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Home My WebLink About219-040DATA SUBMITTAL COMPLIANCE REPORT 8/5/2019 Permit to Drill 2190400 Well Name/No. MILNE PT UNIT M-14 MD 17139 TVD 3970 REQUIRED INFORMATION Operator Hilcorp Alaska LLC Completion Date 4/30/2019 Completion Status 1 -OIL Mud Log No V/ Samples No '/ 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 Current Status 1 -OIL API No. 50-029-23625-00-00 UIC No Directional Survey Yes (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 30832 Digital Data 112 17139 5/22/2019 Electronic Data Set, Filename: MPU M-14 LWD Final.las ED C 30832 Digital Data 4846 17102 5/22/2019 Electronic Data Set, Filename: MPU M-14 ADR Quadrants All Curves.las ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final MD.cgm ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final TVD.cgm ED C 30832 Digital Data 522/2019 Electronic File: MPU M-14—Definitive Survey Report.pdf ED C 30832 Digital Data 5 /2 212 01 9 Electronic File: MPU M-14—Definitive Survey Report.bd ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final MD.emf ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final TVD.emf ED C 30832 Digital Data 5/2212019 Electronic File: MPU M-14 Geosteering.dlis ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 Geosteering.ver ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final MD.pdf ED C 30832 Digital Data 5/22/2019 Electronic File: MPU M-14 LWD Final TVD.pdf ED C 30832 Digital Data 522/2019 Electronic File: MPU M-14 LWD Final MD.tif ED C 30832 Digital Data 5/2212019 Electronic File: MPU M-14 LWD Final TVD.tif ED C 30832 Digital Data 5/22/2019 Electronic File: EMFVlew3_1.zip ED C 30832 Digital Data 522/2019 Electronic File: Readme.txt Log C 30832 Log Header Scans 0 0 2190400 MILNE PT UNIT M-14 LOG HEADERS AOGCC Page I of Monday, August 5. 2019 DATA SUBMITTAL COMPLIANCE REPORT 8/5/2019 Permit to Drill 2190400 Well Name/No. MILNE PT UNIT M-14 Operator Hilcorp Alaska LLC MD 17139 TVD 3970 Completion Date 4/30/2019 Completion Status 1-0I1 Current Status 1-0I1 Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report L / Production Test Information Y / 1� Geologic Markers/Tops COMPLIANCE HISTORY Completion Date: 4/30/2019 Release Date: 3/28/2019 Description Comments: Compliance Reviewed Directional / Inclination Data i r / Mechanical Integrity Test Information Y / NA Daily Operations Summary Y! Date Comments Mud Logs, Image Files, Digital Data Y /'l�'i Composite Logs, Image, Data Files YO Cuttings Samples Y /6� Date: API No. 50.029.23625.00-00 UIC No Core Chips Y I Core Photographs Y /�AJ Laboratory Analyses Y /(Ng1 AOG('C' Page 2 of 2 Monday, August 5, 2019 STATE OF ALASKA ALASF )IL AND GAS CONSERVATION COMMISf V REPORT OF SUNDRY WELL OPERATIONS hr.`k.Fr.§ V aL.►' JUN 13 ?019 1. Operations Abandon Ll Plug Perforations Li Fracture StimulatLi Pull Tubing Li Operaffoils'shutdov7n LJ Performed: Suspend ❑ Perforate ❑ Other Stimulat Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ �rforate New Pool ❑ Repair Wel❑ Re-enter Susp Well ❑ Other: Temp Flow Back ❑✓ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development Q Stratigraphic❑ Exploratory ❑ Service ❑ 219-040 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: 1 AK 99503 50-029-23625-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025514, ADL025515 MPU M-14 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 17,136 feet Plugs measured NIA feet true vertical 3,970 feet Junk measured N/A feet Effective Depth measured 17,134 feet Packer measured 4,537 & 4,657 feet true vertical 3,970 feet true vertical 3,803 & 3,834 feet Casing Length Size MD TVD Burst Collapse Conductor 114' 20" x 34" 80' 80' N/A N/A Surface 4,822' 9-5/8" 4,855' 3,864' 5,750psi 3,090psi Tieback 4,633' 7" 4,664' 3,836' 7,240psi 5.410psi Liner 12,482' 6-5/8" 17,139' 3,970' 6,090psi 3,470psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# L-80 / EUE 8rd 4,710' 3,845- 7" x 3.5" PHIL Ret. Packers and SSSV (type, measured and true vertical depth) BOT SLZXP NIA See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): NIA Treatment descriptions including volumes used and final pressure: N/A 13, Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: D 0 0 0 0 Subsequent to operation: 1,345 230 454 3,320 345 14. Attachments (required per 20 w.c 25.070, 25.071. & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑ Exploratory❑ Development❑ Service ❑ Stratigraphic ❑ 16. Well Status after work: Oil 0 Gas ❑ WDSPL ❑ Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-243 Authorized Name: Chad Helgeson Contact Name: David Haakinson t Authorized Title: Operations Manager Contact Email: dhaakinSOn(WhllcorD.cor /O Authorized Signature: CL.J fT f 1, g, Date: 6/12/2019 Contact Phone: 777-8343 4 74 6 S RBDMS 6� JUN 1 3 2orl Form 10-004 Revised 4/2017 dK � / Submit Original Only STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 2 8 2019 WELL COMPLETION OR RECOMPLETION REPORT AN 1a. Well Status: Oil ❑✓ ' Gas F1 SPLUG ❑ Other ❑ Abandoned ❑ Suspended ib. Well Class: 20AAc 25. 105 20AAC 25.110 Development ❑✓ Exploratory ❑ GINJ ❑ WINJ ❑ WAG[] WDSPL ❑ No. of Completions: -I Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Datit, Com Susp., or 14. Permit to Drill Number / Sundry: Hilcorp Alaska, LLC Aband.: 4/30/2019 219-040 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 April 7, 2019 50-029-23625-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 4913' FSL, 261' FEL, Sec 14, T13N, R9E, UM, AK April 20, 2019 MPU M-14 " Top of Productive Interval: 9. Ref Elevations: KB: 58.8' 17. Field / Pool(s): Milne Point Field 2457' FNL, 1742' FWL, Sec 13, T13N, R9E, UM, AK • GL: 24.7' BF:24.7' Schrader Bluff Oil Pool 10. Plug Back Depth MDfFVD: 18. Property Designation: Total Depth: 1349' FSL, 894' FWL, Sec 20, T13N, R10E, UM, AK • 17,134' MD / 3,970' TVD ' ADI -025514, ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MDfFVD: 19. DNR Approval Number: Surface: x- 533903 y- 6027765 ` Zone- 4 • • 17,139' MD / 3,970' TVD ' LONS 16-004 12. SSSV Depth MDTFVD: 20. Thickness of Permafrost MDTFVD: TPI: x- 535918 y- 6025684 Zone- 4 Total Depth: x- 545614 y- 6018984 Zone- 4 N/A • 2,015' MD / 1,884' 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 CASING WT. PER FT GRADE SETTING DEPTH MD HOLE SIZE CEMENTING RECORD SETTING DEPTH TVD AMOUNT TOP BOTTOM TOP BOTTOM PULLED 20" 216# X-52 Surface 114' Surface 114' 42" ±270 ft3 9-5/8" 40# L-80 Surface Stg 1 L - 331 sx / T - 400 sx 4,855' Surface 3,864' 12-1/4" Stg 2 L - 439 sx / T - 270 sx 262.4 bbls 7" 26# L-80 Surface 4,664' Surface 3,836' Tieback ' Tieback Assy. 6-5/8" 20# L-80 4,657' 17,139' 3,835' 3,970' 8-1/2" Cementless PreDrilled Liner 24. Open to production or injection? Yes ❑✓ No ❑ 25. TUBING RECORD If Yes, list each interval open (MDfFVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number; Date Perfd): 3-1/2" 4,710' 4,537' MD / 3,803' TVD 6-5/8" Pre -Drilled Liner (72 holes per ft) run on 4/27/19 5,325' - 15,248' MD / 3,901' - 4,024' TVD • 15,608' - 15,771' MD / 4,005' - 3,997' TVD COMPLETION 16,126' - 17,099' MD / 3,979' - 3,971' TVD DAT Blank liner: 4,684'- 5,325'MD/ 3,840' - 3,901'TVD VERIh IED 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No ❑✓ Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 15,248'- 15,608' MD / 4,0241- 4,005' TVD -- 15,771' - 16,125' MD / 3,997' - 3,978' TVD 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): TBD Jet Pump Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: TBD Test Period Flow Tubing Casing Press: ICalculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): P I 124-Ho)ftRate Form 10-407 Revised 5/2017 1 6" )7.1C� of ONTIN,SJyED ON PAGE 2 RBDMS�'� MAY 2 8 gQ19submi O wl� only 28. CORE DATA Conventional Corals): Yes ❑ No Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/ VD, 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 2,015' 1,884' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 5,325' SB OA 3,900' information, including reports, per 20 AAC 25.071. SV5 1,399' 1,338' SV1 2,055' 1,918' Ugnu LA3 3,464' 3,139' SB NA 4,217' 3,671' SB OA 4,765' 3,854' Formation at total depth: Schrader Bluff 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: Dr ling Manager Contact Email: cclincIerAhilcorD.com Authorized Contact / Contact Phone: 777-8389 Signature: Date: » r 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-Altemating-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 n core A"., LLC Orig, KB Elev.: 58.8'/ GL Elev.: 24.7' TD= 17,13Y (MD) /To = 3,970(TVD) PBTD =17,134' (MD) /TD = 3,970'(TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-14 Last Completed: 4/30/19 PTD: 219-040 Tree Cameron 31/8" SM Wellhead FMC 11" 5M TC -1A w/11" x 3 1/2" TC -II Top and Bottom Tubing 12-1/4" 2nd stage Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 42" 50 bbls (30 Yards Pilecrete dumped down backside) 12-1/4" 1st stage 331 sx 12.0# Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 439 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20"x34" Conductor (Insulated) 215.5 /A-53 / Weld N/A Surface 40' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface4,855' 2.875" 0.0758 7" Tieback 26/L-80/TXP 6.151" Sur face 4,664' 0.0383 6-5/8" Liner (Pre -Drilled) 20/L-80/Hydril 563 5.924" 4,657' 17,139' 0.0355 DETAIL 3-1/2" 1 Tubing 1 9.3 / L-80 / ELIE 1 2.867" 1 Surf 1 4,710' 1 0.0087 1 WELL INCLINATION DETAIL KOP @ 380' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hole Angle = 75.00 deg. @ XN profile Max Hole Angle = 80.00 deg. @ Tubing tail Max Hole Angle = 93.4 deg. @ 9,532' MD JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 29' Tubing. Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 2,289' 3.5" Patco GLM w/ 1.5" SOGLV set 2,000 psi shear) 2.867" 3 4,443' 3.5" SLB Gauge Mandrel w/Y." Wire (Discharge Gauge) 2.875" 4 4,454' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,776' TVD; 69' (Sleeve Closed) 2.813" 5 4,464' 3.5" SLB Gauge Mandrel w/ Y" Wire (intake Gauge) 2.875" 6 4,484' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 4,537' 7" x 3.5" PHL Retrievable Packer (501k Shear Release) 2.885" 8 4,594' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" RHC -P set 2.750" 9 4,709' 3.5" W LEG (Btm @ 4,710') 2.867" Lower Completion 10 4,657' BOT SLZXP Liner Top Packer w/BD Slips 7" x 9-5/8" (11.24' Tieback Sleeve) 6.170" 11 4,664' 7" Tieback Assy. (8.25" OD No -Go @ 4,654') 6.090" 12 4,679' 7" Hydril 563 L-80 x 6-5/8" Hydril 563 L-80 XO 5.924" 13 5,325' 6-5/8" Pre -Drilled Liner (72 holes per ft) w/ 1 straight -vane centralizer per It Blank liner from 15,248'-15,608'&15,771'-16,125' 5.924 14 17,134' WIV (Wellbore Isolation Valve) 1.000" 15 17,139' Shoe; Btm @ 17,139') - GENERAL WELL INFO AP1:50-029-23625-00-00 Drilled and Completed by Doyon 14-4/30/2019 Revised By: STP 5/03/2019 U Well Name: MP M-14 Field: Milne Point County/State: , Alaska i (LAT/LONG): evation (RKB): 34.07 API#: Spud Date: 4/7/2019 Job Name: 1814314D MPU M-14 Drilling Contractor Doyon 14 AFE #: AFE 8: Hilcorp Energy Company Composite Report Activity Date io... ,x;l5' - Ops Summary _. 