reference: Well Plan: MPU M-1 7i, True North Vertical (ND) Reference: MPU M-17 Planned RKB @ 58.60usft Measured Depth Reference: MPU M-17 Planned RKB @ 58.60usft Calculation Method: Minimum Curvature FORMATION TOP DETAILS No brmetlon Cela s a ailable CASING DETAILS DSS MD Size Name bb 5.00 7218.17 9-5/8 9 5/8" x 12 1/4' 5.00 16887.84 4-1/2 41/2'x81/2' ® F1AL116LJATON Sec MD Inc Azi ND +N/ -S +E/ -W Dleg TF- VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 End Dir : 2089' 8.MD, 1761.33' ND cD 1000 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 ca U StartDir 3°/100' : 400' MD, 400'ND 3 550.00 4.50 155.00 549.85 -5.34 2.49 3.00 155.00 5.14 4000 4 650.00 7.49 157.00 649.29 -14.90 6.69 3.00 5.00 14.14 Start Dir 4'/100': 650' MD, 649.29'ND 5 2088.90 65.04 159.96 1761.33 -779.42 291.18 4.00 3.18 692.01 End Dir : 2088.9' MD, 1761.33' ND 6 6173.01 65.04 159.96 3484.87 -4257.88 1559.92 0.00 0.00 3755.42 Start Dir 4°/100' : 6173.01' MD, 3484.87T7D 7 7118.17 84.00 125.79 3743.15 -4960.93 2108.00 4.00 -65.68 4611.17 End Dir : 7118.17' MD, 3743.15' ND 8 7218.17 84.00 125.79 3753.60 -5019.09 2188.67 0.00 0.00 4710.62 M -17i v P03 Heel Start Dir 4-/100': 7218.17' MD, 3753.6T/D 97369.35 90.05 125.79 3761.45 -5107.35 2311.08 4.00 0.02 4861.53 End Dir : 7369.35' MD, 3761.45' ND 10 16687.84 90.05 125.79 3753.60 -10674.18 10031.95 0.00 0.00 14380.01 M -17i w 04 Toe Total Depth : 16887.84' MD, 3753.6' ND �O ro yA' �O m� o� Q "o MPU M-17 wpO5 41/2"x81/2" 0 0 0 0 0 0 0 o M-171 wpO4 T- -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 Vertical Section at 125.79° (2000 usfUin) WELL DETAILS: Plan: MPU MAT 24.90 -1000 Validated: Ves Version: +N/ -S +E/ -W Northing Easting Latittude Longitude Depth Fmm Depth To 0.00 0.00 6027765.65 533633.87 70' 29' 12.792 N 149° 43'30357 W Tool 33.70 0 Start Dir 3°/100' : 400' MD, 400'ND O C -c - Start Dir 4'/100' : 650' MD, 649.29'TVD 7218.17 MPU M-17 wp05 (MPU M -17i) 2_MW D+IFR2+MS+Sag End Dir : 2089' 8.MD, 1761.33' ND cD 1000 000 1 O FO n O y O N N, ryyo a �D' L 00 �a N 2000- 000 ca U h o g > 3000 �Q 2 Oe F 4000 9 5/8" x 12 1/4" o 0 o a coir < o a o 0 0 i 0 0 0 o M -17i wp03 Heel 5000 �O ro yA' �O m� o� Q "o MPU M-17 wpO5 41/2"x81/2" 0 0 0 0 0 0 0 o M-171 wpO4 T- -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 Vertical Section at 125.79° (2000 usfUin) SURVEY PROGRAM Date: 2017-11-14T00:00:00 Validated: Ves Version: Depth Fmm Depth To Survey/Plan Tool 33.70 1000.00 MPU M-17 wp05 (MPU M -17i) 2_Gyro-NS-GC_Dnll cellar 1000.00 7218.17 MPU M-17 wp05 (MPU M -17i) 2_MW D+IFR2+MS+Sag 7218.17 16887.84 MPU M-17 vrp05 MPUM-17i) 2_MWO+IFR2+MS+Sag �O ro yA' �O m� o� Q "o MPU M-17 wpO5 41/2"x81/2" 0 0 0 0 0 0 0 o M-171 wpO4 T- -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 Vertical Section at 125.79° (2000 usfUin) C_ 1 SUrt Dir 3'/100': 400' MD, 400'NU " \ S1:u1 Dir 4"/100': 650' MD, 649.29n'VD \ End Dir : 2088.9' MD, 1761.33' TVD (r - Project: Milne Point WELL DETA°-s: PI—MPUM-n; Site: M Pt Moose Pad 24.90 Well: Plan: MPU M -17i �N/-s +Fr -w Nunhinghng 1al;u„dp rungwde Wellbore: MPU M -17i O.W 000 6027765.65 533633.87 70"29'12.792N 149.43'30.35]W Plan: MPU M-17 wp05 CASMG DETAILS — TVD TVDSS MD Size Name ® NALLIBURTON 3753.60 3695.00 7218.17 9-5/8 95/8"x121/4" 3753.60 3695.00 16887.84 4-112 41/2"x81/2" sPs�ry o�nn..y REFERENCE INFORMATION C Minale (N/E) Reference: Well Plan: MPU M -17i, True North Vertical (rVD) Reference: MPU M-17 Planned RKB M.60usft Measured Depth Reference: MPU M-17 Planned RKB @ S3.6nus% Delwlalion MCNad: WWI— Curvature SOvt Dv 4'/100': 617301' MD, 3484.87 -TVD End Dir : 7118.17' MD, 3743.15' TVD Start Dv 4V I00' : 7218.17' MD, 3753.6 FVD 95/8"x121/4"�H.l - EndDir : 7369.35'MD,376145'TVD M -17i up03 41 e lh" T,11 Dcpth : ,' 1688].84' MID, 3753.6' TVD 2"x M-1 7i upfH T. - - - MPU M-17 wp05 �I T�-r-I -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 West( -)/East(+) (1500 1 fthn) Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -17i Wellbore: MPU M -17i Design: MPU M-17 wp05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -17i TVD Reference: MPU M-17 Planned RKB @ 58.60usft MD Reference: MPU M-17 Planned RKB @ 58.60usft 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: 6,027,877.65usft Latitude: From: Map Easting: 533,363.92 usft Longitude: Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: Well Plan: MPU M -17i Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore MPU M -17i 6,027,765.65 usfl Latitude: 533,633.87 usfl Longitude: usfl Ground Level: Magnetics Model Name Sample Date Declination BGGM2018 Design MPU M-17 wp05 Audit Notes: (') 9/18/2019 16.45 Dip Angle 80.95 70° 29' 13.905 N 149° 43'38.286 W 0.26 70° 29' 12.792 N 149° 43'30.357 W 24.90 usft Field Strength (nT) 57,413.47746579 Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 125.79 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (1) (1 (usft) usft (usft) (usft) (°/100usft) (°1100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -24.90 0.00 0.00 0.00 0.00 0.00 0.00 400.00 0.00 0.00 400.00 341.40 0.00 0.00 0.00 0.00 0.00 0.00 550.00 4.50 155.00 549.85 491.25 -5.34 2.49 3.00 3.00 0.00 155.00 650.00 7.49 157.00 649.29 590-69 -14.90 6.69 3.00 2.99 2.00 5.00 2,088.90 65.04 159.96 1,761.33 1,702.73 -779.42 291.18 4.00 4.00 0.21 3.18 6,173.01 65.04 159.96 3,484.87 3,426.27 -4,257.88 1,559.92 0.00 0.00 0.00 0.00 7,118.17 84.00 125.79 3,743.15 3,684.55 -4,960.93 2,108.00 4.00 2.01 -3.62 -65.68 7,218.17 84.00 125.79 3,753.60 3,695.00 -5,019.09 2,188.67 0.00 0.00 0.00 0.00 7,369.35 90.05 125.79 3,761.45 3,702.85 -5,107.35 2,311.08 4.00 4.00 0.00 0.02 16,887.84 90.05 125.79 3,753.60 3,695.00 -10,674.18 10,031.95 0.00 0.00 0.00 0.00 9/4/2019 12.49:OOPM Page 2 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -17i Wellbore: MPU M -17i Design: MPU M-17 wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -17i TVD Reference: MPU M-17 Planned RKB @ 58.60usft MD Reference: MPU M-17 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -24.90 33.70 0.00 0.00 33.70 -24.90 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 100.00 0.00 0.00 100.00 41.40 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 200.00 0.00 0.00 200.00 141.40 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 300.00 0.00 0.00 300.00 241.40 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 400.00 0.00 0.00 400.00 341.40 0.00 0.00 6,027,765.65 533,633.87 0.00 0.00 Start Dir 3°/100' : 400' MD, 400'TVD 500.00 3.00 155.00 499.95 441.35 -2.37 1.11 6,027,763.28 533,634.99 3.00 2.28 550.00 4.50 155.00 549.85 491.25 -5.34 2.49 6,027,760.33 533,636.38 3.00 5.14 600.00 6.00 156.25 599.63 541.03 -9.50 4.37 6,027,756.17 533,638.28 3.00 9.10 650.00 7.49 157.00 649.29 590.69 -14.90 6.69 6,027,750.79 533,640.63 3.00 14.14 Start Dir 40/100' : 650' MD, 649.29'TVD 700.00 9.49 157.68 698.74 640.14 -21.71 9.53 6,027,743.98 533,643.50 4.00 20.43 800.00 13.49 158.43 796.71 738.11 -40.19 16.96 6,027,725.54 533,651.01 4.00 37.26 900.00 17.49 158.84 893.06 834.46 -65.06 26.67 6,027,700.72 533,660.83 4.00 59.68 1,000.00 21.49 159.10 987.32 928.72 -96.19 38.63 6,027,669.65 533,672.93 