4162019 PJSM. Skid rig floor into moving position. Bleed test pressure off casing & tree to bleed tank. Secure tree for rig move. 0 PSI on tree with all valves closed. Rig released from MPU M-04 Q 07:OO;Move rig off M-04 down west side of Moose pad, around the corner and spot on Wl4. Shim rig level. 2 hours to replace hydraulic hose on moving system. "';Skid rig floor into drilling position. Notified AOGCC of upcoming diverter test on 5 April 2019 at 13:08. "';Work on rig acceptance checklist. R/U rig floor air, water, mud lines & electrical. Install diverter stack, riser & bell nipple. Install diverter line. Spot & R/U rock washer & cuttings tank. Clear pipe shed & begin loading 5" drill pipe into the pipe shed. Begin changing top drive saver sub;Load 90 bbls water into pit #4. Install 80 mesh screens on the shakers. 358' total of diverter line installed, 180' from rig to 45" targeted tee and 178' from 45° targeted tee to end. 11 V to closest ignition source (generator at Delta office). 333' from outlet at substructure to end of diverter.;Finish installing new saver sub. Tighten all diverter line bolts. R/U upright water tank. Perform derrick inspection. Finish loading & strapping 165 joints of 5" drill pipe. Continue with rig acceptance checklist. R/U 5" handling equipment on the rig floor. 4/7/2019 Finish preparing to pickup 5" drill pipe. Install mouse hole in the rotary table.;P/U 165 joints of 5" drill pipe in the mouse hole and rack back 55 stands in the derrick. P/U 17joints of 5" HWDP & jars and rack back 6 stands in the derrick.;Function test the surface diverter on 5" drill pipe. Knife valve opened in 17 sec. and diverter fully closed in 30 sec. 3000 PSI system pressure, 1900 PSI after closure. 200 PSI recharge in 33 sec. and full recovery in 140 sec. 2091 PSI average for six nitrogen bottles. Test gas alarms - good.;*** AOGCC inspector Matthew Herrera waived witness of the diverter test at 06:42 on 7 April 2019. "';Pre -spud meeting with all parties involved. Discussed well objectives and surface hole hazards. Table top diverter drill - discussed all roles and responsibilities. Reviewed safe briefing areas and emergency notification ;M/U 12-1/4" Kymem KM633X bit, 8" mud motor and XO sub to 36'then a stand of HWDP. Tag bottom of conductor at 114'. Fill lines, conductor & diverter stack - no leaks. Pressure test mud lines to 3500 PSI - good.;Drill 12-1/4" surface hole from 114' to 220' MD / 220 TVD, 106' drilled, 53' /hr AROP. 350 GPM = 500 PSI, 40 RPM = 1 K fl/lbs TO, 8K WOB PU 50K / SO 55K / ROT 55 K. 9.0 ppg MW, 300 vis.;Blow down top drive. POOH from 220' to 33'. M/U MWD tools to 58'. P/U inspect bit & measure directional offset - 659/814`360=291.45'. Continue to M/U MWD to 102' then initialize MWD. ll BHA to 189'then P/U stand of HWDP. Shallow pulse test MWD - good and take 1st survey at 134' (187' bit depth).;Drill 12-114" surface hole from 220'to 584' MD / 584' TVD, 364' drilled, 72.8'/hr AROP. 440 GPM = 980 PSI, 40 RPM = 1 K fl/lbs TO, 10-15K WOB. PU 67K / SO 73K / ROT 71 K. 9.1 ppg MW, 189 vis. 9.5 ppg ECD. Begin 3°/100' build at 355' at 144°.;Last survey at 508.38' MD / 508.08' TVD, 4.75° inc, 137.36° azm. 7.4' from plan, 6.19' high & 4.05' left. Hauled 565 bbls H2O from L -Pad lake for total = 565 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 57 bible cutting/liquids to MPU G&I for total= 57 bbls 4/8/2019 Drill 12-1/4" surface hole from 584'to 1411' (1325' TVD), 824' drilled, 137.9/hr AROP. 575 GPM = 1800 PSI, 80 RPM = 2K TQ, 5K WOB. 9.25 ppg MW, 168 vis, 10.0 ppg ECD. 90K PUW / 90K SOW / 90K ROT. Began 29° inc. tangent at 1222'. Backream 30' at connections.;Drill 12-1/4" surface hole from 1411' to 2207' (2050' TVD), 796' drilled, 13271h AROP. 570 GPM = 1730 PSI, 80 RPM = 3K TQ, 5K WOB. Max gas 24u. 9.3 ppg MW, 164 vis, 10.2 ECD. 112K PUW / 98K SOW / 105K ROT. Base of permafrost at 2015' MD / 1884' TVD. Backream 30' at connections.;Pumped high vis sweep at 2455', 20% increase at shakers back on calculated strokes.;Drill 12-1/4" surface hole from 2207'to 2932' (2679' TVD), 725' drilled, 120.8'/hr AROP. 570 GPM = 1850 PSI, 80 RPM = 5K TO, 10-20K WOB. Max gas 33u. 9.1 ppg MW, 122 vis, 9.8 ECD. 125K PUW / 107K SOW / 116K ROT. Backream 30' at connections.;Drill 12-1 /4" surface hole from 2932' to 3917' (3488' TVD), 985' drilled, 164.2/hr AROP. 580 GPM = 2070 PSI, 80 RPM = 7K TQ, 15K WOB. Max gas 27u. 9.25 ppg MWD, 117 vis, 9.94 ECD. 149K PUW / 115K SOW / 131 ROT. Backream 30' at connections. Began 4°/100' build at 3407'.;Pump high vis sweep at 2932', 10% increase at shakers back on calculated strokes. Pump high vis sweep at 3501', 30% increase at shakers back on calculated strokes. Last survey at 3827.56' MD / 3425.09' TVD, 43.68" inc, 137.79° azm. 17.63' from plan, 17.4T high and 2.37' Ieft.;Hauled 1885 bbis H2O from L-Pad lake for total = 2450 bbis Hauled 0 bbls heated H2O from G&I for total = 0 bbis Hauled 1839 bbls cutting/liquids to MPU G&I for total= 1896 bbis 4/912019 Drill 121/4" surface hole from 3917'to 4644' (3830' TVQ7, 727' drilled, 121.27hr AROP. 584 GPM = 2340 PSI, 80 RPM = 10-11 K TO, 20K WOB. Max gas 51 u. 9.3 ppg MWD, 117 vis, 10.1 ECD. 145K PUW 11 IOK SOW / 130 ROT. Backream 30' at connections. Maintain 4°/100' build;Drill 12-1/4" surface hole from 4644'to 4865' (3865' TVD) to TO in OA-1, 221drilled, 88.47hr AROP. 590 GPM = 2420 PSI, 80 RPM = 10K TO, 25K WOB.ax gas u. 9.3 ppg MWD, 124 vis, 10.2 ECD. 148K PUW / 108K SOW / 125 ROT. Backream 30' at connections. Maintain 4°/100' build.;BROOH from 4866 to 4741'to get above top of sand at 4768' Pump 30 bbl hi vis sweep 4640', back 2000 stks late, 100% increase. Last Survey => MD = 4812.15 TVD =3859.83 Inc =83.44 Azimuth = 128.25 Distance to plan = 4.84' , 3.23' low and 3.61' Ieft;Circulate and condition mud to drop VP from 50 to below 25. Reciprocate 4741' to 4646 alternating end points. 600 GPM = 2150 PSI, 80 RPM = 7K ft/lbs TO. Circulated 29039 strokes = 5.2 bottoms up.;Trip in hole from 4646'to 4865' while oriented high side tool face with mud motor. Perform flow check - static.;BROOH from 4865' to 4646' with 420 GPM = 1110 PSI, 40 RPM = 7K ft/Ibs TO at 5 min/stand. BROOH from 4646' to 1875' with 600 GPM -= 1900 PSI, 80 RPM = 5-10K ft/lbs TO at 5 min/stand. Observe increased pressure and torque in slide intervals, slow pulling speed to 10 min/stand.;ECD started at 9.58 and climbed to 9.92 as we back reamed out. At 1875', the shakers began to unload sand with a 10.75 ECD, slow to 27min. and allow to clean up. Slow to 500 GPM = 1120 PSI, 60 RPM = 5K ft/Ibs TO BROOH from 1875'to 1019'.;Hauled 1540 bbis H2O from L-Pad lake for total = 3990 bbls Hauled 0 bbis healed H2O from G&I for total = 0 bbis Hauled 1445 bbls cultingfliquids to MPU G&I for total= 3341 bbls 4/10/2019 Continue to BROOH from 1019'to HWDP at 750' 500 GPM, 1130 PSI, 60 RPM, 3-5K torque. Loss rate 2 bph BROOH, 32 BBLS total Iosses.;Pull on elevators racking back 6 stds HWDP with jars to 192', L/D NMFCs, download MWD, L/D remaining BHA, Bit and NS stab balled up with clay, bit grade= 2-3-CT-A-E-I-ER- a TD. Static loss rate 2 bph.;Clear and clean rig floor, load casing tools to rig floor, R/U to run 9 5/8" casing, R/U Volant tool with cement swivel, 8' bail extensions, slips and elevators, ready XO on FOSV. Monitor well, static loss rate 2 bph. 12 BBLS while handing BHA & rigging up.;PJSM for running casing, Baker lock and MAJ 9 5/8" shoe jt, 1 it casing and float collar jt. Ensure proper float operation, install top hat as per HES rep, Baker lock and WU Baffle adaptor jt.;RIH with 9- 5/8". 40# L-80 TXP casing from 162'to 1459' (37 its ) fill on the fly and top off every 10 joints ran. Install centralizers per tally. Torque to 20960 ft-lbs with `''r Volant tool. Loss rate 2 bph RIH;Continue to run 9-5/8" 40# L-80 TXP casing from 1459' to 3417', (86 its) fill on the fly and top off every 10 joints ran. Install centralizers as per tally. Torque to 20960 ft-Ibs with Volant tool. Running 30' per min. started pushing fluid away at 2364', slowed to 20' per min.;M/U ES cementer between joints #65 and #66. Baker Lok connections. Verify 6 brass set screws for 3300 PSI opening.;Stage up pumps to 5 BPM = 190 PSI to circulate a bottoms up with 9.6 ppg returns. Add water at 95 BPH and slow rate to 4 BPM = 180 PSI to treat mud. 1980 strokes circulated.;Continue to run 9-5/8" 40# L-80 TXP casing f/ 3417' to 4861', (123 jts) fill on the fly and top off every 10 joints ran. Install centralizers as per tally. Torque to 20960 ft-Ibs with Volant tool. Running 20'/min. Washed down last two joints If 4786'to 4861' @ 2 BPM = 170 PSI, 225K PUW / 140K SOW.;77 bbis lost while running casing. 122 joints of 9-5/8" 40# L 80 TXP BTC-SR casing ran with 80 each 9-5/8" x 12-1/4" Expand-o-lizer centralizers and 10 stop rings.;Stage up pumps from 2 BPM = 170 PSI to 4 BPM = 160 PSI in 1 bbl increments. Reciprocate 40'. Rotate 10 RPM = 15-12K fVlbs TQ. Adding water 45-90 BPH to drop yield point and weight. Begin mud in = 9.3 ppg / 45 vis, mud out 9.6 ppg / 76 vis. Losses at 15 BPH.; Increase to 6 BPM = 160 PSI, 10 RPM = 15-20K ft/lbs TO. Adding water 90 BPH. Last mud in = 9.4 ppg / 39 vis, mud out 9.4 ppg / 56 vis. Losses at 12 BPH ;Hauled 280 bbis H2O from L-Pad lake for total = 4270 bbis Hauled 380 bbis heated H2O from G&I for total = 380 bbis Hauled 712 bbis cutting/liquids to MPU G&I for total= 4053 bbis 79 bbis daily losses / 79 bbls cumulative losses. 4111/2019 Continue to circulate and condition mud at 4855', 6 BPM = 160 PSI, 10 RPM= 15-20K fl/lbs TO. Reciprocate pipe 40'. Add water 90 BPH. Final mud m= 9.3 ppg / 39 vis, mud out 9.4 ppg / 55 vis. YP in 151 YP out 22. P/U 225K, S/O 130K, ROT 210K. Losses at 15 bph. Submit 24 hr BOP test notification.;PJSM for pumping 1st stage cement job with all parties involved, set slips, break out volant, clean dies and cup, lube cup, IWU same. BD TD. Line up to HES & pump 5 bbl water. Test lines to 1000 psi/ 4000 psi. Good.;Cementers Mix and pump 60 bbl Clean spacer with red die and poly Flake in the first 10 bbls 3 bpm, 170 psi. Drop bypass plug. Line up and pump 138.8 bbl 12# Lead Cmt ( 331 SX, 111 bbls mix water) 3 bpm, 220 psi. Mix & pump 82.4 bbl 15.8 Tail cmt. (400 SX, 48 bbls mix water) 3 bpm, 260 psi.;Note: Stroke counter on pump unit not reading correctly, reading approx. double, verify volume pumped by total sx and calculated water volume.;Drop shut off plug. HES pump 20 bbl H2O. Lineup to rig pumps & displace with 157 bbs 9.3 ppg mud 6 bpm, 170 psi ICP. Pump 30 bbl high vis spacer, Displace with 139.2 bbls 9.3 ppg mud 5 bpm, 660 psi.;Last 10 bbls slow to 3 bpm, FCP 580 psi, Displace with total of 3355.6 stks (356.3 bbls) 2.9 bbls under calculated. Bump 1140 psi & hold for 5 min. Bleed off floats. CIP @ 12:22. Final lift 580 PSI. Rotate & reciprocate 20' while displacing. Set on depth for last 20 bbls pumped.;Pressure to 2830 psi and shear open ESC. No losses while displacing cement.;Circ through ESC at 2272'. Stage up to 5 BPM, 300 PSI, 1257 stks for BU, 800 sties away slow to 4 bpm, 240 psi dump spacer and contaminated clabbered mud with traces of cement. Dumped total 60 bbls spacer and 190 bbls clabbered contaminated mud. Phase 2 weather conditions at 12:30.;Continue to circulate through ESC, 5 bpm 220 psi taking returns back to pits, pump 5 BU total, pressure increased to 2000 psi. shut down pump, pressure held at 1440 psi with no bleed off.;Cycle pump pressuring up to 1200 psi, stage up pump Kto 2350 psi in 200 psi increments then bleeding off pressure, at 2350 psi started seeing fluid in stack move, increase to 2500 psi, getting returns, pressure slowly dropped down to 800 psi.;Take thick mud returns to cellar and vac truck. Swap and take returns to pits at 4 bpm, 600 psi ICP and 200 psi FCP. Treat mud returns. Improved to Phase 1 weather conditions at 18:30.;Shut down. Flush stack with black water and function annular to ensure free of cement. Break out Volant tool, flush and inspect dies - good. Make back up.;Continue to circulate at 4 BPM, 125 PSI while waiting on super sucker to empty at G&I and return to the rig. PJSM with Doyon, M -I, Peak & Halliburton for 2nd stage cement job.;Mix and pump 60 bbls of 10.0 ppg Clean Spacer w/ 4# red dye and 5# Pol-E-Flake in 1st 10 bbls at 4 BPM = 120 PSI. Mix and pump 344.3 bbls of 10.7 ppg Perm L lead cement (439 sxs at 4.407 yield) at 5 BPM = 370 PSI. Begin seeing spacer at 175 bbls lead pumped and good cement at 310 bbls lead pumped.;Mix and pump 56.2 bbls of 15.8 ppg Premium G tail cement (270 sxs at 1.169 yield) at 3 BPM = 240 PSI. Load closing plug. Pump 20 bbls of water at 5 BPM = 240 PSI. Displace with rig: Pump 9.1 ppg spud mud 7.3 BPM = 320 PSI ICP, 830 PSI FCP. Slow to 3.4 BPM= 580 PSI for last 10 bbls.;Plug bumped @ 1504 strokes (1512 calculated). Final lift 510 PSI. Pressure up & shift ES cementer closed @ 1570 PSI. Bleed off pressure, no flow verified cementer closed. CIP at 01:05.60 bbls of spacer and 262.4 bbls of cement back to surface. No losses during cement job.;Drivtng conditions: Phase 2 Milne & SP and Phase 3 for Conoco and east spine road at 01:15.;Drain cement from stack and flush with black water, cycling the diverter 4x times. Remove diverter line from diverter tee and unbolt diverter from diverter adapter. Hoist stack. Sim -ops: R/D cement and casing equipment and Volant tool on the rig floor.;Wellhead representative installed 9-518" casing slips with 80K on slips. Cut 9-5/8" casing and L/D cut joint (2.45'). N/D flow nipple and remove riser.;Hauled 600 bbls H2O from L -Pad lake for total = 4870 bbls Hauled 460 bbls heated H2O from G&I for total = 840 bbls Hauled 1487 bbls cutting/liquids to MPU G&I for total= 5540 bbls 65 bbls daily losses, 144 bbis cumulative losses. 4/1 212 01 9 Welder make final 9 5/8" casing cut, .44'total cut= 2.9', dress casing stump. Pull riser and LID bell nipple. N/D diverter stack. remove knife valve and tee., clean in pits.;Well head rep Install wellhead and orient same. Install csg spool. Test slip lock seal to 500 psi for 5 min and 2475 psi @ 80% of 9 5/8" 40# L-80 collapse pressure for 10 min. SimOps: C/O Geo-span.;N/U tbg spool, install blank flange and FMC valve on spool. NIU and align BOP stack, install kill line, install accumulator lines. Sim -ops: clean mud pits, prep rig floor for testing.;C/O upper pipe ram f/ 31/2" x 6" VBRs to 41/2" x 7" VBRs, Install MPD riser. Install both mouse holes.;lnstall test plug, R/U BOP test equipment, flood stack and lines with water. Trip nipple air boot leaking. Remove and replace air boot, damaged new air boot installing trip nipple. Obtain replacement air boots from the iRig. Install replacement- no leaks.;lnstall test plug and test joint. Perform BOP body test 250 PSI low / 3000 PSI high -good. AOGCC rep Bob Noble waived witness for BOP test @ 17:08.;Test BOP equipment as per PTD and AOGCC requirement. #1: Annular on 5" test joint, valves #12,13 & 14, 3" Demco, upper IBOP #2:4.5"x7" VBR rams on 5" test joint, valves #1, 9 & 11, HCR kill, lower IBOP #3: Valves#5, 8 & 10, manual kill, 5" TIW #1 #4: Valves #4, 6 & 7, 5" TIW #2;#5: Valves #1 & 2, 5" dart valve #6: HCR choke #7: 2.875"x5" VBR lower rams on 5" test joint #8 Blind rams, valve #3 #9 Annular on 7" test joint#10 4.5"xT' VBR on 7" test joint & manual choke #11 Hydraulic choke "A" #12 Manual choke "B";All tests performed with water to 250 PSI low and 3000 PSI high, held for 5 min. and charted. Accumulator test: 2975 PSI system pressure 1650 PSI after closure 44 sec for 200 PSI recharge 195 see for full PSI recharge 2008 PSI six nitrogen bottle avemge.;R/D test equipment and blow down lines. Pull 7" test joint and test plug. Install 9" I.D. long wear bushing. Clean flow line.;lnstall mousehole in rotary table. R/U 5" elevators and slips. Prepare to pick up S' drill pipe.;Hauled 75 bbls H2O from L -Pad lake for total = 4945 bbls Hauled 260 bbls heated H2O from G&I for total = 1100 bbls Hauled 986 bbls cutting/liquids to MPU G&I for total= 6526 bbls 0 bbls daily losses, 144 cumulative for interval. 4/13/2019 Prep pipe shed for P/U 5" drill pipe, move cleanout BHA off drill pipe.;PJSM, Drift and P/U 138 jts of 5" NC50 drill pipe using mouse hole and racking back 46 stands. SimOps: spot MPD unit on ODS of dg.;PJSM, M/U 8 1/2" Cleanout BHA #2, 8 1/2" MT bit, 7" motor, float sub, 3 NMFCs, RIH from derrick w/ 6 jts 5" HWDP, Jars with 11 jts HWDP= 678.53'.;Drift and single in with 5" DS50 drill pipe V 678'to 2077', conduct valve drill, well secure in 2 minutes 27 seconds, hold AAR with crew, floor hand called out all good in the cellar but failed to announce manual choke and manual kill valves are open. Continue to single in to 2236' atjt 49.;WU top drive, wash and ream down f/ 2236' with 450 gpm, 800 psi , 20 rpm, 3-4k torque, drill cement V 2267', drill ESC f/ 2272' to 2275'. Wash down to / 2300'. Ream 3x times and trip though with no problems. PU 112K, SO 95K, ROT I00K.;ComInue to drift and single in with 5" NC50 drill pipe H 2300'V 4681'. /f\ Wash and ream f/ 4681'V 4709' with 250 GPM, 460 PSI, 20 RPM, 9K TO. Tag cement with 15K. Rack back stand to 4681' and blow down top drive. PU 170K, \ SO 10GK, ROT 130K.;Pressure test 9-5/8" 40# L-80 casing to 2500 PSI for 30 min. on chart. Close upper pipe rams and pump down kill line and drill string. \✓ Pumped 4.0 bbls and bled back 4.0 bbls. Blow down llnes.;Drill the 9-5/8" casing shoe track & cement f/ 4709'V 4855', 500 GPM, 1240 PSI, 40 RPM, 9K TO, 3- 12K WOB (cement 12K & equipment 3-5K). All items on depth. Baffle adapter: 4732'-4734', float collar 4772'-4774'& float shoe 4853'4755'. Cleanout the rat hole f/ 4855'V 4865'.;Ream baffle adapter and float collar 2x then slide through clean. Ream float shoe 3x then slide through clean ;Drill 20' of new 8-1/2" hole from 4865'to 4885' (3867' TVD), 20' drilled, 71.47hr AROP, Circulate 500 strokes to clear BHA, then rack back two stands to 4776'.;Circulate & condition mud prior to performing FIT, 500 GPM, 1180 PSI, 40 RPM, 9K Polbs TO. Circulate 3125 strokes, complete circulation. 9.2 ppg MW. Shut down, perform flow check - static and blow down top drive.;R1U to perform FIT at shoe depth 4855' MD / 3864' TVD with 9.2 ppg MW = 563 PSI. Pumped 1.0 bbls and bled back 1.0 bbls. R/D test equipment and blow down Iines.;Hauled 50 bbis H2O from L -Pad take for total = 4995 bbls Hauled 100 bbls heated H2O from G&I for total = 1200 bbls Hauled 772 bbls cutting/liquids to MPU G&I for total= 7298 bbls 0 bbls daily losses, 144 bbls cumulative losses. 4/1412019 Flow check well, static, TOOH with 8 1/2" cleanout assy f/ 4776' to 678' at HWDP. 2.7 bbl losses over calculated displacement TOOH.;Perform flow check at HWDP, slight flow receding to no flow in 15 min. UD 15 its excess HWDP. Rack back HWDP jar stand and stand of NMDC to 126'. UD remaining BHA #2. Bit grade= 1/1/WT/A/E/I/NO/BHA.;Load out tools, clear rig floor. Monitor well with trip tank.;Clean rig floor. Inspect and C/O 5" NC50 saver sub, C/O front grabber dies, back set in good shape. Monitor well, static.;PJSM, load tool to rig floor, WU rotary steerable BHA #3. M/U BHA #3:8-1/2" PDC bit, Geo -Pilot, MWD w/ ADR, DGR, PWD & directional to 83'. Test & initialize MWD tools, SimOps: test MPD lines to 250 / 1250 psi;RlH w/ drill collars, HWDP and jars from the derrick to 274'. PIU one joint of drill pipe to 305'. Shallow pulse test MWD 400 GPM, 760 PSI -good test. Change out 5" drill pipe elevators due to excessive wear/ play. Mobilize RCD bearing to the rig floor.;Single in the hole with 5" drill pipe from 305' to 876'. Utilize 2.94" drift.;Sewice top drive and draw works. Change joystick for pipe skate carriage on rig floor control.;Single in the hole with 5" drill pipe from 876' to 2173'. Utilize 2.94" drift.;Fill drill pipe. Pressure test Geo -Span lines to 2500 PSI, good test. Break-in Geo -Pilot seals and function test Geo -Pilot -good. Blow down top drive.;Single in the hole with 5" drill pipe from 2173' to 4742'. Utilize 2.94" drift. Filled pipe at 4082' due to full mud pits from pipe displacement. 3.6 bbis total lost on trip in the hole.;Slip and cut 60' of drilling line. Perform draw works depth encoder calibration.;PJSM. Remove trip nipple and install MPD RCD. Flood MPD lines and function test- good.;Hauled 50 bbis H2O from L -Pad lake for total = 5045 bbls Hauled 100 bbis heated H2O from G&I for total = 1200 bbls Hauled 119 bbis cutting/liquids to MPU G&I for total= 7417 bbls 0 bbls daily losses, 0 bbls cumulative losses as per mud report at midnight. 