4.00 87.59 1,100.00 25.48 159.29 1,079.01 1,020.41 -133.44 52.78 6,027,632.47 533,687.25 4.00 120.85 1,200.00 29.48 159.42 1,167.71 1,109.11 -176.61 69.05 6,027,589.37 533,703.71 4.00 159.30 1,300.00 33.48 159.53 1,252.97 1,194.37 -225.52 87.35 6,027,540.55 533,722.23 4.00 202.74 1,400.00 37.48 159.61 1,334.38 1,275.78 -279.90 107.61 6,027,486.26 533,742.73 4.00 250.98 1,500.00 41.48 159.69 1,411.55 1,352.95 -339.51 129.71 6,027,426.77 533,765.10 4.00 303.77 1,600.00 45.48 159.75 1,484.09 1,425.49 -404.04 153.56 6,027,362.35 533,789.24 4.00 360.86 1,700.00 49.48 159.80 1,551.66 1,493.06 -473.19 179.04 6,027,293.32 533,815.03 4.00 421.96 1,800.00 53.48 159.85 1,613.92 1,555.32 -546.62 206.02 6,027,220.02 533,842.34 4.00 486.79 1,900.00 57.48 159.89 1,670.57 1,611.97 -623.96 234.37 6,027,142.81 533,871.04 4.00 555.02 2,000.00 61.48 159.93 1,721.34 1,662.74 -704.85 263.96 6,027,062.07 533,900.99 4.00 626.32 2,088.90 65.04 159.96 1,761.33 1,702.73 -779.42 291.18 6,026,987.63 533,928.54 4.00 692.01 End Dir : 2088.9' MD, 1761.33' TVD 2,100.00 65.04 159.96 1,766.02 1,707.42 -788.87 294.63 6,026,978.19 533,932.03 0.00 700.34 2,200.00 65.04 159.96 1,808.22 1,749.62 -874.04 325.69 6,026,893.17 533,963.48 0.00 775.35 2,300.00 65.04 159.96 1,850.42 1,791.82 -959.21 356.76 6,026,808.15 533,994.93 0.00 850.36 2,400.00 65.04 159.96 1,892.62 1,834.02 -1,044.39 387.82 6,026,723.13 534,026.37 0.00 925.36 2,500.00 65.04 159.96 1,934.82 1,876.22 -1,129.56 418.89 6,026,638.11 534,057.82 0.00 1,000.37 2,600.00 65.04 159.96 1,977.02 1,918.42 -1,214.73 449.95 6,026,553.09 534,089.27 0.00 1,075.38 2,700.00 65.04 159.96 2,019.23 1,960.63 -1,299.90 481.02 6,026,468.07 534,120.72 0.00 1,150.39 2,800.00 65.04 159.96 2,061.43 2,002.83 -1,385.07 512.09 6,026,383.05 534,152.16 0.00 1,225.40 2,900.00 65.04 159.96 2,103.63 2,045.03 -1,470.24 543.15 6,026,298.03 534,183.61 0.00 1,300.40 3,000.00 65.04 159.96 2,145.83 2,087.23 -1,555.41 574.22 6,026,213.01 534,215.06 0.00 1,375.41 3,100.00 65.04 159.96 2,188.03 2,129.43 -1,640.58 605.28 6,026,127.99 534,246.50 0.00 1,450.42 3,200.00 65.04 159.96 2,230.23 2,171.63 -1,725.75 636.35 6,026,042.97 534,277.95 0.00 1,525.43 3,300.00 65.04 159.96 2,272.43 2,213.83 -1,810.92 667.41 6,025,957.95 534,309.40 0.00 1,600.44 3,400.00 65.04 159.96 2,314.63 2,256.03 -1,896.09 698.48 6,025,872.92 534,340.84 0.00 1,675.44 3,500.00 65.04 159.96 2,356.83 2,298.23 -1,981.26 729.54 6,025,787.90 534,372.29 0.00 1,750.45 3,600.00 65.04 159.96 2,399.04 2,340.44 -2,066.43 760.61 6,025,702.88 534,403.74 0.00 1,825.46 3,700.00 65.04 159.96 2,441.24 2,382.64 -2,151.60 791.67 6,025,617.86 534,435.19 0.00 1,900.47 3,800.00 65.04 159.96 2,483.44 2,424.84 -2,236.77 822.74 6,025,532.84 534,466.63 0.00 1,975.48 9/42019 12:49:OOPM Page 3 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -17i Wellbore: MPU M-171 Design: MPU M-17 wp05 Planned Survey Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (1) (usft) usft (usft) 3,900.00 65.04 159.96 2,525.64 2,467.04 -2,321.94 4,000.00 65.04 159.96 2,567.84 2,509.24 -2,407.11 4,100.00 65.04 159.96 2,610.04 2,551.44 -2,492.28 4,200.00 65.04 159.96 2,652.24 2,593.64 -2,577.45 4,300.00 65.04 159.96 2,694.44 2,635.84 -2,662.63 4,400.00 65.04 159.96 2,736.64 2,678.04 -2,747.80 4,500.00 65.04 159.96 2,778.85 2,720.25 -2,832.97 4,600.00 65.04 159.96 2,821.05 2,762.45 -2,918.14 4,700.00 65.04 159.96 2,863.25 2,804.65 -3,003.31 4,800.00 65.04 159.96 2,905.45 2,846.85 -3,088.48 4,900.00 65.04 159.96 2,947.65 2,889.05 -3,173.65 5,000.00 65.04 159.96 2,989.85 2,931.25 -3,258.82 5,100.00 65.04 159.96 3,032.05 2,973.45 -3,343.99 5,200.00 65.04 159.96 3,074.25 3,015.65 -3,429.16 5,300.00 65.04 159.96 3,116.45 3,057.85 -3,514.33 5,400.00 65.04 159.96 3,158.66 3,100.06 -3,599.50 5,500.00 65.04 159.96 3,200.86 3,142.26 -3,684.67 5,600.00 65.04 159.96 3,243.06 3,184.46 -3,769.84 5,700.00 65.04 159.96 3,285.26 3,226.66 -3,855.01 5,800.00 65.04 159.96 3,327.46 3,268.86 -3,940.18 5,900.00 65.04 159.96 3,369.66 3,311.06 -4,025.35 6,000.00 65.04 159.96 3,411.86 3,353.26 -4,110.52 6,100.00 65.04 159.96 3,454.06 3,395.46 -4,195.69 6,173.01 65.04 159.96 3,484.88 3,426.28 -4,257.88 Start Dir 40/100' : 6173.01' MD, 3484.87'TVD 1,872.19 6,023,019.75 6,200.00 65.49 158.88 3,496.17 3,437.57 -4,280.83 6,300.00 67.21 154.94 3,536.30 3,477.70 -4,365.06 6,400.00 69.04 151.10 3,573.57 3,514.97 -4,447.72 6,500.00 70.94 147.36 3,607.80 3,549.20 -4,528.43 6,600.00 72.92 143.70 3,638.82 3,580.22 -4,606.78 6,700.00 74.96 140.12 3,666.49 3,607.89 -4,682.38 6,800.00 77.06 136.61 3,690.68 3,632.08 -4,754.88 6,900.00 79.20 133.16 3,711.25 3,652.65 -4,823.92 7,000.00 81.38 129.76 3,728.11 3,669.51 -4,889.16 7,100.00 83.60 126.40 3,741.18 3,682.58 -4,950.29 7,118.17 84.00 125.79 3,743.15 3,684.55 -4,960.93 End Dir : 7118.17' MD, 3743.15' ND 7,200.00 84.00 125.79 3,751.70 3,693.10 -5,008.52 7,218.17 84.00 125.79 3,753.60 3,695.00 -5,019.09 Start Dir 4°/100' : 7218.17' MD, 3753.6'TVD - 9 5/8" x 12 1/4" 7,300.00 87.27 125.79 3,759.82 3,701.22 -5,066.80 7,369.35 90.05 125.79 3,761.45 3,702.85 -5,107.35 End Dir : 7369.35' MD, 3761.45' TVD 7,400.00 90.05 125.79 3,761.42 3,702.82 -5,125.27 7,500.00 90.05 125.79 3,761.34 3,702.74 -5,183.76 Halliburton Standard Proposal Report Well Plan: MPU M -17i MPU M-17 Planned RKB @ 58.60usft MPU M-17 Planned RKB @ 58.60usft True Minimum Curvature 9/4/2019 12:49:OOPM Page 4 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,467.04 853.80 6,025,447.82 534,498.08 0.00 2,050.49 884.87 6,025,362.80 534,529.53 0.00 2,125.49 915.93 6,025,277.78 534,560.97 0.00 2,200.50 947.00 6,025,192.76 534,592.42 0.00 2,275.51 978.06 6,025,107.74 534,623.87 0.00 2,350.52 1,009.13 6,025,022.72 534,655.31 0.00 2,425.53 1,040.19 6,024,937.70 534,686.76 0.00 2,500.53 1,071.26 6,024,852.68 534,718.21 0.00 2,575.54 1,102.32 6,024,767.65 534,749.65 0.00 2,650.55 1,133.39 6,024,682.63 534,781.10 0.00 2,725.56 1,164.45 6,024,597.61 534,812.55 0.00 2,800.57 1,195.52 6,024,512.59 534,844.00 0.00 2,875.57 1,226.58 6,024,427.57 534,875.44 0.00 2,950.58 1,257.65 6,024,342.55 534,906.89 0.00 3,025.59 1,288.71 6,024,257.53 534,938.34 0.00 3,100.60 1,319.78 6,024,172.51 534,969.78 0.00 3,175.61 1,350.85 6,024,087.49 535,001.23 0.00 3,250.61 1,381.91 6,024,002.47 535,032.68 0.00 3,325.62 1,412.98 6,023,917.45 535,064.12 0.00 3,400.63 1,444.04 6,023,832.43 535,095.57 0.00 3,475.64 1,475.11 6,023,747.41 535,127.02 0.00 3,550.65 1,506.17 6,023,662.38 535,158.46 0.00 3,625.66 1,537.24 6,023,577.36 535,189.91 0.00 3,700.66 1,559.92 6,023,515.29 535,212.87 0.00 3,755.43 1,568.53 6,023,492.38 535,221.59 4.00 3,775.84 1,604.47 6,023,408.32 535,257.90 4.00 3,854.24 1,646.57 6,023,325.86 535,300.37 4.00 3,936.74 1,694.64 6,023,245.38 535,348.81 4.00 4,022.94 1,748.45 6,023,167.28 535,402.96 4.00 4,112.40 1,807.73 6,023,091.95 535,462.57 4.00 4,204.70 1,872.19 6,023,019.75 535,527.35 4.00 4,299.39 1,941.51 6,022,951.03 535,596.99 4.00 4,396.00 2,015.37 6,022,886.13 535,671.13 4.00 4,494.06 2,093.40 6,022,825.37 535,749.43 4.00 4,593.11 2,108.00 6,022,814.79 535,764.07 4.00 4,611.17 2,174.01 6,022,767.50 535,830.29 0.00 4,692.55 2,188.67 6,022,757.00 535,845.00 0.00 4,710.62 2,254.85 6,022,709.59 535,911.38 4.00 4,792.20 2,311.08 6,022,669.31 535,967.79 4.00 4,861.53 2,335.94 6,022,651.50 535,992.73 0.00 4,892.18 2,417.05 6,022,593.39 536,074.10 0.00 4,992.18 9/4/2019 12:49:OOPM Page 4 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -17i Wellbore: MPU M -17i Design: MPU M-17 wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -17i TVD Reference: MPU M-17 Planned RKB @ 58.60usft MD Reference: MPU M-17 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Vertical Northing Easting DLS Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W (usft) (1) (1) (usft) usft (usft) (usft) 7,600.00 90.05 125.79 3,761.26 3,702.66 -5,242.24 2,498.17 7,700.00 90.05 125.79 3,761.17 3,702.57 -5,300.73 2,579.28 7,800.00 90.05 125.79 3,761.09 3,702.49 -5,359.21 2,660.40 7,900.00 90.05 125.79 3,761.01 3,702.41 -5,417.69 2,741.51 8,000.00 90.05 125.79 3,760.93 3,702.33 -5,476.18 2,822.63 8,100.00 90.05 125.79 3,760.84 3,702.24 -5,534.66 2,903.74 8,200.00 90.05 125.79 3,760.76 3,702.16 -5,593.15 2,984.86 8,300.00 90.05 125.79 3,760.68 3,702.08 -5,651.63 3,065.97 8,400.00 90.05 125.79 3,760.60 3,702.00 -5,710.12 3,147.09 8,500.00 90.05 125.79 3,760.51 3,701.91 -5,768.60 3,228.20 8,600.00 90.05 125.79 3,760.43 3,701.83 -5,827.09 3,309.31 8,700.00 - 90.05 125.79 3,760.35 3,701.75 -5,885.57 3,390.43 8,800.00 90.05 125.79 3,760.27 3,701.67 -5,944.05 3,471.54 8,900.00 90.05 125.79 3,760.18 3,701.58 -6,002.54 3,552.66 9,000.00 90.05 125.79 3,760.10 3,701.50 -6,061.02 3,633.77 9,100.00 90.05 125.79 3,760.02 3,701.42 -6,119.51 3,714.89 9,200.00 90.05 125.79 3,759.94 3,701.34 -6,177.99 3,796.00 9,300.00 90.05 125.79 3,759.85 3,701.25 -6,236.48 3,877.12 9,400.00 90.05 125.79 3,759.77 3,701.17 -6,294.96 3,958.23 9,500.00 90.05 125.79 3,759.69 3,701.09 -6,353.44 4,039.35 9,600.00 90.05 125.79 3,759.61 3,701.01 -6,411.93 4,120.46 9,700.00 90.05 125.79 3,759.53 3,700.93 -6,470.41 4,201.57 9,800.00 90.05 125.79 3,759.44 3,700.84 -6,528.90 4,282.69 9,900.00 90.05 125.79 3,759.36 3,700.76 -6,587.38 4,363.80 10,000.00 90.05 125.79 3,759.28 3,700.68 -6,645.87 4,444.92 10,100.00 90.05 125.79 3,759.20 3,700.60 -6,704.35 4,526.03 10,200.00 90.05 125.79 3,759.11 3,700.51 -6,762.84 4,607.15 10,300.00 90.05 125.79 3,759.03 3,700.43 -6,821.32 4,688.26 10,400.00 90.05 125.79 3,758.95 3,700.35 -6,879.80 4,769.38 10,500.00 90.05 125.79 3,758.87 3,700.27 -6,938.29 4,850.49 10,600.00 90.05 125.79 3,758.78 3,700.18 -6,996.77 4,931.61 10,700.00 90.05 125.79 3,758.70 3,700.10 -7,055.26 5,012.72 10,800.00 90.05 125.79 3,758.62 3,700.02 -7,113.74 5,093.83 10,900.00 90.05 125.79 3,758.54 3,699.94 -7,172.23 5,174.95 11,000.00 90.05 125.79 3,758.45 3,699.85 -7,230.71 5,256.06 11,100.00 90.05 125.79 3,758.37 3,699.77 -7,289.20 5,337.18 11,200.00 90.05 125.79 3,758.29 3,699.69 -7,347.68 5,418.29 11,300.00 90.05 125.79 3,758.21 3,699.61 -7,406.16 5,499.41 11,400.00 90.05 125.79 3,758.12 3,699.52 -7,464.65 5,580.52 11,500.00 90.05 125.79 3,758.04 3,699.44 -7,523.13 5,661.64 11,600.00 90.05 125.79 3,757.96 3,699.36 -7,581.62 5,742.75 11,700.00 90.05 125.79 3,757.88 3,699.28 -7,640.10 5,823.87 11,800.00 90.05 125.79 3,757.79 3,699.19 -7,698.59 5,904.98 11,900.00 90.05 125.79 3,757.71 3,699.11 -7,757.07 5,986.09 12,000.00 90.05 125.79 3,757.63 3,699.03 -7,815.56 6,067.21 Map Map Northing Easting DLS Vert Section (usft) (usft) 3,702.66 6,022,535.28 536,155.47 0.00 5,092.18 6,022,477.17 536,236.84 0.00 5,192.18 6,022,419.05 536,318.21 0.00 5,292.18 6,022,360.94 536,399.58 0.00 5,392.18 6,022,302.83 536,480.95 0.00 5,492.18 6,022,244.72 536,562.32 0.00 5,592.18 6,022,186.61 536,643.69 0.00 5,692.18 6,022,128.50 536,725.06 0.00 5,792.18 6,022,070.39 536,806.43 0.00 5,892.18 6,022,012.28 536,887.80 0.00 5,992.18 6,021,954.16 536,969.17 0.00 6,092.18 6,021,896.05 537,050.54 0.00 6,192.18 6,021,837.94 537,131.91 0.00 6,292.18 6,021,779.83 537,213.28 0.00 6,392.18 6,021,721.72 537,294.65 0.00 6,492.18 6,021,663.61 537,376.02 0.00 6,592.18 6,021,605.50 537,457.40 0.00 6,692.18 6,021,547.39 537,538.77 0.00 6,792.18 6,021,489.27 537,620.14 0.00 6,892.18 6,021,431.16 537,701.51 0.00 6,992.18 6,021,373.05 537,782.88 0.00 7,092.18 6,021,314.94 537,864.25 0.00 7,192.18 6,021,256.83 537,945.62 0.00 7,292.18 6,021,198.72 538,026.99 0.00 7,392.18 6,021,140.61 538,108.36 0.00 7,492.18 6,021,082.50 538,189.73 0.00 7,592.18 6,021,024.38 538,271.10 0.00 7,692.18 6,020,966.27 538,352.47 0.00 7,792.18 6,020,908.16 538,433.84 0.00 7,892.18 6,020,850.05 538,515.21 0.00 7,992.18 6,020,791.94 538,596.58 0.00 8,092.18 6,020,733.83 538,677.95 0.00 8,192.18 6,020,675.72 538,759.32 0.00 8,292.18 6,020,617.61 538,840.69 0.00 8,392.18 6,020,559.49 538,922.06 0.00 8,492.18 6,020,501.38 539,003.43 0.00 8,592.18 6,020,443.27 539,084.80 0.00 8,692.18 6,020,385.16 539,166.17 0.00 8,792.18 6,020,327.05 539,247.54 0.00 8,892.18 6,020,268.94 539,328.91 0.00 8,992.18 6,020,210.83 539,410.28 0.00 9,092.18 6,020,152.72 539,491.65 0.00 9,192.18 6,020,094.60 539,573.02 0.00 9,292.18 6,020,036.49 539,654.39 0.00 9,392.18 6,019,978.38 539,735.76 0.00 9,492.18 9/4/2019 1249.00PM Page 5 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 -17i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-17 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-17 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -17i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -17i (usft) (1) Design: MPU M-17 wp05 (usft) usft Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,698.95 12,100.00 90.05 125.79 3,757.55 3,698.95 -7,874.04 6,148.32 6,019,920.27 539,817.13 0.00 9,592.18 12,200.00 90.05 125.79 3,757.46 3,698.86 -7,932.52 6,229.44 6,019,862.16 539,898.50 0.00 9,692.18 12,300.00 90.05 125.79 3,757.38 3,698.78 -7,991.01 6,310.55 6,019,804.05 539,979.87 0.00 9,792.18 12,400.00 90.05 125.79 3,757.30 3,698.70 -8,049.49 6,391.67 6,019,745.94 540,061.24 0.00 9,892.18 12,500.00 90.05 125.79 3,757.22 3,698.62 -8,107.98 6,472.78 6,019,687.83 540,142.61 0.00 9,992.18 12,600.00 90.05 125.79 3,757.13 3,698.53 -8,166.46 6,553.90 6,019,629.71 540,223.98 0.00 10,092.18 12,700.00 90.05 125.79 3,757.05 3,698.45 -8,224.95 6,635.01 6,019,571.60 540,305.35 0.00 10,192.18 12,800.00 90.05 125.79 3,756.97 3,698.37 -8,283.43 6,716.13 6,019,513.49 540,386.72 0.00 10,292.18 12,900.00 90.05 125.79 3,756.89 3,698.29 -8,341.91 6,797.24 6,019,455.38 540,468.09 0.00 10,392.18 13,000.00 90.05 125.79 3,756.80 3,698.20 -8,400.40 6,878.35 6,019,397.27 540,549.46 0.00 10,492.18 13,100.00 90.05 125.79 3,756.72 3,698.12 -8,458.88 6,959.47 6,019,339.16 540,630.83 0.00 10,592.18 13,200.00 90.05 125.79 3,756.64 3,698.04 -8,517.37 7,040.58 6,019,281.05 540,712.20 0.00 10,692.18 13,300.00 90.05 125.79 3,756.56 3,697.96 -8,575.85 7,121.70 6,019,222.94 540,793.57 0.00 10,792.17 13,400.00 90.05 125.79 3,756.48 3,697.88 -8,634.34 7,202.81 6,019,164.82 540,874.94 0.00 10,892.17 13,500.00 90.05 125.79 3,756.39 3,697.79 -8,692.82 7,283.93 6,019,106.71 540,956.31 0.00 10,992.17 13,600.00 90.05 125.79 3,756.31 3,697.71 -8,751.31 