4/15/2019 Parked at 4740' Finish flow testing MPD lines, install drip pan under RCD bearing.;PJSM for displacing to new 8.8 ppg flow pro mud. Get parameters, RIH f/ 4740'to 4883', pump 450 gpm, 1260 psi, 40 rpm, 7k torque to ensure geo-pilot home. PU 160K, SO 100K, ROT 125K.;Pump 35 bbl spacer, displace wellbore from 9.2 ppg spud mud to new 8.8 ppg flow pro mud 429 gpm, 920 psi 40 rpm reciprocating pipe taking returns thru MPD, with new mud at shoe, rack back i stand to 4834' above shoe, continue displacing pumping total 407 bbls. reciprocate and rotate.;Shut down pumps, BD TD, clean under shakers, install new 140# shaker screens. Get new parameters, SPRs 1 - 2 MPs, M/U std, wash to bottom.;Drill 8 1/2" production hole from 4885' to 5007' (3861' TVD), 122', AROP 61 FPH, 447 GPM = 1010 psi, 60-120 RPM= 10-13K ft -lbs torque, WOB = 15K, MW = 8.8 ppg, Vis = 44, ECD = 9.53 ppg, Max gas = 12 units PU = 153K, SO= 90K, ROT= 123K.;Just out of shoe targeting 87 deg, crossed 49' fault, downthrown to east, apparent dip is 89 deg. MPD monitor annulus for pressure increase during connections.;Drill 81/2" production hole from 5007'to 5668' (3920' TVD), 661' drilled, AROP 110.2 FPH, 500 GPM = 1390 psi, 120 RPM = 12K ft-Ibs torque, WOB = 10K, MW = 8.9 ppg, Vis = 42, ECD = 10.1 ppg, Max gas = 155 units PU = 152K, SO = 85K, ROT= 120K.;Crossed fault at casing shoe (4,855'md), the fault was a 49' DTE fault. Got back in the sand at 5,303' and and 3,899' TVD, out of zone from 4857' to 5303' (446). Entered OA1 at 5303', OA2 at 5407' and OA3 at 5579.;MPD chokes Rill open while drilling. Close chokes on connections and monitor for pressure -none, Note: @ 16:25 CODE RED announced at MP camp, P/U off bttm, circulate and work pipe, all clear announced at 16:35, resume drilling.;Drill 8-1/2" production hole from 566V to 6418' (3918' TVD), 750' drilled, AROP 125 FPH. 500 GPM = 1370 PSI, 120 RPM = 12K ft -lbs torque, WOB = 5-15K. MW = 9.0 ppg, Vis = 44, ECD = 10.26 ppg, Max gas = 115 units. PU = 155K, SO = 75K, ROT = 115K.;Began building up at 5954'. Entered OA2 at 6188'. Pumped high vis sweep at 5980', 10% increase at shakers and back on strokes. MPD chokes full open while drilling. Close chokes on connections and monitor for pressure - none.;Drill 8-1/2" production hole from 6418' to 6832' (3912' TVD) 414' drilled, AROP 69 FPH. 505 GPM = 1510 PSI, 120 RPM = 13K ft-Ibs torque, WOB = 10-12K. MW = 9.05 ppg, Vis = 42, ECD = 10.30 ppg, Max gas = 125 units. PU = 160K, SO = 75K, ROT = 117K.;Pumped high vis sweep at 6553', 50% increase and 150 strokes late. Entered OA1 at 6447'. MPD chokes full open while drilling. Close chokes on connections and monitor for pressure - none. Last survey at 6673.48' MD 13912' TVD, 90.45' ins, 123.78' azm, 23.5' from plan, 6.98' high, 22.44' Ieft.;Hauled 585 bbis H2O from L -Pad lake for total = 5630 bbls Hauled 100 bbls heated H2O from G&I for total = 1200 bbls Hauled 947 bbls cutting/liquids to MPU G&I for total= 8364 bbis 0 bbis daily losses, 0 bbis cumulative losses 7 concretions drilled for 3.32% of the lateral. 4/16/2019 Drill 8-1/2" production hole from 6831'to 7125' (3903' TVD) 294' drilled, AROP 49 FPH. 507 GPM = 1450 PSI, 120 RPM = 12-13K ft -lbs torque, WOS = 10K. MW = 9 ppg, Vis = 42, ECD = 10.14 ppg, Max gas = 240 units. PU = 165K, SO = 70K, ROT = 118K.;Drilling in the OA -1 sand, 4-5' above the top of OA -2; formation dip is 89.5-89.9 , next undulation to OA -3 is at 7,700'md. At 6900' dump and dilute 290 bbis due to MBT @ 7 lowering to 5. MPD monitor for pressure increase during connections.;Pump 30 bbis hi vis sweep @ 7026, sweep back 175 stks late with 25% increase.;Drill 8-1/2" production hole from 7125' to 7830' (3913' TVD) 705' drilled, AROP 117.5 FPH. 500 GPM = 1470 PSI, 120 RPM = 14K ft -lbs torque, WOB = 13K. MW = 8.9 ppg, Vis = 46, ECD = 10.35 ppg, Max gas = 132 units. PU = 167K, SO = 70K, ROT = 114K.;Drill in the OA -1 to 7500' then start down, performing the undulation to OA -3. Anticipate to be in OA -3 at 7900'. Pump 30 bbis hi vis sweep @ 7501', sweep back 200 stks late with 50% increase MPD monitor for pressure increase during connections. - none ;Drill 8- 12" production hole from 7830' to 8552' (3921' TVD) 722' drilled, AROP 120.3 FPH. 500 GPM = 1640 PSI, 120 RPM = 16K ft-Ibs torque, WOB = 5-15K. MW = 9.0 ppg, Vis = 44, ECD = 10.67 ppg, Max gas = 120 units. PU = 167K, SO = 70K, ROT = 1141K.;Drill in the OA -3 at 7960', out down to the center of the zone and level off . Formation Dip is -90°. Next undulation up to OA -1 is planned at 9,400'md. Pump 30 bbls hi vis sweep @ 7979, sweep back 200 stks late with 30% increase. MPD monitor for pressure increase during connections. - none -;Drill 8-12" production hole from 8552'to 9315' (3929' TVD) 763' drilled, AROP 127.16 FPH. 503 GPM = 1630 PSI, 120 RPM = 17-18K ft-Ibs torque, WOB = 12K. MW = 9.0 ppg, Vis = 51, ECD = 10.58 ppg, Max gas = 407units. PU = 185K, SO = 40K, ROT= 114K.;Drilling in the OA -3 sand, 3-7' below the base of OA -2; formation dip is -90°. Pump 30 bbls hi vis sweep @ 8551', sweep back 400 stks late with 25% increase Pump 30 bbis hi vis sweep @ 9028', sweep back 500 stks late with 100% increase;MPD monitor for pressure increase during connections. - none - Last survey at 9246.06' MD / 3912' TVD, 92.98' inc, 126.06' azm, 5.31' from plan, 4.45' Low, 2.89' Right.;Hauled 525 bbis H2O from L -Pad lake for total= 6155 bbis Hauled 0 bbis heated H2O from G&I for total = 1200 bbls Hauled 1265 bbis cutting/liquids to MPU G&I for total= 9629 this 0 bbis daily losses, 0 bbis cumulative losses 25 concretions drilled for 5.26% of the lateral. 4/17/2019 Drill 8-1/2" production hole from 9315' to 993V (3904' TVD) 623' drilled, AROP 103.8 FPH. 504 GPM = 1630 PSI, 120 RPM = 19K ft -lbs torque, WOB = 10K. MW = 9.0 ppg, Vis = 49, ECD = 10.68 ppg, Max gas= 148 units. PU = 185K, SO= 40K, ROT= 115K.;Drill in OA3 until -9400' then undulate to OA -1, drilling in OA -1 at 9510' MPD holding 50 psi annulus pressure during connections starting at 9609. Pump 30 bbl hi vis sweep @ 9505', sweep back 500 stks late, 50% increase.;Drill 8-1/2" production hole from 9938'to 10553' (3903' TVD) 615' drilled, AROP 102.5 FPH. 500 GPM = 1800 PSI, 120 RPM= 14K ft -lbs torque, WOB = 12K. MW= 9.0 ppg, Vis = 45, ECD = 10.63 ppg, Max gas= 147 units. PU = 175K, SO= 40K, ROT= 110K.;Pump 30 bbl hi vis sweep @9981', sweep back 600 stks late, 50% increase. 10300' Bring lubes to .5% adding 4 drums Lo -fork to system. reducing TO f/ 20k to 16k MPD holding 50 psi annulus pressure during connections. Continue drilling in OA -1 TO 10800'.;Drill 8-1/2" production hole from 10553'to 11 004' (3913' TVD) 451' drilled, AROP 75.16 FPH. 500 GPM = 1900 PSI, 120 RPM = 14K ft -lbs torque, WOB = 20K. MW = 9.0 ppg, Vis = 45, ECD =10.97 ppg, Max gas = 166 units. PU = 170K, SO = 40K, ROT = 110K.;Pump 30 bbl hi vis sweep @ 10553', sweep back 200 stks late, 40% increase. Maintaining 0.5% lube (Lo-tork) in system. MPD holding 50 psi annulus pressure during connections. Start undulation down to OA -3 at 10800';Experienced aggressive deflection off concretions while dropping down from the OA -1 to OA -3 Reamed out excessive micro dls f/10915' V 1093U (12° dl up throw, over 10' course length, reamed out to <10') & f/ 10984't/ 10994' (14° dl down throw. over 10' course length, reamed outto 00`).;Dri118-1/2" production hole from 11004'to 1150T (3926' TVD) 503' drilled, AROP 83.83 FPH. 500 GPM = 1900 PSI, 120 RPM = 16K ft -lbs torque, WOB = 11 K. MW = 9.0 ppg, Vis = 45, ECD = 11.02 ppg, Max gas = 172 units. PU = 174K, SO = 40K, ROT = 110K.;Pump 30 bbl hi vis sweep @ 11030, sweep back 500 stks late, No increase in return cuttings. Dumped and diluted 290 bbls 8.8 ppg Flo -Pro NT Maintaining 0.5% lube (Lo- tork) in system. At 11125' MPD holding 80 psi annulus pressure during connections. Entered the OA -3 at 11220', will hold until 12600'.;Last survey at 11437.11' MD / 3928.90' TVD, 90.39' Inc, 128.36° azm, 3.87' from plan, 3.6' High, 1.40' Left.;Hauled 650 bbls H2O from L -Pad lake for total = 6805 bbls Hauled 0 bbls heated H2O from G&I for total = 1200 bbls Hauled 922 bbls cutting/liquids to MPU G&I for total= 10551 bbls 0 tools daily losses, 0 bbls cumulative losses 42 concretions drilled for 311' = 4.7% of the lateral. 4/18/2019 Drill 8-1/2" production hole from 11507 to 11 983' (3914' TVD) 476' drilled, AROP 79.3 FPH. 500 GPM = 2000 PSI, 120 RPM = 18K ft -lbs torque, WOB = 10- 15K. MW = 9.0 ppg, Vis = 45, ECD = 11.15 ppg, Max gas = 368 units. PU = 175K, SO = 40K, ROT = 112K.;Pump 30 bbl hi vis sweep @ 11599', sweep back 250 stks late, 100% increase at shakers, mostly clay, sand. MPD holding 90 psi annulus pressure during connections. Maintaining 0.5% lube (Lo-tork) in system. Drill in the OA -3 until 12600' ;Drill 8-1/2" production hole from 11 983'to 12651' (3922' TVD) 668' drilled, AROP 133.6 FPH. 500 GPM = 2070 PSI, 120 RPM = 18K ft -lbs torque, WOB = 5-15K. MW = 9 ppg, Vis = 50, ECD = 11.35 ppg, Max gas = 179 units. PU = 174K, SO = 40K, ROT = 110K.;Pump 30 bbl hi vis sweep @ 12078', sweep back 300 stks late, 50% increase at shakers, mostly clay, some sand Drill in the OA -3 until 12609, start undulation to OA -1 (Entered OA -1 @ 1260V) MPD holding 100 psi annulus pressure during connections. Maintaining 0.5% lube (Lo4ork) in system.;Due to ECDs climbing to 11.35 ppg, perform cleanup cycle @ 12651', pump 30 bbl hi vis sweep, 530 gpm, 2450 psi, 120 rpm, 1lk tq. reciprocating pipe.;Drill 8-1/2" production hole from 12651'to 13110' (3932' TVD) 45V drilled, AROP 91.8 FPH. 490 GPM = 2050 PSI, 120 RPM= 21 K ft-Ibs torque, WOB = 5-15K. MW = 9 ppg, Vis = 50, ECD = 11.27 ppg, Max gas = 175 units. PU = 190K, SO = 40K, ROT = 105K. Maintaining 0.5% lube (Lo-tork).;Pump 30 bbl hi vis sweep @ 12651', sweep back 300 stks late with no increase in cuttings return. Pump 30 bbl hi vis sweep @ 13027', sweep back 300 stks late with 40% increase in cuttings return.Drill in the OA -1 (Entered OA -1 @ 12608') until 13800' 12861', MPD holding 110 psi BP during connections.;Drill 8-1/2" production hole from 13110'to 13594' (3948' TVD) 484' drilled, AROP 80.67 FPH. 490 GPM = 2150 PSI, 120 RPM = 21 K ft -lbs torque, WOB = 10K. MW = 9 ppg, Vis = 47, ECD = 11.4 ppg, Max gas = 123 units. PU = 190K, SO = 40K, ROT=109K.;Pump 30 bbl hi vis sweep @ 13503', sweep back 200 stks late, 25% increase in return cuttings. Followed the sweep with dumped and dilute of 290 bbls 8.8 ppg Flo -Pro NT. Maintaining 0.5% lube (Lo -fork) in system. At 13500' MPD holding 115 psi annulus pressure during connections.;Last survey at 13528.23' MD / 3951.08' TVD, 87.73° inc, 124.81 °azm, 21.87' from plan, 19.68' Low, 9.54' Left.;Hauled 625 btols H2O from L -Pad lake total = 7430 bbls Hauled 0 bbls healed H2O from G&I total = 1200 bbls Hauled 798 bbls cutting/liquids to MPU G&I total= 11349 bbls 0 bols daily losses, 0 bbls cumulative losses 54 concretions drilled for 41 2' = 4.8% of the lateral 4/19/2019 Drill 8-1/2" production hole from 13594' to 14168' (3966' TVD) 574' drilled, AROP 95.6 FPH. 485 GPM = 2290 PSI, 120 RPM = 23K ft-Ibs torque, WOB = 11 K. MW = 9 ppg, Vis = 50, ECD =11.8 ppg, Max gas = 339 units. PU = 195K, SO = 40K, ROT=110K.;Pump 30 bbl hi vis sweep @ 13978', back 500 stks late, 75% increase at shakers. Drill in the OA -1 until 13800', start undulation down to OA -3. MPD holding 120 psi annulus pressure during connections. Increase lubes f/ .5% to 1 % adding 4 drums Lo -fork to sys.;Drill 8-1/2" production hole from 14168' to 14739' (3980' TVD) 571' drilled, AROP 95.17 FPH. 475 GPM = 2170 PSI, 120 RPM = 21 K ft-Ibs torque, WOB = 5-7K. MW = 9.1 ppg, Vis = 51, ECD = 11.71 ppg, Max gas = 78 units. PU = 197K, SO = 40K, ROT=1101K.;Crossed the OA 2 top at 14220' and into OA -3 at 14460', Apparent dip over this section was 87.5 deg MPD holding 140 psi annulus pressure during connections. Pumped 30 bbl hi vis sweep @ 14547', back 500 stks late with no increase;Drill 8-1/2" production hole from 14739'to 15214' (4021' TVD) 475 drilled, AROP 86.36 FPH. 475 GPM = 2180 PSI, 120 RPM = 22K ft -lbs torque, WOB = 5-7K. MW = 9.05 ppg, Vis = 52, ECD = 11.2 ppg, Max gas = 290 units. PU = 212K, SO = 40K, ROT =111 K.;Maintained the OA -3 target, Apparent dip over this section was 87.75 deg. MPD holding 140 psi annulus pressure during connections. Pumped 30 bbl hi vis sweep @ 15024', back 500 stks late with no increase. Backream full stands at connection.;Perform clean-up cycle while dump and dilute with 580 bbls new 8.8 ppg Flo -Pro mud. 475 GPM - 2140 PSI, 140 RPM - 21 k Tq, Reciprocating pipe. Initial ECD @ 11.8 ppg, Final ECD @ 11.2 ppg. Tq down from 21k@ 120 RPM to 20K @ 130-140 RPM.;Drill 8-1/2" production hole from 15214'to 15595 (4004' TVD) 381' drilled, AROP 76.2 FPH. 500 GPM = 2350 PSI, 140 RPM= 201(ft-Ibs torque, WOB = 15K. MW = 9.05 ppg, Vis = 48, ECD = 11.72 ppg, Max gas =146 units. PU = 185K, SO= 40K, ROT= 110K.;Maintained the OA -3 target with formation dip of -87° until fault encountered @ 15264' MD / 4025' TVD. Fault has a 20-25 DTN throw putting the wellbore into shale below the OA - Sand Increased inc from 86.75' to 97' to reacquire the OA Zones. Base of OA -3 re-entered at 15596' MD / 4007' TVD.;At 15214', MPD holding 150 psi annulus pressure during connections. Backream full stands at connection. Pumped 30 bbl hi vis sweep @ 15498', back 500 stks late with 10% increase.;Last survey at 15525.29' MD / 4014.91' TVD, 97.33° inc, 125.34° azm, 71.36' from plan, 70.53' Low, 10.8T Right. Out of zone for a total of 332' after 2nd fault crossing. Projected #3 fault upcoming at -15780' MD.;Hauled 865 bbls H2O from L -Pad lake total = 8295 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 1127 bbls cutting/liquids to MPU G&I total= 12476 bbls 0 bbls daily losses, 0 bbis cumulative losses 67 concretions drilled for 538'= 5% of the lateral 4/20/2019 Drill 8-1/2" production hole from 15595' to 16069' (3986' TVD)474' drilled, AROP 79 FPH. 455 GPM = 2130 PSI, 120 RPM= 22K ft -lbs torque, WOB = 10K. MW =9 ppg, Vis = 48, ECD = 11.83 ppg, Max gas =427 units. PU = 193K, SO= 40K, ROT= 110K.;Encountered fault #3 @ 15796' ( 3970' TVD) with a throw of 30' down to the north, Pumped 30 bbl hi vis sweep @ 15973', back 550 silks late, no increase. MPD holding 150 psi annulus pressure during connections. Backream full stands at connechon.;Drill 8-1/2" production hole from 16069'to 16544' (3954' TVD) 475' drilled, AROP 79.16 FPH. 446 GPM = 2130 PSI, 120 RPM = 22K ft -lbs torque, WOB = 10K. MW = 9 ppg, Vis = 49, ECD = 11.92 ppg, Max gas =77 units. PU = 201K, SO = 40K, ROT = 105K.;Back in OA3 at 16120' MD ( 3979' TVD ) 324' out of zone after 3rd fault crossing. MPD holding 150 psi annulus pressure during connections. Backream full stands at connection.;Drill 8-1/2" production hole from 16544'to 16906' (3971' TVD) 362' drilled, AROP 60.33 FPH. 500 GPM = 2475 PSI, 125 RPM = 23K ft -lbs torque, WOB = 5K. MW = 8.8 ppg, Vis = 46, ECD = 11.63 ppg, Max gas =172 units. PU = 206K, SO = 40K, ROT = 105K. Backream full stands at connection.;MPD holding 165/170 psi annulus pressure during connections. Dump and dilute w/ 580 bbls new 8.8 ppg Flo -Pro mud at 16639'450 GPM - 2250 PSI, 120 RPM - 22k Tq, Reciprocating pipe Initial ECD @ 11.8 ppg, Final ECD @ 11.2 ppg. Tq down from 21 k @ 120 RPM to 20K @ 130-140 RPM;Dril18-1/2" production hole from 16909'to 17139' (3974' TVD) 230' drilled, AROP 76.66FPH. 500 GPM = 2560PSI, 125 RPM = 23K ft -lbs torque, WOB = 5K. MW = 8.9 ppg, Vis = 45, ECD = 11.91 ppg, Max gas =57 units. PU = 206K, SO = 40K, ROT = 105K. Backream full stands at connection.;MPD holding 1651170 psi annulus pressure during connections. Start losing fluid @ 17062' ECD at 11.91 ppg. Initial loss rate of 150 bbls/hr. 60 BPH Losses @ 400 GPM. Shut pump down and monitor MPD pressure, build to 290 psi.;Build and pump 30 BBL LCM Pill, 13 PPB Nutplug Fine, 13 PPD Nutplug Med, 13 PPB SafeCarb 40. Spot pill outside bit and hold for 15 min. Pumped down @ 310 GPM - 1450 PSI, 120 RPM - 21 K tq. 25 BPH Iosses.;Circulate at 300 GPM -1373 psi, 115 RPM - 20K Tq. 25 BPH losses, Increase flow to 350 GPM and losses increase to 55 BPH. Mix and pump 2nd 30 BBL LCM Pill, 13 PPB Nutplug Fine, 13 PPD Nutplug Med, 13 PPB SafeCarb 40 Pumped pill down @ 30 GPM -1290 PSI, 120 RPM, 20k Tq. 50 BPH Iosses.;Last survey at 17045.18' MD / 3972.30' TVD, 91.5° inc, 124.54° azm, 42.41' from plan, 42.13' Low, 4.86' Right.;Hauled 800 bbis H2O from L -Pad lake total = 9095 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 1477 bbls cutting/liquids to MPU G&I total= 13953 bbls 0 bbls daily losses, 0 bbls cumulative losses 71 concretions drilled for 578' = 4.7% of the lateral 4/21/2019 Working pipe f/ 17139' Pump 2nd 30 BBL LCM Pill, 13 PPB Nutplug Fine, 13 PPD Nutplug Med, 13 PPB SafeCarb 40. Pumped pill down @ 300 GPM -1290 PSI, 120 RPM, 20k Tq. 3300 siks total, with LCM pill out of bit, rack i std back to 17111% BD TD.;After pumps off, Shut in surface pressure climbed to 270 psi, slowly bled to 170 psi.;MPD hold 170 psi, circulate thru MPD equipment to keep from freezing, work pipe slow to 17021, rotating slow while S/O, letting LCM pill soak for 1 hr. Stage pumps slowly 50 gpm increments to 400 gpm, 1850 psi, loss rate 108 bph.;RIH to bttm, Work pipe f/ 17139' Pump 3rd 30 BBL LCM Pill, 13 PPB Nutplug Fine, 13 PPB Nut plug Med, 13 PPB SafeCarb 40. Pumped pill down @ 300 GPM - 1250 PSI, 50 RPM, 18k Tq. 3300 stks w/ LCM pill out of bit, rack i std back to 17111', BD TD. Pumping LCM pill, loss rate reduce f/ 108 to 12 bph.;MPD hold 170 psi, circulate thru MPD equipment to keep from freezing, work pipe slow to 17021, rotating slow while S/O, letting LCM pill soak for 1 hr. Stage up pumps slowly, 50 gpm increments to 385 gpm, 1650 psi, loss rate 48 bph.;Slow pump to 200 gpm, 950 gpm, Run back to bthn 17139' working pipe. Mix and pump 4th 30 bbl LCM pill 220 GPM - 950 PSI, 45 RPM, 15k Tq. 3300 stks w/ LCM pill out of bit, rack 1 std back to 17111', BD TD.;MPD hold 170 psi, circulate thru MPD equipment to keep from freezing, work pipe slow to 17021, rotating slow while SIO, letting LCM pill soak for 1 hr. Stage pumps slowly 50 gpm increments to 385 gpm, 1620 psi, loss rate 50 bph. Note: Decision made from town to call TO @ 17139' ( 3969' TVD ).;At 17120' Condition mud and clean wellbore for liner run, pumping 385 gpm, 1650 psi. 120 rpm, 15-23k TO, reciprocate pipe, increase lubes f/ 1 % to 4%, (2% to fork, 2% 776) each BU, rack back 2 stands total to 17014'.;On the 2nd stand pulled, losses dropped from 50 bph to 6 bph at 385 gpm. Shut down pump, MPD monitor for pressure build, 230 psi in 15 min. Total losses circulating = 62.5 bbls. PU 170K, SO 40K, ROT 113K.;Perform MPD pressure test. Shut in pressure at 235 PSI after 15 minutes.;RIH 2 stands from 17024'to bottom at 17139'. Obtain final MWD survey and establish backreaming parameters.;BROOH 1117139' t/ 15671', 389 GPM, 1620 PSI, 150 RPM, 15K TO, 11.2 ECD. Initial pulling speed of 57min, increased pulling speed to 7'/min. @ 16301' then 10'/min. @ 16119' with 11.08 ECD. Maintain 260 to 270 PSI on connections with MPD. 75.5 bbl loss while BROOH.;BROOH f/ 15671'V 14220', 370-389 GPM, 1620 PSI, 150 RPM, 15K TQ, Initial ECD of 11.2, drop to 10.76. 5-10'/min pulling speed, adjust as pressure & ECD dictate. Maintain 370 GPM, 150 RPM, 107min at 14735'. Loss rate at -10 BPH. MPD down to 200 PSI back pressure.;lncrease in cutting (Clay) @ 15400'& 15000'. Shakers blinding off with short surge of clay returned. 115 bbls loss at 10-50 BPH while BROOK Total losses while BROOH = 190.5 bbls.;Final survey of 17069.48' MD / 3971.79' TVD, 90.94° inc, 124.43° azm, showed 41.41' from plan, 42.15' low & 4.67' right.;Hauled 90 bbls H2O from L -Pad lake total = 9185 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 171 bbls cuttingaiquids to MPU G&I total= 14124 bbls 353 bbls daily losses, 353 bbls cumulative losses 71 concretions drilled for 578' = 4.7% of the lateral 4/22/2019 Continue to BROOH f/ 14220't/ 12366', 375 GPM, 1230 PSI, 150 RPM, 10K TO, No issues. ECD of 10.61. with 10'/min pulling speed, adjust as pressure & ECD dictate. Maintain 375 GPM, 150 RPM, Loss rate at -10.4 BPH. MPD holding 70 PSI back reaming and 260 psi during connections.;BROOH f/ 12366't/ 10115', 375 GPM, 1230 PSI, 150 RPM, 7.51K TO, No issues. ECD of 10.60. with 10'/min pulling speed, adjust as pressure & ECD dictate. Maintain 375 GPM, 150 RPM, Loss rate at -10.4 BPH. MPD holding 170 PSI back reaming and 260 psi during connections.;BROOH f/ 101 15' V 7885', 375 GPM, 1030 PSI, 150 RPM, 7K TQ, No issues. ECD of 10.60. with 10'/min pulling speed. Maintain 375 GPM, 150 RPM, Loss rate at -7BPH. MPD holding 200 PSI back reaming and 260 psi during connections.;BROOH f/ 7885' U 5778', 375 GPM, 1030 PSI, 150 RPM, 41K TO, No issues. ECD of 10.60. with 107min pulling speed. Maintain 375 GPM, 150 RPM, Loss rate at -2 BPH. MPD holding 220 PSI back reaming and 260 psi during connections.;10k overpull & 2.5k increase in torque at 6373'. No pressure increase observed. Reduce pulling speed and work through 2x until clean before continue BROOH.;Hauled 280 bbls H2O from L -Pad lake total = 9465 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 57 bbls cutting/liquids to MPU G&I total= 14181 bbls 161 bbls daily losses, 514 bbls cumulative losses 4/23/2019 BROOH f/ 5778' V 5129', 375 GPM, 1030 PSI, 150 RPM, 4K TQ, No issues. ECD of 10.60. with 107mm pulling speed. Maintain 375 GPM, 150 RPM, Loss rate at-2 BPH MPD holding 200 PSI back reaming and 260 psi during connections. Obtain MWD survey @ 4957'.;BROOH V 5129 t/ 4838',(95/8 shoe @ 4856), 375 GPM, 1030 PSI, 120 RPM, 5-6K TQ, No issues. Slow RPM U 120/80/60 as BHA enters the shoe.;Circulate 2x 30 bbl Hi-vis sweeps around. 377 GPM - 1030 PSI, 120 RPM 31k Tq. 50% increase in cuttings return with 1st sweep, no increase on 2nd sweep. PU=137k, 5O=104k.;Perform MPD pressure test. Initial shut in pressure of 250 psi, increased to 263 psi. Bled down to 200 psi, increased to 220 psi. Bleed off 2 bbis, psi @ 80# increasing to 167 psi. Bleed down 2 bbls, psi @ 30#, increasing to 118 psi. Bled down to 30 psi, pressure increase to 80 psi.;Circulate 20 bbis to warm lines. Shut pumps down and monitor pressure. Bled off 2 bbls in 15 min, Calculated increase of 0.3 PPG.;Circulate 9.4 PPG mud around. Initial 300 GPM -590 psi. 80 RPM -1-2k Tq. Final 300 GPM - 620 psi. 9.4 ppg in/ out.;Monitor flow at trip tank. 0.8 bbls return over 20 minutes, becoming static. Continue to monitor well -static- Remove RCD Bearing and install trip nipple.;Fill lines and check for leaks -no leaks -Monitor well on trip tank. Slip and cut 100' drlg line. Inspect saver sub and service TopDrive & Crown.;POOH on elevators, laying down singles, from 4835to 4385'. No sign of swabbing or gains. Pump dryiob and B/D TD. Continue pulling out of hole laying down singles V 274'. 