7,365.04 6,019,048.60 541,037.68 0.00 11,092.17 13,700.00 90.05 125.79 3,756.23 3,697.63 -8,809.79 7,446.16 6,018,990.49 541,119.05 0.00 11,192.17 13,800.00 90.05 125.79 3,756.15 3,697.55 -8,868.27 7,527.27 6,018,932.38 541,200.42 0.00 11,292.17 13,900.00 90.05 125.79 3,756.06 3,697.46 -8,926.76 7,608.38 6,018,874.27 541,281.79 0.00 11,392.17 14,000.00 90.05 125.79 3,755.98 3,697.38 -8,985.24 7,689.50 6,018,816.16 541,363.16 0.00 11,492.17 14,100.00 90.05 125.79 3,755.90 3,697.30 -9,043.73 7,770.61 6,018,758.05 541,444.53 0.00 11,592.17 14,200.00 90.05 125.79 3,755.82 3,697.22 -9,102.21 7,851.73 6,018,699.93 541,525.90 0.00 11,692.17 14,300.00 90.05 125.79 3,755.73 3,697.13 -9,160.70 7,932.84 6,018,641.82 541,607.27 0.00 11,792.17 14,400.00 90.05 125.79 3,755.65 3,697.05 -9,219.18 8,013.96 6,018,583.71 541,688.64 0.00 11,892.17 14,500.00 90.05 125.79 3,755.57 3,696.97 -9,277.67 8,095.07 6,018,525.60 541,770.01 0.00 11,992.17 14,600.00 90.05 125.79 3,755.49 3,696.89 -9,336.15 8,176.19 6,018,467.49 541,851.38 0.00 12,092.17 14,700.00 90.05 125.79 3,755.40 3,696.80 -9,394.63 8,257.30 6,018,409.38 541,932.75 0.00 12,192.17 14,800.00 90.05 125.79 3,755.32 3,696.72 -9,453.12 8,338.42 6,018,351.27 542,014.12 0.00 12,292.17 14,900.00 90.05 125.79 3,755.24 3,696.64 -9,511.60 8,419.53 6,018,293.16 542,095.49 0.00 12,392.17 15,000.00 90.05 125.79 3,755.16 3,696.56 -9,570.09 8,500.64 6,018,235.05 542,176.86 0.00 12,492.17 15,100.00 90.05 125.79 3,755.07 3,696.47 -9,628.57 8,581.76 6,018,176.93 542,258.23 0.00 12,592.17 15,200.00 90.05 125.79 3,754.99 3,696.39 -9,687.06 8,662.87 6,018,118.82 542,339.60 0.00 12,692.17 15,300.00 90.05 125.79 3,754.91 3,696.31 -9,745.54 8,743.99 6,018,060.71 542,420.97 0.00 12,792.17 15,400.00 90.05 125.79 3,754.83 3,696.23 -9,804.02 8,825.10 6,018,002.60 542,502.35 0.00 12,892.17 15,500.00 90.05 125.79 3,754.74 3,696.14 -9,862.51 8,906.22 6,017,944.49 542,583.72 0.00 12,992.17 15,600.00 90.05 125.79 3,754.66 3,696.06 -9,920.99 8,987.33 6,017,886.38 542,665.09 0.00 13,092.17 15,700.00 90.05 125.79 3,754.58 3,695.98 -9,979.48 9,068.45 6,017,828.27 542,746.46 0.00 13,192.17 15,800.00 90.05 125.79 3,754.50 3,695.90 -10,037.96 9,149.56 6,017,770.16 542,827.83 0.00 13,292.17 15,900.00 90.05 125.79 3,754.41 3,695.81 -10,096.45 9,230.68 6,017,712.04 542,909.20 0.00 13,392.17 16,000.00 90.05 125.79 3,754.33 3,695.73 -10,154.93 9,311.79 6,017,653.93 542,990.57 0.00 13,492.17 16,100.00 90.05 125.79 3,754.25 3,695.65 -10,213.42 9,392.90 6,017,595.82 543,071.94 0.00 13,592.17 16,200.00 90.05 125.79 3,754.17 3,695.57 -10,271.90 9,474.02 6,017,537.71 543,153.31 0.00 13,692.17 16,300.00 90.05 125.79 3,754.08 3,695.48 -10,330.38 9,555.13 6,017,479.60 543,234.68 0.00 13,792.17 16,400.00 90.05 125.79 3,754.00 3,695.40 -10,388.87 9,636.25 6,017,421.49 543,316.05 0.00 13,892.17 16,500.00 90.05 125.79 3,753.92 3,695.32 -10,447.35 9,717.36 6,017,363.38 543,397.42 0.00 13,992.17 9/42019 12:49:OOPM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -17i Hole Company: Hilcorp Alaska, LLC Depth TVD Reference: MPU M-17 Planned RKB @ 58.60usft Diameter Project: Milne Point (usft) MD Reference: MPU M-17 Planned RKB @ 58.60usft (11) Site: M Pt Moose Pad 3,753.60 9 5/8" x 12 1/4" North Reference: True 16,887.84 Well: Plan: MPU M -17i Survey Calculation Method: Minimum Curvature Plan Annotations Wellbore: MPU M -17i Measured Design: MPU M-17 wp05 Depth Depth Planned Survey +E/ -W (usft) Measured (usft) Vertical Comment Map Map 400.00 Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,695.24 2,088.90 16,600.00 90.05 125.79 3,753.84 3,695.24 -10,505.84 9,798.48 6,017,305.27 543,478.79 0.00 14,092.17 16,700.00 90.05 125.79 3,753.75 3,695.15 -10,564.32 9,879.59 6,017,247.15 543,560.16 0.00 14,192.17 16,800.00 90.05 125.79 3,753.67 3,695.07 -10,622.81 9,960.71 6,017,189.04 543,641.53 0.00 14,292.17 16,887.84 90.05 125.79 3,753.60 . 3,695.00 -10,674.18 10,031.95 6,017,138.00 543,713.00 0.00 14,380.01 Total Depth : 16887.84' MD, 3753.6' TVD 2,311.08 End Dir : 7369.35' MD, 3761.45' TVD Targets Target Name hit/miss target Shape M -17i wp04 Toe plan hits tarqet center Point M -17i wp03 Heel plan hits tarqet center Circle (radius 30.00) Casing Points Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting (°) (°) (usft) (usft) (usft) (usft) (usft) 0.00 0.00 3,753.60 -10,674.18 10,031.95 6,017,138.00 543,713.00 1.17 124.87 3,753.60 -5,019.09 2,188.67 6,022,757.00 535,845.00 Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () (11) 7,218.17 3,753.60 9 5/8" x 12 1/4" 9-5/8 12-1/4 16,887.84 3,753.60 4 1/2" x 8 1/2" 4-1/2 8-1/2 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/$ +E/ -W (usft) (usft) (usft) (usft) Comment 400.00 400.00 0.00 0.00 Start Dir 3°/100' : 400' MD, 400'TVD 650.00 649.29 -14.90 6.69 Start Dir 4°/100' : 650' MD, 649.29'TVD 2,088.90 1,761.33 -779.42 291.18 End Dir :2088.9' MD, 1761.33' TVD 6,173.01 3,484.88 -4,257.88 1,559.92 Start Dir 4°/100' : 6173.01' MD, 3484.87'TVD 7,118.17 3,743.15 -4,960.93 2,108.00 End Dir : 7118.17' MD, 3743.15' TVD 7,218.17 3,753.60 -5,019.09 2,188.67 Start Dir4°/100' : 7218.17' MD, 3753.6'TVD 7,369.35 3,761.45 -5,107.35 2,311.08 End Dir : 7369.35' MD, 3761.45' TVD 16,887.84 3,753.60 -10,674.18 10,031.95 Total Depth : 16887.84' MD, 3753.6' TVD 9/4/2019 12:49:00PM Page 7 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -17i MPU M -17i MPU M-17 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 04 September, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 Well Coordinates: 6,027,765.65 N, 533,633.87 E (70" 29' 12.79" N, 149' 43' 30.36" W) Datum Height: MPU M-17 Planned RKB @ 58.60usft Scan Range: 33.70 to 7,218.17 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 7i - MPU M-17 wp05 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 Scan Range: 33.70 to 7,218.17 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M Pt L Pad M Pt M Pad M-01 - M-01 - M-01 M-01 - M-01 - M-01 M-01 - M-01 A- M-01 A M-01 - M-01 A- M-01 A M-01 - M-01 A- M-01 A M Pt Moose Pad 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-14 - MPU M-14 - MPU M-14 MPU M-14 - MPU M-14 - MPU M-14 MPU M-14 - MPU M-14 - MPU M-14 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 677.28 254.79 677.28 249.19 706.18 6,479.69 420.42 6,479.69 326.02 4,227.08 4.454 Centre Distance Pass - 6,708.70 443.19 6,708.70 298.94 4,409.44 3,072 Ellipse Separation Pass - 6,908.70 509.90 6,908.70 325.42 4,539.24 2.764 Clearance Factor Pass - 677.28 254.79 677.28 249.19 706.18 45.481 Centre Distance Pass - 708.70 254.95 708.70 249.09 739.00 43.511 Ellipse Separation Pass - 1,108.70 290.14 1,108.70 280.98 1,142.37 31.675 Clearance Factor Pass - 33.70 269.96 33.70 269.04 34.07 296.052 Centre Distance Pass - 208.70 270.63 208.70 268.55 206.65 129.903 Ellipse Separation Pass - 1,958.70 401.52 1,958.70 380.48 1,825.67 19.077 Clearance Factor Pass - 567.64 85.06 567.64 80.39 564.98 18.211 Centre Distance Pass - 608.70 85.20 608.70 80.22 604.88 17.096 Ellipse Separation Pass - 3,733.70 309.25 3,733.70 242.00 3,712.12 4.598 Clearance Factor Pass - 33.70 30.00 33.70 29.09 34.42 32.904 Centre Distance Pass - 133.70 30.34 133.70 28.83 134.02 20.097 Ellipse Separation Pass - 2,533.70 133.63 2,533.70 92.29 2,541.12 3.232 Clearance Factor Pass - 33.70 30.00 33.70 29.09 34.42 32.904 Centre Distance Pass - 133.70 30.34 133.70 28.83 134.02 20.097 Ellipse Separation Pass - 2,533.70 133.63 2,533.70 92.28 2,541.12 3.232 Clearance Factor Pass - 33.70 30.00 33.70 29.09 34.42 32.904 Centre Distance Pass - 133.70 30.34 133.70 28.83 134.02 20.097 Ellipse Separation Pass - 04 September, 2019 - 12:52 Page 2 of 8 COMPASS Hileorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 346.43 179.88 346.43 176.56 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 54.069 Centre Distance Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI 433.70 180.07 Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 176.09 433.58 45.157 Ellipse Separation Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI Scan Range: 33.70 to 7,218.17 usft. Measured Depth. 228.14 983.70 219.66 955.53 26.901 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 145.21 429.14 35.403 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 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 1,442.63 11.435 Centre Distance MPU M-18 - MPU M-18PB2 - MPU M-18PB2 2,533.70 133.63 2,533.70 92.29 2,541.12 3.232 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 320.12 243.55 320.12 240.76 320.65 87.212 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 358.70 243.66 358.70 240.58 357.81 79.051 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 6,308.70 491.02 6,308.70 354.89 9,551.96 3.607 Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 320.12 243.55 320.12 240.76 320.65 87.212 Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 358.70 243.66 358.70 240.58 357.81 79.051 Ellipse Separation Pass - MPU M-20 - MPU M -20P81 - MPU M-20PB1 6,308.70 491.02 6,308.70 354.89 9,551.96 3.607 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 320.12 243.55 320.12 240.76 320.65 87.212 Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 358.70 243.66 358.70 240.58 357.81 79.051 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 6,308.70 491.02 6,308.70 354.89 9,551.96 3.607 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 383.70 89.88 383.70 86.25 383.80 24.743 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 433.70 90.01 433.70 85.99 433.80 22.382 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 758.70 108.48 758.70 101.90 756.52 16.494 Clearance Factor Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI 346.43 179.88 346.43 176.56 346.54 54.069 Centre Distance Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI 433.70 180.07 433.70 176.09 433.58 45.157 Ellipse Separation Pass - Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI 983.70 228.14 983.70 219.66 955.53 26.901 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 428.02 149.43 428.02 145.21 429.14 35.403 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 483.70 149.74 483.70 144.81 484.97 30.360 Ellipse Separation Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 5,508.70 1,497.31 5,508.70 1,373.32 5,198.01 12.077 Clearance Factor Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,343.73 121.21 1,343.73 110.61 1,442.63 11.435 Centre Distance Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,358.70 121.47 1,358.70 110.58 1,456.50 11.154 Ellipse Separation Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,458.70 136.79 1,458.70 123.39 1,546.37 10.208 Clearance Factor Pass - Plan: MPU M -15i - M -15i - M -15i wp04 843.80 174.26 843.80 166.68 829.60 22.977 Centre Distance Pass - Plan: MPU M-1 5i - M -15i - M -15i wp04 883.70 174.37 883.70 166.54 867.72 22.258 Ellipse Separation Pass - Plan: MPU M -15i - M -15i - M -15i wp04 6,208.70 1,457.90 6,208.70 1,327.39 5,952.80 11.171 Clearance Factor Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 730.38 209.38 730.38 202.71 715.40 31.393 Centre Distance Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M-151 P2 wp02 783.70 209.64 783.70 202.56 763.91 29.617 Ellipse Separation Pass - Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02 2,758.70 420.14 2,758.70 372.88 2,612.85 8.889 Clearance Factor Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 560.82 120.08 560.82 114.68 556.69 22.252 Centre Distance Pass - Plan: MPU M-16 P2 - M -i 6 Phase 2 - MPU M-16 P2 w 633.70 120.34 633.70 114.40 627.11 20.245 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 4,183.70 342.36 4,183.70 252.06 4,115.46 3.791 Clearance Factor Pass - 04 September, 2019 - 12:52 Page 3 of 8 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-1 7i - MPU M-1 7i - MPU M-17 wp05 Scan Range: 33.70 to 7,218.17 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 -17i P2 - M112 Phase 2 - M -17i P2 wp02 261.37 30.14 261.37 27.02 261.47 9.677 Centre Distance Pass - Plan: MPU M -17i P2 - M112 Phase 2 - M-171 P2 wp02 6,733.70 113.21 6,733.70 21.24 6,600.00 1.231 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 439.11 59.18 439.11 55.16 435.79 14.725 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 483.70 59.38 483.70 55.01 480.38 13.612 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 7,218.17 747.19 7,218.17 572.45 7,060.45 4.276 Clearance Factor Pass - Plan: MPU M -19i - MPU KA -19i - Jeb Stuart - MPU M-1 383.70 120.06 383.70 116.44 379.80 33.183 Centre Distance Pass - Plan: MPU M-1 9i - MPU M-1 9i - Jeb Stuart - MPU M-1 433.70 120.19 433.70 116.18 429.80 29.994 Ellipse Separation Pass - Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 3,383.70 404.72 3,383.70 339.87 3,404.56 6.241 Clearance Factor Pass - Plan: MPU M-1 9i P2 - Slot 27 - M-1 9i P2 - M-1 9i P2 w{ 283.70 60.14 283.70 57.30 279.80 21.169 Centre Distance Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M-1 9i P2 wF 333.70 60.36 333.70 57.14 329.26 18.762 Ellipse Separation Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wl 7,218.17 1,090.47 7,218.17 924.61 6,900.53 6.575 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 383.70 270.44 383.70 266.38 383.80 66.533 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 508.70 270.59 508.70 265.56 507.81 53.766 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 6,258.70 506.92 6,258.70 354.06 8,883.03 3.316 Clearance Factor Pass - Plan: MPU M-21 i - M -21i - M -21i wp02 383.70 172.63 383.70 168.99 383.80 47.522 Centre Distance Pass - Plan: MPU M -21i - M -21i - M -21i wp02 433.70 172.73 433.70 168.71 433.80 42.950 Ellipse Separation Pass - Plan: MPU M -21i - M -21i - M -21i wp02 6,258.70 1,264.27 6,258.70 1,126.93 8,662.37 9.206 Clearance Factor Pass - Plan: MPU M -21i P2 - M -21i Phase 2 - M-21 i P2 wp02 383.70 153.59 383.70 149.53 383.80 37.786 Centre Distance Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 433.70 153.75 433.70 149.30 433.23 34.535 Ellipse Separation Pass - Plan: MPU M -21i P2 - M-21 i Phase 2 - M -21i P2 wp02 6,233.70 1,396.49 6,233.70 1,252.76 8,478.69 9.716 Clearance Factor Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 335.84 124.36 335.84 120.67 335.94 33.677 Centre Distance Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 