26.3 bbl loss on trip out of hole.;Monitor well. UD HWDP, Jars & Flex Collars. Plug in and Download MWD data. UD DM Collar.;Service Rig, Topdrive & Drawworks.;Continue to UD BHA to pipeshed. BIO bit & UD. Bit graded 2-1-CT-N-X-I-NO-TD. Had a few chipped cutters, otherwise in good shape. ILS had undercut wear on both ends of blades, no other notable damage to BHA assembly.;Clear and Clean rig floor. PJSM and prep for UD drillpipe from Derrick.;Hauled 40 bbis H2O from L-Pad lake total = 9505 bbis Hauled 0 bbis heated H2O from G&I total = 1200 bbls Hauled 347 bbis cutting/liquids to MPU G&I total= 14528 bbls 32.5 bbis daily losses, 545.5 bbis cumulative losses 4/24/2019 Lay down 60 stands 5" Drill Pipe from the Derrick via mousehole. Monitor well on trip tank. - 12 bbis loss -;Continue laying down 5" Drill Pipe from Derrick via mousehole. 90 Stand total laid down. 51 stands left in Derrick.;Mobilize 3-112" handling equipment to rig floor. R/U for making stds of 3-1/2", 9.3#, L-80 Tubing.;Pick up and rack in Derrick, 57 stands 3-1/2", 9.3#, L-80 Tubing. Tq V 3130 R/Ibs. Static loss rate @ -1 BPH.;Pick up and rack in Derrick, 47 stands 3- 112". 9.3#, L-80 Tubing. Tq t/ 3130 ft/lbs. Static loss rate @ -1 BPH.;Hauled 25 bbls H2O from L-Pad lake total = 9530 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbis Hauled 347 bbis cutting/liquids to MPU G&I total= 14528 bbis 44 bbis daily losses, 589.5 bbis cumulative losses 425/2019 Continue to build 77 stands stands of 3-12", 9.3# L-80 Tubing and rack in Derrick. Total of 134 stands racked back. 1 BPH static loss rate.;Clear and clean rig floor. C/O elevators. P/U jnt DP and M/U stack washer. Wash stack and LID wash tools.;RU ROPE testing equipment. Pull wear bushing & install the test plug. Flood lines, choke manifold and stack with fresh water. Purge the air from the system & perform body test. Good Test. Put rig on Shore Hi-Line power @ 13:46 hrs;Test BOP equipment as per AOGCC & PTD requirements. AOGCC inspector Matthew Herrera witnessed testing. All tests performed to 250 PSI low / 3000 PSI high, held for 5 min. & charted. #1: Upper 4-1/2"x7" VBR on 5" test joint, choke valves 1,12,13,14, 3" kill line Demco valve & upper IBOP.;#2: HCR kill, lower IBOP, Choke valves 9 & 11 #3: Manual kill, 5" TIW #1, Choke valves 5, 8 &10 #4: 5" TIW #2, choke valves 4, 6 & 7. #5: 5" dart valve, choke valves 2.;#6: Lower 2 7/8"x5" VBR on 5" test joint. Accumulator test: 3000 PSI system, 1650 PSI after closure, 200 PSI in 40 sec., full in 185 sec., 6 nitrogen bottle avg 2068 PSI. #7: Annular on 3-1/2" test joint, Manual choke #8: Lower 2-718"x5" VBR on 3-112" test joint. #9: Upper 4-12"x7" VBR on 7" test;#10: Blind rams & choke valve 3 #11: Hydraulic choke "A" #12: Manual choke "B" Pull test plug and UD test joint. Blow down choke & kill lines. Install 9" ID wear bushing.;Rigged up casing running equipment and MIU safety joint for 6-518" PDL run.;Hold PJSM with rig and casing crew. P/U shoe joint, P/U and RIH w/6-5/8", 20#, L-80, Hydril 563, Pre-Drilled liner V 1186'. Centralizer every joint. M/U Tq = 7100 ff/Ibs. Losses @ 1 BPH;P/U and RIH w/ 6-5/8", 20#, L-80, Hydril 563, Pre-Drilled liner V 1186't/ 6464'. P/U Wt @ Shoe = 1151k, S/O = 99k. Centralizer every joint. M/U Tq = 7100 ft/Ibs. Losses @ 1 BPH.;Hauled 90 bbis H2O from L-Pad lake total= 9620 bbis Hauled 0 bbls heated H2O from G&I total = 1200 bbis Hauled 57 bbls cutting/liquids to MPU G&I total= 14585 bbis 32.4 bbis daily losses, 621.9 bbls cumulative losses 4/262019 Cont P/U and RIH w/ 6-5/8", 20#, L-80, Hydril 563, PDL V 6464't' 12453. PIU Wt = 165k, S/O = 70k. Cent every joint. M/U Tq = 7.1 k Nibs. Losses @ 1 BPH. Tagged up ledge at 11014', worked string up and down 2x before making it through. No other issues. Liner set in compression on down stroke.;Change handling equipment to 3-1/2". Change safety joint XO's to 3-1/2". Rig up 4-12" double stack power tongs and false table.;PJSM with rig, BOT and casing crew. RIH with 3-IP', 9.3#, L-80 EUE tubing from Derrick U6125'. 3100 fVlbs Tq. P/U = 75K, S/O = 65K;M/U safetyjt & triple connect. R/D false table and break over 6-5/8" PDL. P/U U 225k & SIO V45k 2x. Apply rotary at 5k Tq and S/O V 451k then pull up, string free @ 2151k. Work string 2x f/ 12453 V 12414'. 195k Up wt, 951k down. Reset PDL in compression, R/U false table and UD safety joint.;Continue RIH with 3-1 P', 9.3#, L-80 EUE tubing from Derrick f/ 61 25'V7243T. 3100 ft/lbs Tq. P/U = 75K, SIO = 65K UD 2 its for space oukMN safery jt & triple connect. R/D false table and break over 6-518" PDL. P/U V 225k & SID V40k 2x. Apply rotary at 5k Tq and S/O V 40k then pull up, string free @ 220k. Work string 2x f/ 12453' V 12414'. 200k Up wt, 85k down. Reset PDL in compression, R/U false table and UD safety joint.;Space out 3-1/2" tubing 2x 6' pups. M/U Baker SLZXP Packer and 3 jts 5" HWDP V 12,581' Set 3-12" inner string 5.37' off no-go Drift HWDP w/ 2.34";Kelly up and break circulation. Pumped 10 bbis. Stage up from 1 BPM - 380 psi to 3 BPM - 640 psi;Continue running in hale with the 6-5/8" pre-drilled liner on 5" HWDP V 13660'. Losses at 1 BPH;Hauled 30 bbis H2O from L-Pad lake total = 9650 bbis Hauled 0 bbls heated H2O from G&I total = 1200 bbis Hauled 57 bbis cutting/liquids to MPU G&I total= 14642 bbis 32.5 bbis daily losses, 654.4 bbis cumulative losses 4/272019 Continue to Run 20# L-80 6.625 PDL Liner to him on 5" HWDP from the pipe shed F/ 13660'T/ 17140'. Fill on the fly topping off every 15 joints. Wash down last joint staging pumps up to 2 bpm. Took 290 to break over up. UP/DN 270/115K;Continue to stage up pumps monitoring losses. Stage up pumps to 5 bpm at 1450 psi. Start ROT before brine reaches shoe. 18K Tq Working pipe 41' with IOk RPM. Stop ROT & reciprocating at 900 bbl in to circ. Cleared two OH volumes with sea water while ROT.;See completions report for remainder of daily activity.;Hauled 115 bbls H2O from L-Pad lake total = 9765 bbis Hauled 0 bbis heated H2O from G&I total = 1200 bbis Hauled 2472 bbis cuffing/liquids to MPU G&I total= 17114 bbls Hilcorp Energy Company Composite Report Well Name: MP M-14 Field: Milne Point County/State: , Alaska (LAT/LONG): avation (RKB): API #: Spud Date: 4/7/2019 Job Name: 1814314C MPU M-14 Completion Contractor APE #: AFF S' Activity Data Ops Summary 4/27/2019 Continue to stage up pumps monitoring losses. Stage up pumps to 5 bpm at 1450 psi. Start ROT before brine reaches shoe. 18K Tq Working pipe 41' with 10k RPM. Stop ROT & reciprocating at 900 bbl in to circ. Cleared two OH volumes with sea water while ROT before parking.,Circ Sweep & three sapp pills with 50 BBL in between all in seawater. Pump 610 bbl total Circ at 5 bpm & Chase with 9.4 PPG Brine with sweep until it cleaned up and went to brine. 757 bbl total.,Shut down and drop setting ball. 1.25 OD. Chase down with HV pill & 1380 bbl 9.4 brine. Set SLZXP as per baker rep. Bump and pressure up to 2800 psi. felt shift at 2600. Hold 2800 for 5 min. Pressure up to 3800 psi with rig pumps and line up lest pump. Pressure up to 4200 psi and felt release. Set down to 150K as per baker hand. Bleed down and P/U & verify free.,Close annular and test LT & back side to 1680 psi for 10 min. Good. TOL = 4657.32' BOL = 17139' Bleed down and UD top single.,P/U & break circ pumping HV sweep and chase with two Liner volumes. 600 bbls total. Pump @ 5-7 BPM as losses allowed. Initial brine wt back - 8.5+ ppg Increasing U 9.3 ppg at 550 bbls pumped. Clean brine back at 580 bbls. Losses - 188 bible Shut down and monitor well. 40 bbl/hr static losses.,POOH UD 5" HWDP to pipe shed f/ 17120't/ 14345' Losses - 40 bbls/hr Brine wt for hole fill reduced to 9.2 ppg @ 23:00,Continue POOH UD 5" HW DP to pipe shed 1114345' V 12490' Losses - 40 bbls/hr,C/O handling equipment V 3-1/2". M/U floor valve to 3-1/2" EUE XO. UD Packer/Hanger running tool.,POOH laying down 3-1/2" tubing to pipe shed f/ 12490' V 9370' Losses - 30 bbWhr Brine wt for hole fill reduced to 9.1 ppg, Hauled 115 this H2O from L -Pad lake total = 9765 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 2472 bbls cutting/liquids to MPU G&I total= 17114 bbls 4/28/2019 POOH f/ 9270't' 4557', laying down 3-1/2", 9.3# 1 EUE tubing to shed. 9.1 ppg brine top filling the hole. Losses slowing down from 30 BPH to 20 BPH,POOH V 4557' V surface, racking 3-1/2", 9.39 1 EUE tubing in Derrick. Losses at 18 Blai down Baker slick stick assembly. Change out 3-1/2" handling equipment. WU 3-1/2" wash pipe to 8.37' No-Go.,Service top drive - change out fill up connection, add hydraulic oil,Change out link tilt hydraulic hoses on top drive.,RIH with 3-1/2" wash pipe on 5" drillpipe from Derrick to 4581'. PU=131 SO= 1151 Continue in and tag out with No -Go at 4671'. Tag out 8k on depth.,Establish circulation and stage pumps up to 14 BPM - 560 psi. Circulate bottoms up 5x. Losses @ 75 BPH,Build & pump 9.1 ppg hi -vis sweep followed with 407 bbis 9.11 brine, pumping until clean brine observed at surface. 3-7 BPM, 50-170 psi. Total pumped 441 bbls, Loss of 24 bbls while circulating displacing.,Monftor well, -taking Fluid-. UD 5" drillpipe single & blowdown topdrive.,POOH f/ 4644' V surface, laying down 5" drill pipe to shed. Break and lay down wash pipe & pull wear bushing. 42.7 bbls lost over pipe displacement / 13.13 BPH average,Clear and clean rig floor. C/O handling equipment & rig up to run 7". Rig Perform dummy run with 7" hanger & landing joint. M/U floor valve to 7" XO 18 BPH static losses, PJSM, P/U Baker Bullet seals tie -back assembly to 17'. Run 7" 26# L-80 TXP BTC -SR liner f/ 17' V 3901' Torque to 14750 Ili with Doyon casing double stack tongs. 