358.70 124.38 358.70 120.51 358.29 32.150 Ellipse Separation Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 583.70 145.12 583.70 139.52 568.17 25.910 Clearance Factor Pass - Plan: MPU M-231 - Slot 22 - M -23i - M -23i wp03 383.70 127.61 383.70 124.19 383.80 37.316 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 408.70 127.63 408.70 124.01 408.80 35.312 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 658.70 148.53 658.70 142.95 650.00 26.612 Clearance Factor Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 383.70 138.03 383.70 133.96 383.80 33.956 Centre Distance Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 408.70 138.05 408.70 133.79 408.80 32.409 Ellipse Separation Pass - Plan: MPU M-231 P2 - Slot20 - M -23i Phase 2 - M -23i F 633.70 160.70 633.70 154.70 617.81 26.784 Clearance Factor Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 361.37 172.50 361.37 169.06 361.47 50.078 Centre Distance Pass - 04 September, 2019 - 12:52 Page 4 of 8 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 209.89 261.37 308.70 210.05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 708.70 259.62 708.70 383.70 218.59 Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 483.70 218.89 483.70 958.70 257.24 Scan Range: 33.70 to 7,218.17 usft. Measured Depth. 383.70 137.65 383.70 433.70 137.84 433.70 808.70 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 64.49 1,483.70 1,508.70 63.52 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 261.37 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 583.70 335.92 Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 383.70 172.51 383.70 168.88 383.49 47.516 Ellipse Separation Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 683.70 214.71 683.70 208.61 650.30 35.239 Clearance Factor Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P: 311.37 194.76 311.37 191.26 311.47 55.604 Centre Distance Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P< 358.70 194.95 358.70 191.08 356.28 50.482 Ellipse Separation Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P: 658.70 234.86 658.70 228.74 624.51 38.368 Clearance Factor Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 383.70 153.44 383.70 149.81 383.80 42.241 Centre Distance Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 408.70 153.46 408.70 149.63 408.80 40.098 Ellipse Separation Pass - Plan: MPU M-251 - Slot 18 - M -25i - M -25i wp03 683.70 182.02 683.70 176.06 667.19 30.503 Clearance Factor Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 261.37 218.69 261.37 215.58 261.47 70.230 Centre Distance Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 308.70 218.87 308.70 215.40 306.09 63.035 Ellipse Separation Pass - Plan: MPU M -25i P2 - Slot 12 - M -25i Phase 2 - M -25i 683.70 272.87 683.70 266.62 633.83 43.612 Clearance Factor Pass - Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: Plan: MPU M-26 P2 - Slot 09 - M-26 Phase 2 - M -26P: Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - u Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - u Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX- u Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 Proposal: N1 Kuparuk - Slot 34 - MPU M -NI - Kup N1 Rig: MPU M-22 - MPU M-22 - MPU M-22 Rig: MPU M-22 - MPU M-22 - MPU M-22 Rig: MPU M-22 - MPU M-22 - MPU M-22 Rig: MPU M-22 - MPU M-22 - MPU M-22 wp08 261.37 209.89 261.37 308.70 210.05 308.70 708.70 259.62 708.70 383.70 218.59 383.70 483.70 218.89 483.70 958.70 257.24 958.70 383.70 137.65 383.70 433.70 137.84 433.70 808.70 171.19 808.70 1,483.70 64.49 1,483.70 1,508.70 63.52 1,508.70 1,515.74 63.47 1,515.74 261.37 194.96 261.37 308.70 195.06 308.70 733.70 239.86 733.70 33.70 127.78 33.70 308.70 128.68 308.70 583.70 153.76 583.70 335.92 127.78 335.92 206.78 261.47 67.404 Centre Distance Pass - 206.57 306.55 60.477 Ellipse Separation Pass - 253.22 659.41 40.538 Clearance Factor Pass - 214.95 376.70 60.168 Centre Distance Pass - 214.48 476.67 49.632 Ellipse Separation Pass - 249.18 926.31 31.910 Clearance Factor Pass - 134.02 383.80 37.879 Centre Distance Pass - 133.82 433.80 34.259 Ellipse Separation Pass - 164.20 805.27 24.473 Clearance Factor Pass - 50.38 1,533.16 4.570 Clearance Factor Pass - 49.94 1,555.74 4.677 Ellipse Separation Pass - 50.09 1,562.06 4.742 Centre Distance Pass - 192.28 261.47 72.702 Centre Distance Pass - 192.02 307.42 64.067 Ellipse Separation Pass - 233.62 693.50 38.435 Clearance Factor Pass - 126.87 33.95 140.136 Centre Distance Pass - 125.94 307.73 47.084 Ellipse Separation Pass - 148.92 563.48 31.761 Clearance Factor Pass - 124.52 335.92 39.188 Centre Distance Pass - 04 September, 2019 - 12:52 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Clearance Summary Based on Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 Separation Warning usft Scan Range: 33.70 to 7,218.17 usft. Measured Depth. 358.01 37.200 Ellipse Separation Pass - Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 803.44 Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) Rig: MPU M-22 - MPU M-22 - MPU M-22 wp08 358.70 127.81 358.70 124.37 Rig: MPU M-22 - MPU M-22 - MPU M-22 wp08 583.70 151.64 583.70 146.50 Slat 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 845.76 138.54 845.76 131.33 Slot 33 - Placeholder - Slat 33 - Placeholder - Slot 33 - 858.70 138.58 858.70 131.28 Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 1,008.70 148.17 1,008.70 139.70 Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 951.94 222.33 951.94 214.30 Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 958.70 222.34 958.70 214.26 Slot 39 - Placeholder - Slot 39 - Placeholder - Slot 39 - 1,058.70 225.92 1,058.70 217.20 Milne Point Exploration From To Survey/Plan (usft) (usft) 33.70 1,000.00 MPU M-17 wp05 1,000.00 7,218.17 MPU M-17 wp05 7,218.17 16,887.84 MPU M-17 wp05 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point @Measured Clearance Summary Based on Depth Factor Minimum Separation Warning usft 358.01 37.200 Ellipse Separation Pass - 562.34 29.481 Clearance Factor Pass - 803.44 19.218 Centre Distance Pass - 815.90 18.962 Ellipse Separation Pass - 957.80 17.493 Clearance Factor Pass - 904.71 27.694 Centre Distance Pass - 911.07 27.516 Ellipse Separation Pass - 1,000.00 25.900 Clearance Factor Pass - Survey Tool 2_Gyro-NS-GC_Drill collar 2_MWD+IFR2+MS+Sag 2_M W D+IFR2+MS+Sag 04 September, 2019 - 12:52 Page 6 of 8 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION W.._. .ETAD-S PIan'MPUM-17i NAD 1927 (N CONUS) Alaska Zone 04 Co-ordinate(N/E)Rerere-W.11 Plan: MPU M-1 7i. T- %1h V.6c 1(TVD) Reference: MPU N417 Planned RKB Q 58.90usft 24.90 Site: M Pt Moose Pad SparrY Grilling Well: Plan: MPU M -17i Me --d Depth Reference: MPU M-17 Planned RKB ( 5860usft l: Metwd tN/-S +E/ -W Nonbing E h.g 1-ai!!ude 1_ -gird, Wellbore: MPU M -17i Calwlation Minimum Curvature 0.00 0.00 6027765.65 533633.87 70. 29' 11792 N 14V 43' 30.357 ' Plan: MPU M-17 wp05 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering Criteria 33.70 To 16887.84 Date: 2017-11-14700:00:00 Validated: V Version: Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS SII ( 1 OF 2) 33.70 1000.00 MPU M-17 Wp05 (MPU M -17i) 2 GUyNS-GC Drill colla 1000.00 7218.17 MPU M-17 Wp05 (MPU M-1 7i) 2-M D+IFR2++TAS+Sag TVD TVDSS MD Size Name I 7218.17 16887.84 MPU M-17 wp05(MPU M -17i) 2_MWD+IFR2+MS+Sag 3753.60 3695.00 7218.17 9-5/8 95/8"x121/4" 3753.60 3695.00 16887.84 4-1/2 4 1/2" x 8 1/2" C150.00 o120.00 FAF/ Kup 51 wp01 V I �IIII c6 90.00 III I U M-16 M-19 P2 wp02i III i I l� 60.00 } ' (j M-18 P wp03 M-0815 W wp02-.MCLaws MPU M,18 U' 30.00- , M -17i 2wp02 f,' M�1 0.00 i 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) 4.00 T I i I I O v 3.00 c I If I i _.._____ � ______ - _ _._.._. - I -__ - _ '. i I i I j 14L ° Collision Risk Procedures Req. 6 2.00 Q.Collision Avoidance Req. j I No -Go Zone - Stop Drilling' I I j 1.00 NOERRORS ! I I I 0.00 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -17i MPU M -17i MPU M-17 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 04 September, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M -17i -MPU M -17i - MPU M-17 wp05 Well Coordinates: 6,027,765.65 N, 533,633.87E (70° 29' 12.79" N, 149° 43' 30.36" W) Datum Height: MPU M-17 Planned RKB @ 58.60usft Scan Range: 7,218.17 to 16,887.84 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 Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 16,887.84 829.82 16,887.84 243.70 10,894.52 1.416 Clearance Factor Pass - Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 ® ®®®® Scan Range: 7,218.17 to 16,887.84 usft. Measured Depth. ®®® ® Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad MPJ -20 - MPJ -20A- MPJ -20A 16,887.84 829.82 16,887.84 243.70 10,894.52 1.416 Clearance Factor Pass - MPJ -24 - MPJ -24A- MPJ -24A ® ®®®® MPJ -24 - MPJ -24A- MPJ -24A ®®® ® MPJ -24 - MPJ -24A- MPJ -24A ®® MPJ -24 - MPJ -241-1 - MPJ -241-1 ®® ® MPJ -24 - MPJ -241-1 - MPJ-24LI a MPJ -24 - MPJ -24L1 - MPJ -241-1 ®®® MPJ -24 - MPJ -24L1 PBI - MPJ -24L1 PB1 ®®® MPJ-24-MPJ-24L1PB1-MPJ-24L1PB1 ®®®® MPJ-24-MPJ-24L1PB2-MPJ-24L1PB2 12,965.78 MPJ -24 - MPJ -24L1 PB2 - MPJ -24L1 PB2 13,874.00 MPJ -24 - MPJ -24L1 PB2 - MPJ -24L1 PB2 Pass - MPJ -24 - MPU J-24 - MPJ -24 S ®® MPJ -24 - MPU J-24 - MPJ -24 ® ®®® MPJ -24 - MPU J-24 - MPJ -24 ® ®®® MPJ -27 - MPJ -27 - MPJ -27 ® ®®®® M Pt L Pad MPU L-51 - MPU L-51 - MPU L-51 12,593.17 1,395.99 12,593.17 1,139.02 13,874.00 5.432 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 12,868.17 1,348.88 12,868.17 1,109.60 13,874.00 5.637 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 12,965.78 1,345.35 12,965.78 1,114.31 13,874.00 5.823 Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53 9,518.17 952.17 9,518.17 749.97 14,800.00 4.709 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 9,743.17 899.62 9,743.17 718.46 14,800.00 4.966 Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53 9,846.92 893.62 9,846.92 724.11 14,800.00 5.272 Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56 10,193.17 1,200.90 10,193.17 1,000.78 14,330.00 6.001 Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56 10,543.17 1,131.10 10,543.17 952.96 14,330.00 6.349 Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56 10,600.70 1,129.64 10,600.70 954.60 14,330.00 6.454 Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57 11,718.17 1,401.22 11,718.17 1,178.39 13,941.00 6.288 Clearance Factor Pass - 04 September, 2019 - 12:55 Page 2 of 6 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -17i - MPU M-17 wp05 344.44 7,218.17 211.42 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 2.589 Clearance Factor Pass - 7,218.17 Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wp05 7,218.17 474.33 4,688.86 Scan Range: 7,218.17 to 16,887.84 usft. Measured Depth. Pass - 7,218.17 830.97 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 663.96 6,944.97 4.976 Centre Distance 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 16,538.30 MPU L-57 - MPU L-57 - MPU L-57 12,018.17 1,346.69 12,018.17 1,141.07 13,941.00 6.550 Ellipse Separation Pass - MPU L-57 - MPU L-57- MPU L-57 12,117.91 1,342.99 12,117.91 1,144.42 13,941.00 6.763 Centre Distance Pass - M Pt M Pad M-01 - M-01 - M-01 M-01 - M-01 A- M-01 A M Pt Moose Pad MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-16 - MPU M-16 - MPU M-16 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18 - MPU M-18 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB1 - MPU M-18PB1 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-18 - MPU M-18PB2 - MPU M-18PB2 MPU M-20 - MPU M-20 - MPU M-20 MPU M-20 - MPU M-20PB1 - MPU M-20PB1 MPU M-20 - MPU M-20PB2 - MPU M-20PB2 Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 7,218.17 344.44 7,218.17 211.42 4,844.20 2.589 Clearance Factor Pass - 7,218.17 694.89 7,218.17 474.33 4,688.86 3.151 Clearance Factor Pass - 7,218.17 830.97 7,218.17 663.96 6,944.97 4.976 Centre Distance Pass - 16,518.17 981.84 16,518.17 472.70 16,306.00 1.928 Clearance Factor Pass - 16,538.30 981.64 16,538.30 472.63 16,306.00 1.929 Ellipse Separation Pass - 16,213.88 746.95 16,213.88 315.86 16,571.99 1.733 Centre Distance Pass - 16,418.17 750.49 16,418.17 300.02 16,731.00 1.666 Ellipse Separation Pass - 16,443.17 752.42 16,443.17 300.52 16,731.00 1.665 Clearance Factor Pass - 7,218.17 789.19 7,218.17 602.33 7,254.47 4.224 Centre Distance Pass - 10,093.17 795.09 10,093.17 540.39 10,361.00 3.122 Ellipse Separation Pass - 10,168.17 806.42 10,168.17 545.74 10,361.00 3.094 Clearance Factor Pass - 11,343.36 777.67 11,343.36 515.42 11,696.69 2.965 Centre Distance Pass - 11,493.17 781.77 11,493.17 495.38 11,767.00 2.730 Ellipse Separation Pass - 11,543.17 788.44 11,543.17 498.23 11,767.00 2.717 Clearance Factor Pass - 7,218.17 1,082.40 7,218.17 916.19 10,181.55 6.512 Clearance Factor Pass - 7,218.17 1,082.40 7,218.17 916.19 10,181.55 6.512 Clearance Factor Pass - 7,218.17 1,082.40 7,218.17 916.19 10,181.55 6.512 Clearance Factor Pass - 7,218.17 820.77 7,218.17 642.21 6,853.69 4.597 Centre Distance Pass - 13,468.17 919.47 13,468.17 493.87 13,102.21 2.160 Clearance Factor Pass - 7,218.17 747.19 7,218.17 572.45 7,060.45 4.276 Centre Distance Pass - 16,418.17 765.06 16,418.17 277.36 16,500.00 1.569 Ellipse Separation Pass - 16,443.17 766.73 16,443.17 277.66 16,500.00 1.568 Clearance Factor Pass - 7,218.17 1,279.55 7,218.17 1,103.97 7,064.47 7.287 Centre Distance Pass - 16,887.84 1,486.24 16,887.84 979.03 17,645.78 2.930 Clearance Factor Pass - 04 September, 2019 - 12:55 Page 3 of 6 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M-1 7i - MPU M-17 wpO5 9,643.17 523.14 9,643.17 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 3,964.06 3.803 Clearance Factor Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 Reference Design: M Pt Moose Pad - Plan: MPU M -17i - MPU M -17i - MPU M-17 wpOs 521.71 9,668.17 384.78 3,957.19 Scan Range: 7,218.17 to 16,887.84 usft. Measured Depth. Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 9,688.03 521.36 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 385.11 3,951.70 3.827 Centre Distance 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 463.09 Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wr 7,218.17 1,090.47 7,218.17 924.61 6,900.53 6.575 Ellipse Separation Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wp 13,643.17 1,496.75 13,643.17 1,072.29 13,900.00 3.526 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 7,218.17 1,111.95 7,218.17 930.07 9,536.16 6.114 Clearance Factor Pass - Milne Point Exploration MPU-Liviano-01 - Liviano-01 - Liviano-01 9,643.17 523.14 9,643.17 385.58 3,964.06 3.803 Clearance Factor Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 9,668.17 521.71 9,668.17 384.78 3,957.19 IW O Ellipse Separation Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 9,688.03 521.36 9,688.03 385.11 3,951.70 3.827 Centre Distance Pass - MPU-Liviano-01 - Liviano-01A- Liviano-01A 9,793.17 594.84 9,793.17 465.34 3,884.86 4.593 Clearance Factor Pass - MPU-Liviano-0l-Liviano-01A-Liviano-01A 9,843.17 591.20 9,843.17 463.09 3,874.87 4.615 Ellipse Separation Pass - MPU-Liviano-0l-Liviano-01A-Liviano-01A 9,86324 590.87 9,863.24 463.54 3,870.83 4.640 Centre Distance Pass - From To Survey/Plan Survey Tool (usft) (usft) 33.70 1,000.00 MPU M-17 wp05 2_Gyro-NS-GC_Drill collar 1,000.00 7,218.17 MPU M-17 wp05 2_MWD+IFR2+MS+Sag 7,218.17 16,887.84 MPU M-17 wp05 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 04 September, 2019 - 12.55 Page 4 of 6 COMPASS MALLIBURTON Project: Milne Point REFERENCE INFORMATION Nk- 1ETAILSPIanMPUM-17i NAD1927(NADCONCONUS) Aloka Zone 04 Coordinate lVD) Reference: MP M-1 MPU M -17i, True North Vertical Reference: MPU Planned RKR ® 5 sh ?g90 Site: M Pt Moose Pad Bpe,r'y Orllling Well: Plan: MPU M -17i M-17 Measured Daplh Reference: MPU IA17 Planned RKB (� SB 60usfl D,pth Zo6 +N/ -S +E/ -W Northing EiShn IntitNJc IongiNJc 0.00 Wellbore: MPU M -17i C Iwlatim Method: Minimum Curve— 0.00 6027765 65 533633.87 70" 29' 12.792N 149° 43'30357 Plan: MPU M-17 wp05 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria 33.70 To 16887.84 Date: 2017-11-14T000000 Validated: Yes Version: Ladder/S.F. Plots Depth From Depth T Survey/Plan Tool CASING DETAILS PH (2 of 2) 33.70 1000.00 MPU M-17 wp05 (MPU M -17i) 2_Gyro NS-GC_Dnll colla 1000.00 7218.17 MPUM-17wp05(MPUM-17i) 2-MWDIiFR2+MS+Sag 7218.17 16887.84 MPUM-17wp05(MPUM-17i) 2-MWD. FR2+MS+Sag TVD TVDSS MD Size Name 3753.60 3695.00 7218.17 9-5/8 95'8"z 121/4" 3753.60 3695.00 16887.84 4-1/2 41/2"x81/2" ry 1 MPJ4L T .cN150.00 ._ I d MPJ -2 I' 6CD 120.00 _-_- _- _ _. _ l .._ . 1..., .. _ ; MPJ -24A l N U) I 60.00— " 0.00 � i O 30.00 .fu i .—__ ��- I I — —'-- 0.00 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16500 Measured Depth (1000 usft/in) I jT/1 o v 3.00 I i t0 LL I I I I 0 2.00 n Collision Risk Procedures Req. I U Collision Avoidance Req. SII 1.00 - No -Go Zone - Stop Drilling I NOERRORS i o.00 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16500 Measured Depth (1000 usft/in) TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: ;7 Development Service Exploratory Stratigraphic Test _ Non -Conventional FIELD: ��/ !'/!� ? f POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 PTD#:2191250 Company Hilcorp Alaska LLC _ _ Initial Class/Type Well Name: MI_LNE_ PT_UNIT_M-17 Program SER Well bore seg ❑ SER/PEND GeoArea 890 Unit 11.328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached No CMT vol adequate to circulate on conductor & surf csg i2 Lease number appropriate Yes Surf Loc & Top Prod Int lie in ADL0025514; Portion of Productive Interval lies in ADL0025515; 3 Unique well name and number Yes TD lies in ADL0025517. 4 Well located in a defined pool Yes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05. 5 Well located proper distance from drilling unit boundary Yes CO 477.05 specifies: "There are no restrictions as to well spacing except that no pay shall 6 Well located proper distance from other wells Yes be opened in a well closer than 500 feet from the exterior boundary of the affected area." 7 Sufficient acreageavailablein drilling unit Yes As planned, well conforms to spacing requirements. 8 If deviated, is wellbore plat included Yes NA 9 Operator only affected party Yes Seabed condition survey (if off -shore) 10 Operator has appropriate bond in force Yes 39 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 SFD 9/10/2019 14 Well located within area and strata authorized by Injection Order# (put 10# in comments) -(For Yes Area Injection Order No. 10-6 15 All wells within 1/4 mile area of review identified (For service well only) Yes MPU M-01, M -01A, M-16, M-18, Liviano 1, Liviano 1A, J-24, J-241-1, J -20A 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) No 17 Nonconven. gas conforms to AS31.05.030([.1_.A),0.2.A-D) NA 18 Conductor string provided Engineering 19 Surface casing protects all known_ USDWs 20 CMT vol adequate to circulate on conductor & surf csg 21 CMT vol adequate to tie-in long string to surf csg 22 CMT will coverall known _productive horizons 23 Casing designs adequate for C, T, B & permafrost 24 Adequate tankage or reserve pit 25 If a re -drill, has a_ 1.0-403 for abandonment been approved 26 Adequate wellbore separation proposed 27 If-diverter required, does it meet_ regulations Appr Date 28 Drilling fluid program schematic &_ equip list adequate GLS 9/24/2019 29 BOPEs, do they meet regulation 30 BOPE press rating appropriate; test to (put psig in comments) Yes 20" inch conductor set at 112 ft NA permafrost area Yes 9 5/8" casing will be cemented using a 2 stage system. ES tool NA injection lateral will have swell packers and ICD's Yes Yes BTC calcs supplied in permit Yes Rig has steel pits. All waste to approved disposal wells. NA grassroots injector well. Yes J-24 well fails collision parameters ... well is P & A 'd in the OA sand. Yes Yes Max form pressure = 1654 psi ( 8.5 ppg EMW) will drill with 8.8 - 9.5 ppg mud. Using MPD in case of BHP issue Yes Doyon 14 had 5000 psi WP BOPE Yes MASA= 1276 psi Test BOPE to 3000 psi Geologic Engineering Public Using MPD to manage any higher than anticipated pressures from offset injectors. GLS Commissioner: Date: Commissioner: Date Commissioner Date 31 Choke manifold complies w/API_ RP -53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas_ probable No H2S not likely but rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 mile review completed_ ... all wells have mechanical integrity. 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 Gas hydrates not expected from drilling of offset wells. However, mitigation measures are discussed in Appr Date 37 Seismic analysis of shallow gas zones NA "Anticipated Drilling Hazards" section. Abnormal pressure has been encountered in M -Pad_ wells SFD 9/10/2019 38 Seabed condition survey (if off -shore) NA due to nearby injection. Managed Pressure Drilling will be used to monitor and control pressure, 39 Contact name/phone for weekly -progress reports [exploratory only] NA Onsite materials sufficient to build system to 1 ppg above highest anticipated mud weight. Geologic Engineering Public Using MPD to manage any higher than anticipated pressures from offset injectors. GLS Commissioner: Date: Commissioner: Date Commissioner Date