16-18 BPH loss rate -Hauled 190 bbls H2O from L -Pad lake total = 9955 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbls Hauled 605 bbls cutting/liquids to MPU G&I total= 17719 bbls Diesel Fuel (Gallons): Recd = 0, Used = 699, On hand = 7626 505.1 bible daily losses, 1453.5 bbls cumulative losses Total Mud Loss = 677.40 1 Total Brine Loss = 776.1 4/29/2019 Run T'26# L-80 TXP BTC -SR liner f/ 3901'V 4665.58' Torque to 14750 ft/lbs with Doyon casing double stack tongs. Tagged No -Go 5k (1'high) 16-18 BPH loss rate -Shut annular & Pressure test backside to 250 . Verity seals landed Good. Bleed down and open up annular. UD joints 115 & 114. P/U joint # 120 for space out. M/U hanger and landing joint. R/U circ equipment. M/U to string and land out. Close annular., Pressure up on injection line to 250. P/U on string until ports open and verify pressure dump. Good.,PJSM, & test lines to annulus. Good. Pressure up on injection line to 250. P/U on string until ports open and verify pressure dump. Good. Line up and reverse circ 63 bbl corrosion inhibitor then chase with 71 bbl diesel. FCP 430 psi. Land hanger.,Bleed down to cellar and verify seals engaged. Good. Back side dead. Open annular & drain stack. R/D landing joint. Change handling equipment to 5". M/U Pack off running tool on two singles of 5" dip. RIH & set pack off. RILD. Wellhead rep verify. Test Void to 500/5000 psi good. 5 min./10 min.,Test annulus to 1200 psi for 30 min. Bled down 30 psi. Good. Bleed of pressure test & R/D 5" equipment. Side note- Conduct PJSM R/U & run 3.5 completion with SLB talk wire & Halliburton completions.,R/U to run 3.5 completion. R/U shives & tie back lugger lines. WU Well control XO & 3.5 IF TIW.,M/U 3-112" pup joint w/ wireline entry guide, 3 joints of 3-112" 9.3# L-80 EUE tubing, HES XN nipple assy, 1 joint 3- 1/2" tubing, HES 3-1/2"x7" retrievable packer, i joint of 3-1/2" tubing, HES X nipple assy and SLB sliding sleeve and gauges to 273'. Torque to 3000 Ribs with Doyon casing double stack tongs. Loss Rate - 24 BPH,Terminate TEC wire and pressure test to 5000 PSI - good test.,Continue to run 3-1/2" Jet Pump completion on 3-1/2" 9.3# L-80 EUE tubing from the derrick f/ 273 t/ 2057' as per tally. Torque to 3000 fVlbs with Doyon casing double stack tongs. Install 143 cross coupler Cannon clamps, at every connection, 6 half clamps & 2 centralizer clamps Loss Rate - 18 BPH.,Code 99 Red on pad. Secure and monitor the well. Available personnel respond to vehicle fire on pad.,PJSM, Continue to run 3-1/2" Jet Pump completion on 3-1/2" 9.3# L-80 EU E tubing from the derrick f/ 205T t/ 4676' as per tally. Torque to 3000 fit/lbs with Doyon casing double stack tongs. Install 143 cross -coupler Cannon clamps, at every connection, 6 half clamps & 2 centralizer clamps Loss Rate - 18 BPH.,C/0 elevators & P/U 5" drill pipe landing joint. M/U XO subs & Cameron 11"x3-112" tubing hanger. Perform TEC wire penetrations through hanger. Blow down Iines.,Land 3-1/2" completion on hanger. 75K PU, 70K SO, 30K on hanger. Final pressure gauge readings. Intake: 1805.74 PSI, 64.52', Discharge: 1808.41 PSI, 64.51". Run in lock down screws. Drop ball (1.31") & rod. R/U circulating head, hoses & chart recorder., Pressure up to 3600 PSI on the tubing. Set packer & test tubing for 30 min. Bleed tubing to 2100 PSI. Pressure up to 3600 PSI on the IA & test casing for 30 min. Tubing climbed to 2700 PSI due to compression. Bleed tubing off, shear valve in GLM @ 2288'., UD landing jt. Install BPV and test U 500 psi. Start cleaning rig floor.,N/D BOPE and rack back to travelling stump. Continue clear and clean rig floor of completion handling equipment.,Clean and prep hanger and TEC wire. Nipple up tree and test void to 500/5000 psi. Install gauge housing.,Hauled 85 bbls H2O from L -Pad lake total = 10040 bbls Hauled 0 bbls heated H2O from G&I total = 1200 bbl 4/30/2019 Schlumberger representative tested electrical connections and operation of downhole gauges - good., Remove BPV, install TWC, RU and pressure test tree to 250 PSI low / 5000 PSI high for 5 min. each - good tests.,Remove TWC and unable to thread in BPV. Well head representative sourced and installed replacement BPV., R/U circulating lines to tree. Pump 83 bbls diesel freeze protection down the tubing, taking returns to the cellar from IA at 2 BPM, 400 PSI ICP and 400 PSI FCP. Flush mud pump #1 with 20 bbls of water, blow down lines and RD circulating Iines.,Secure cellar and well. Final pressures: tubing = 100 PSI, IA = 200 PSI, OA = 0 PSI.,Released rig at 12:00 and begin preparing for rig move to M-16. Please see M-16 report for remainder of day., Hauled 0 bbls H2O from L -Pad lake for total = 10040 bbls Hauled 0 We heated H2O from G&I for total = 1200 bbls Hauled 0 bbis cuffing/liquids to MPU G&I for total= 17802 bbls 5/2/2019 —WEATHER STAND-BY FOR HIGH WINDS"' 5/3/2019 PT PCE TO 250psi LOW, 2,500psi HIGH PULLED BALL & ROD ASSEMBLY FROM RHC -M @ 4,550' SLIM. PULLED 1.5 SHEAR VLV FROM STA.91 @ 2,259' SLIM . SET 1.5" DGLV IN STA.# 1. PULLED RHC -M BODY FROM XN-NIP @ 4,564' SLM . SHIFTED SLIDING SLEEVE DOWN TO THE OPEN POSITION @ 4,423' SUM. SET 3-1/2" X -LOCK & 3" JET 5/10/2019 "WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 250U2000H" PULL 3" JET PUMP (SER #: HC -0001, RATIO 12B, FLOW THROUGH SUB, OAL=62") @ 4422' SLM / 4454' MD, RECOVER PACKING & NUBBINS SET 3" JET PUMP (SER #: H-1113, RATIO 9C, SCREEN, OAL=69") IN XD SSD @ 4424' SLM 14454' MD, GOOD SET '"JOB COMPLETE, NOTIFY PAD -OP TO LEAVE WELL S11 UPON DEPARTURE" Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-14 500292362500 Sperry Drilling Definitive Survey Report 22 April, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-14 Project: Milne Point TVD Reference: MPU M-14 Actual RKB @ 58.77usft Site: M Pt Moose Pad MD Reference: MPU M-14 Actual RKB @ 58.77usft Well: MPU M-14 North Reference: True Wellbore: MPU M-14 Survey Calculation Method: Minimum Curvature Design: MPU M-14 Database: NORTH US+CANADA Iroject Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-14 Well Position +N/S +E/ -W Position Uncertainty Wellbore MPU M-14 0.00 usft Northing: 0.00 usft Easting: 0.00 usft Wellhead Elevation: Magnetics Model Name Sample Date Design Audit Notes: Version: Vertical Section: BGGM2018 4/1!2019 MPU M-14 6,027,765.67 usfl Latitude: 533,903.80 usfl Longitude: 0.00 usfl Ground Level: Declination Dip Angie 16.71 70° 29' 12.7798 N 149° 43'22.4151 W 24.70 usft Field Strength (nT) 80.96 57,430.93568750 1.0 Phase: ACTUAL Tie On Depth: 34.07 Depth From (TVD) +N/ -S +EI -W Direction (usft) (nen) (usft) (I 34.07 0.00 0.00 124.93 Survey Program Date 4/22/2019 From To (usft) (nsft) Survey (Wellbore) Tool Name Description Survey Date 134.20 4,812.15 MPU M-14 MWD+IFR2+MS+Sag (1) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 04/03/2019 4,861.24 17,069.48 MPU M-14 MWD+IFR2+MS+Sag (2) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 04/15/2019 Survey Map Map Vertical MD (usft) Inc (I Azi (I TVD (usfl) TVDSS (usfl) +N/ -S (usfl) +E/ -W (usft) Northing (ft) Easting (ft) DLS (111001 Section (ft) Survey Tool Name 34.07 0.00 0.00 34.07 -24.70 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 UNDEFINED 134.20 0.32 50.62 134.20 75.43 0.18 0.22 6,027,765.85 533,904.02 0.32 0.08 2_MWD+IFR2+MS+Sag(1) 227.97 0.57 70.10 227.97 169.20 0.50 0.86 6,027,766.18 533,904.65 0.31 0.42 2_MWD+IFR2+MS+Sag(1) 321.43 0.96 85.41 321.42 262.65 0.72 2.07 6,027,766.40 533,905.87 0.47 1.29 2_MWD+IFR2+MS+Sag(1) 414.13 3A9 126.75 414.06 355.29 -0.71 4.85 6,027,764.98 533,908.65 2.65 4.38 2_MWD+IFR2+MS+Sag(1) 508.38 4.75 137.36 508.09 449.32 -5.10 9.53 6,027,760.61 533,913.35 1.91 10.73 2_MWD+IFR2+MS+Sag(1) 599.73 8.34 139.58 598.83 540.06 -12.93 16.39 6,027,752.82 533,920.25 3.94 20.84 2_MWD+IFR2+MS+Sag(1) 694.37 12.09 142.11 691.95 633.18 -25.98 26.93 6,027,739.81 533,930.85 3.99 36.96 2_MWD+IFR2+MS+Sag(1) 789.16 14.89 146.41 784.12 725.35 -43.96 39.77 6,027,721.89 533,943.76 3.14 57.78 2_MWD+IFR2+MS+Sag(1) 884.18 19.34 147.80 874.91 816.14 -67.46 54.91 6,027,698.47 533,959.02 4.70 83.65 2_MWD+IFR2+MS+Sag(1) 977.23 23.46 147.73 961.52 902.75 -96.17 73.02 6,027,669.84 533,977.25 4.43 114.93 2_MWD+IFR2+MS+Sag(1) 1,072.74 26.57 145.77 1,048.07 989.30 -129.92 95.19 6,027,636.20 533,999.58 3.37 152.43 2_MWD+IFR2+MS+Sag(1) 1,167.04 28.87 144.57 1,131.54 1,072.77 -165.91 120.26 6,027,600.33 534,024.80 2.51 193.59 2_MWD+IFR2+MS+Sag(1) 41222019 2:34:52PM Page 2 COMPASS 5000.15 Build 91 41221019 2:34:52PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-14 Project: Milne Point TVD Reference: MPU M-14 Actual RKB @ 58.77usft Site: M Pt Moose Pad MD Reference: MPU M-14 Actual RKB @ 58.77usft Well: MPU M-14 North Reference: True Wellbore: MPU M-14 Survey Calculation Method: Minimum Curvature Design: MPU M-14 Database: NORTH US+CANADA Survey Map Map vertical NO Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°floe') (ft) Survey Tool Name 1,262.59 26.94 145.36 1,215.97 1,157.20 -202.51 145.94 6,027,563.84 534,050.64 2.06 235.60 2_MWD+IFR2+MS+Sag (1) 1,356.15 26.45 146.10 1,299.56 1,240.79 -237.25 169.60 6,027,529.22 534,074.47 0.63 274.89 2_MWD+IFR2+MS+Sag(1) 1,451.97 25.77 146.25 1,385.60 1,326.83 -272.28 193.08 6,027,494.30 534,098.10 0.71 314.20 2_MWD+IFR2+MS+Sag(1) 1,546.43 26.06 145.86 1,470.56 1,411.79 -306.52 216.13 6,027,460.16 534,121.31 0.36 352.70 2_MWD+IFR2+MS+Sag(1) 1,640.81 28.24 145.11 1,554.54 1,495.77 -342.00 240.54 6,027,424.80 534,145.87 2.34 393.03 2 MWD+IFR2+MS+Sag(1) 1,736.22 28.14 145.48 1,638.63 1,579.86 -379.06 266.20 6,027,387.87 534,171.70 0.21 435.28 2_MWD+IFR2+MS+Sag(1) 1,831.43 27.33 144.75 1,722.90 1,664.13 -415.40 291.54 6,027,351.64 534,197.20 0.92 476.87 2_MWD+IFR2+MS+Sag(1) 1,925.36 28.52 144.33 1,805.89 1,747.12 -451.23 317.06 6,027,315.93 534,222.88 1.28 518.31 2_MWD+IFR2+MS+Sag(1) 2,020.66 30.18 143.83 1,888.96 1,830.19 489.05 344.47 6,027,278.24 534,250.46 1.76 562.43 2_MWD+IFR2+MS+Sag(1) 2,115.73 29.70 144.44 1,971.34 1,912.57 -527.50 372.27 6,027,239.92 534,278.43 0.60 607.24 2_MWD+IFR2+MS+Sag(1) 2,210.47 31.38 144.53 2,052.94 1,994.17 -566.69 400.23 6,027,200.87 534,306.57 1.77 652.60 2_MWD+IFR2+MS+Sag (1) 2,305.87 31.34 145.27 2,134.40 2,075.63 -607.31 428.78 6,027,160.38 534,335.30 0.41 699.27 2_MWD+IFR2+MS+Sag(1) 2,401.37 30.27 145.99 2,216.43 2,157.66 -647.67 456.39 6,027,120.15 534,363.10 1.19 745.02 2_MWD+IFR2+MS+Sag(1) 2,496.55 30.36 146.89 2,298.59 2,239.82 -687.71 482.95 6,027,080.24 534,389.83 0.49 789.71 2 MWD+IFR2+MS+Sag(1) 2,591.75 29.64 144.24 2,381.04 2,322.27 -726.96 509.85 6,027,041.11 534,416.91 1.58 834.24 2_MWD+IFR2+MS+Sag(1) 2,687.03 28.83 144.82 2,464.18 2,405.41 -764.86 536.86 6,027,003.34 534,444.08 0.90 878.08 2_MWD+IFR2+MS+Sag(1) 2,781.09 28.85 143.33 2,546.58 2,487.81 -801.60 563.47 6,026,966.73 534,470.87 0.76 920.94 2_MWD+IFR2+MS+Sag(1) 2,878.71 29.83 144.07 2,631.68 2,572.91 -840.15 591.79 6,026,928.31 534,499.35 1.07 966.23 2_MWD+IFR2+MS+Sag(1) 2,974.43 29.20 142.11 2,714.98 2,656.21 -877.85 620.10 6,026,890.74 534,527.83 1.20 1,011.03 2_MWD+IFR2+MS+Sag(1) 3,069.33 28.62 141.17 2,798.05 2,739.28 -913.83 648.57 6,026,854.90 534,556.46 0.78 1,054.96 2_MWD+IFR2+MS+Sag(1) 3,164.45 29.50 141.84 2,881.19 2,822.42 -949.99 677.32 6,026,818.87 534,585.38 0.99 1,099.24 2_MWD+IFR2+MS+Sag(1) 3,259.13 29.02 141.00 2,963.79 2,905.02 -986.17 706.18 6,026,782.83 534,614.39 0.67 1,143.62 2_MWD+IFR2+MS+Sag (1) 3,353.55 29.56 141.33 3,046.14 2,987.37 -1,022.15 735.14 6,026,746.98 534,643.52 0.60 1,187.97 2_MWD+IFR2+MS+Sag(1) 3,447.84 34.21 140.63 3,126.18 3,067.41 -1,060.82 766.51 6,026,708.46 534,675.06 4.95 1,235.82 2_MWD+IFR2+MS+Sag(1) 3,542.94 35.87 140.84 3,204.04 3,145.27 -1,103.10 801.06 6,026,666.35 534,709.80 1.75 1,288.36 2_MWD+IFR2+MS+Sag(1) 3,636.87 36.92 139.31 3,279.65 3,220.88 -1,145.83 836.83 6,026,623.78 534,745.77 1.48 1,342.15 2_MWD+IFR2+MS+Sag(1) 3,733.13 40.25 138.69 3,354.89 3,296.12 -1,191.12 876.22 6,026,578.67 534,785.36 3.48 1,400.38 2_MWD+IFR2+MS+Sag(1) 3,827.56 43.68 137.79 3,425.09 3,366.32 -1,238.20 918.28 6,026,531.79 534,827.63 3.69 1,461.82 2_MWD+IFR2+MS+Sag(1) 3,921.85 46.89 136.86 3,491.42 3,432.65 -1,287.45 963.70 6,026,482.76 534,873.27 3.48 1,527.26 2_MWD+IFR2+MS+Sag(1) 4,016.22 49.49 135.63 3,554.33 3,495.56 -1,338.24 1,012.35 6,026,432.19 534,922.14 2.92 1,596.22 2_MWD+IFR2+MS+Sag(1) 4,113.26 54.41 132.65 3,614.13 3,555.36 -1,391.38 1,067.21 6,026,379.31 534,977.24 5.62 1,671.63 2_MWD+IFR2+MS+Sag(1) 4,208.27 57.91 127.91 3,667.05 3,608.28 -1,442.32 1,127.42 6,026,328.65 535,037.67 5.54 1,750.16 2_MWD+IFR2+MS+Sag(1) 4,303.54 62.44 125.63 3,714.43 3,655.66 -1,491.75 1,193.63 6,026,279.53 535,104.10 5.19 1,832.74 2_MWD+IFR2+MS+Sag(1) 4,399.52 66.31 125.71 3,755.93 3,697.16 -1,542.20 1,263.92 6,026,229.40 535,174.61 4.03 1,919.25 2_MWD+IFR2+MS+Sag(1) 4,494.88 71.33 127.04 3,790.38 3,731.61 -1,594.93 1,335.48 6,026,177.00 535,246.40 5.42 2,008.11 2_MWD+IFR2+MS+Sag(1) 4,588.17 74.50 125.31 3,817.78 3,759.01 -1,647.55 1,407.45 6,026,124.72 535,318.61 3.83 2,097.25 2_MWD+IFR2+MS+Sag(1) 4,685.62 78.41 126.84 3,840.60 3,781.83 -1,703.33 1,484.00 6,026,069.29 535,395.40 4.29 2,191.95 2_MWD+IFR2+MS+Sag(1) 4,781.49 82.88 127.63 3,856.18 3,797.41 -1,760.56 1,559.29 6,026,012.41 535,470.95 4.73 2,286.44 2_MWD+IFR2+MS+Sag(1) 4,812.15 83.44 128.25 3,859.83 3,801.06 -1,779.27 1,583.30 6,025,993.81 535,495.04 2.71 2,316.84 2_MWD+IFR2+MS+Sag(1) 4,861.24 84.76 128.85 3,864.88 3,806.11 -1,809.70 1,621.49 6,025,963.56 535,533.36 2.95 2,365.57 2_MWD+IFR2+MS+Sag(2) 41221019 2:34:52PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 Survey MD Inc Azi TVD (usft) (1) (1) (usft) 4,956.51 86.81 130.01 3,871.88 5,050.29 86.18 128.85 3,877.61 5,145.70 85.00 5,241.55 84.75 5,339.24 84.82 5,433.39 85.69 5,529.80 87.11 5,622.95 87.48 5,720.77 88.53 5,816.57 88.22 5,911.20 87.85 6,004.85 89.77 6,101.62 92.05 6,196.91 92.30 6,292.47 92.30 6,387.24 92.49 6,482.80 91.49 6,577.85 90.82 6,673.48 90.45 6,769.20 91.56 6,864.23 91.00 6,960.34 91.19 7,055.11 90.14 7,149.25 90.63 7,244.65 90.01 7,340.06 90.76 7,432.88 90.57 7,528.28 89.89 7,625.64 87.98 7,720.63 87.60 7,815.36 87.04 7,910.05 88.35 8,006.14 87.98 8,101.40 90.26 8,197.08 90.26 8,291.95 90.51 8,387.23 89.76 8,480.32 89.34 8,571.31 89.27 8,673.30 89.46 125.24 121.82 121.81 123.29 125.14 125.14 124.41 123.99 123.21 124.29 123.57 122.37 122.36 122.87 122.91 123.22 123.78 126.36 128.40 129.99 129.81 126.37 122.47 123.02 123.78 123.75 124.91 125.56 124.50 125.36 125.93 127.71 127.44 126.89 126.91 125.51 123.33 123.36 3,884.95 3,893.52 3,902.40 3,910.19 3,916.24 3,920.64 3,924.04 3,926.76 3,930.00 3,931.95 3,930.41 3,926.79 3,922.96 3,919.00 3,915.68 3,913.77 3,912.71 3,911.03 3,908.90 3,907.07 3,905.97 3,905.33 3,904.80 3,904.16 3,903.08 3,902.70 3,904.51 3,908.17 3,912.60 3,916.41 3,919.49 3,920.95 3,920.52 3,919.88 3,919.65 3,920.38 3,921.49 3,922.62 TVDSS (usft) 3,813.11 3,818.84 3,826.18 3,834.75 3,843.63 3,851.42 3,857.47 3,861.87 3,865.27 3,867.99 3,871.23 3,873.18 3,871.64 3,868.02 3,864.19 3,860.23 3,856.91 3,855.00 3,853.94 3,852.26 3,850.13 3,848.30 3,847.20 3,846.56 3,846.03 3,845.39 3,844.31 3,843.93 3,845.74 3,849.40 3,853.83 3,857.64 3,860.72 3,862.18 3,861.75 3,861.11 3,860.88 3,861.61 3,862.72 3,863.85 Halliburton Definitive Survey Report +NI -S (usft) -1,870.04 -1,929.49 -1,986.80 -2,039.52 -2,090.81 -2,141.29 -2,195.39 -2,248.95 -2,304.70 -2,358.53 -2,410.86 -2,462.88 -2,516.88 -2,568.70 -2,619.82 -2,670.85 -2,722.71 -2,774.56 -2,827.34 -2,882.32 -2,940.00 -3,000.72 -3,061.51 3,119.57 -3,173.48 -3,225.09 -3,276.18 -3,329.20 -3,384.10 -3,438.86 -3,493.17 -3,547.35 -3,603.31 -3,660.39 -3,718.74 -3,776.05 -3,833.25 -3,888.24 -3,939.67 -3,995.73 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU NI -14 MPU M-14 Actual RKB @ 58.77usft MPU M-14 Actual RKB @ 58.77usft True Minimum Curvature NORTH US + CANADA Map Map Vertical +EI -W Northing Easting DLS Section (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 1,694.87 6,025,903.56 535,607.01 2.47 2,460.28 2_MWD+IFR2+MS+Sag(2) 1,767.17 6,025,844.44 535,679.57 1.41 2,553.60 2_MWD+IFR2+MS+Sag(2) 1,843.08 6,025,787.49 535,755.73 3.97 2,648.64 2_MWD+IFR2+MS+Sa9(2) 1,922.65 6,025,735.14 535,835.53 3.56 2,744.07 2_MWD+IFR2+MS+Sag (2) 2,005.32 6,025,684.23 535,918.43 0.07 2,841.21 2_MWD+IFR2+MS+Sag (2) 2,084.40 6,025,634.12 535,997.74 1.82 2,934.95 2_MWD+IFR2+MS+Sag (2) 2,163.96 6,025,580.38 536,077.53 2.42 3,031.16 2_MWD+IFR2+MS+Sag(2) 2,240.05 6,025,527.18 536,153.86 0.40 3,124.20 2_MWD+IFR2+MS+Sag (2) 2,320.35 6,025,471.80 536,234.40 1.31 3,221.96 2_MWD+IFR2+MS+Sag (2) 2,399.55 6,025,418.34 536,313.84 0.54 3,317.71 2_MWD+IFR2+MS+Sag (2) 2,478.32 6,025,366.37 536,392.84 0.91 3,412.26 2_MWD+IFR2+MS+Sag (2) 2,556.17 6,025,314.71 536,470.92 2.35 3,505.87 2_MWD+IFR2+MS+Sag(2) 2,636.45 6,025,261.08 536,551.43 2.47 3,602.60 2 MWD+IFR2+MS+Sag(2) 2,716.33 6,025,209.63 536,631.54 1.29 3,697.77 2_MWD+IFR2+MS+Sag(2) 2,796.98 6,025,158.89 536,712.42 0.01 3,793.15 2_MWD+IFR2+MS+Sag(2) 2,876.74 6,025,108.22 536,792.40 0.57 3,887.76 2_MWD+IFR2+MS+Sag(2) 2,956.93 6,025,056.73 536,872.82 1.05 3,983.20 2_MWD+IFR2+MS+Sag(2) 3,036.57 6,025,005.26 536,952.69 0.78 4,078.18 2_MWD+IFR2+MS+Sag(2) 3,116.31 6,024,952.85 537,032.66 0.70 4,173.78 2_MWD+IFR2+MS+Sag(2) 3,194.63 6,024,898.23 537,111.22 2.93 4,269.47 2_MWD+IFR2+MS+Sag(2) 3,270.12 6,024,840.90 537,186.97 2.23 4,364.39 2_MWD+IFR2+MS+Sag (2) 3,344.59 6,024,780.52 537,261.71 1.67 4,460.21 2_MWD+IFR2+MS+Sag(2) 3,417.29 6,024,720.08 537,334.67 1.12 4,554.62 2 MWD+IFR2+MS+Sag(2) 3,491.37 6,024,662.35 537,409.01 3.69 4,648.60 2_MWD+IFR2+MS+Sag(2) 3,570.05 6,024,608.81 537,487.93 4.14 4,743.97 2_MWD+IFR2+MS+Sag(2) 3,650.29 6,024,557.57 537,568.40 0.97 4,839.31 2_MWD+IFR2+MS+Sag(2) 3,727.78 6,024,506.84 537,646.11 0.84 4,932.09 2_MWD+IFR2+MS+Sag (2) 3,807.09 6,024,454.18 537,725.65 0.71 5,027.47 2_MWD+IFR2+MS+Sag (2) 3,887.47 6,024,399.66 537,806.27 2.30 5,124.80 2_MWD+IFR2+MS+Sag(2) 3,965.00 6,024,345.26 537,884.04 0.79 5,219.72 2_MWD+IFR2+MS+Sag(2) 4,042.48 6,024,291.30 537,961.76 1.26 5,314.34 2_MWD+IFR2+MS+Sag(2) 4,120.05 6,024,237.49 538,039.57 1.65 5,408.95 2_MWD+IFR2+MS+Sag(2) 4,198.09 6,024,181.89 538,117.86 0.71 5,504.98 2_MWD+IFR2+MS+Sag(2) 4,274.33 6,024,125.16 538,194.35 3.04 5,600.17 2_MWD+IFR2+MS+Sag (2) 4,350.16 6,024,067.17 538,270.44 0.28 5,695.75 2 MWD+IFR2+MS+Sag (2) 4,425.76 6,024,010.21 538,346.29 0.64 5,790.54 2_MWD+IFR2+MS+Sag (2) 4,501.96 6,023,953.36 538,422.74 0.79 5,885.77 2_MWD+IFR2+MS+Sag(2) 4,577.06 6,023,898.71 538,498.09 1.57 5,978.83 2_MWD+IFR2+MS+Sag (2) 4,652.11 6,023,847.64 538,573.36 2.40 6,069.80 2_MWD+IFR2+MS+Sag(2) 4,737.31 6,023,791.97 538,658.80 0.19 6,171.75 2_MWD+IFR2+MS+Sag (2) 4222019 2:34.52PM Page 4 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 Survey MD Inc Azi TVD (usft) V) (1) (usft) 8,768.80 89.39 123.83 3,923.58 8,866.68 90.32 124.11 3,923.82 8,959.52 90.26 9,053.11 89.58 9,149.17 89.02 9,247.06 92.98 9,342.32 93.22 9,436.26 93.04 9,531.88 93.35 9,627.21 91.19 9,722.01 90.39 9,817.63 89.71 9,913.09 90.20 10,007.98 90.32 10,103.61 90.63 10,198.54 90.01 10,293.90 88.90 10,389.05 90.01 10,485.42 89.52 10,580.44 89.70 10,675.70 90.14 10,770.84 90.13 10,866.10 88.10 10,962.02 89.02 11,056.77 86.74 11,151.21 86.24 11,247.00 85.87 11,342.72 88.47 11,437.11 90.39 11,532.77 90.75 11,628.07 89.34 11,723.20 89.64 11,818.29 92.30 11,913.87 90.08 12,007.66 89.09 12,103.77 88.84 12,199.46 87.85 12,294.46 88.04 12,390.33 89.03 12,485.90 91.99 123.73 124.62 125.92 126.06 125.15 125.11 124.91 124.41 123.59 123.66 124.33 124.08 125.49 125.65 124.25 124.70 124.97 123.39 122.94 122.02 122.67 126.27 125.25 125.22 126.98 128.72 128.36 126.43 122.16 118.70 121.62 122.53 122.88 124.94 125.18 125.19 126.38 126.86 3,923.36 3,923.49 3,924.66 3,922.95 3,917.80 3,912.67 3,907.34 3,903.57 3,902.26 3,902.17 3,902.25 3,901.82 3,901.03 3,900.50 3,901.40 3,902.31 3,902.70 3.903.35 3,903.48 3,903.26 3,904.73 3,907.14 3,910.65 3,916.43 3,923.02 3,927.75 3,928.68 3,927.73 3,927.66 3,928.50 3,926.89 3,924.91 3,925.59 3,927.33 3,930.09 3,933.50 3,935.95 3,935.10 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map TVDSS +N/ -S +E/ -W Northing (usft) (usft) (usft) (ft) 3,864.81 .4,048.57 4,816.85 6,023,739.50 3,865.05 -4,103.26 4,898.03 6,023,685.19 3,864.59 -4,155.06 4,975.06 6,023,633.74 3,864.72 -4,207.63 5,052.49 6,023,581.52 3,865.89 4,263.10 5,130.91 6,023,526.43 3,864.18 -4,320.60 5,210.09 6,023,469.29 3,859.03 4,375.98 5,287.43 6,023,414.27 3,853.90 -4,429.96 5,364.14 6,023,360.65 3,848.57 -4,484.73 5,442.34 6,023,306.24 3,844.80 -0,538.90 5,520.68 6,023,252.43 3,843.49 -4,591.90 5,599.27 6,023,199.79 3,843.40 -4,644.85 5,678.89 6,023,147.21 3,843.48 4,698.23 5,758.03 6,023,094.20 3,843.05 4.751.57 5,836.51 6,023,041.22 3,842.26 4,806.12 5,915.04 6,022,987.04 3,841.73 4,861.34 5,992.26 6,022,932.17 3,842.63 4,915.96 6,070.41 6,022,877.91 3,843.54 4,969.82 6,148.85 6,022,824.42 3,843.93 -5,024.87 6,227.95 6,022,769.74 3,844.58 -5,078.25 6,306.55 6,022,716.72 3,844.71 -5,130.36 6,386.29 6,022,664.98 3,844.49 -5,181.45 6,466.55 6,022,614.26 3,845.96 -5,232.40 6,547.01 6,022,563.68 3,848.37 -5,286.67 6,626.05 6,022,509.78 3,851.88 -5,342.00 6,702.88 6,022,454.81 3,857.66 -5,396.38 6,779.87 6,022,400.78 3,864.25 -5,452.68 6,857.09 6,022,344.84 3,868.98 -5,511.34 6,932.57 6,022,286.53 3,869.91 -5,570.14 7,006.39 6,022,228.07 3,868.96 -5,628.23 7,082.38 6,022,170.34 3,868.89 -5,681.92 7,161.09 6,022,117.02 3,869.73 -5,730.09 7,243.10 6,022,069.22 3,868.12 -5,777.85 7,325.29 6,022,021.85 3,866.14 -5,828.59 7,406.26 6,021,971.48 3,866.82 -5,879.26 7,485.17 6,021,921.17 3,868.56 -5,932.87 7,564.92 6,021,867.93 3,871.32 -5,987.81 7,643.21 6,021,813.35 3,874.73 -6,042.52 7,720.81 6,021,759.01 3,877.18 -6,098.56 7,798.55 6,021,703.33 3,876.33 -6,155.56 7,875.24 6,021,646.68 Well MPU M-14 MPU M-14 Actual RKB @ 58.77usft MPU M-14 Actual RKB @ 58.77usft True Minimum Curvature NORTH US + CANADA Map Easting DLS (ft) (°1100') 538,738.58 0.50 538,819.99 0.99 538,897.26 0.41 538,974.92 1.20 539,053.58. 1.47 539,133.02 4.05 539,210.60 0.99 539,287.55 0.20 539,365.98 0.39 539,444.57 2.33 539,523.39 1.21 539,603.24 0.71 539,682.62 539,761.33 539,840.11 539,917.56 539,995.96 540,074.63 540,153.97 540,232.81 540,312.78 540,393.26 540,473.95 540,553.23 540,630.30 540,707.53 540,784.99 540,860.73 540,934.81 541,011.06 541,090.01 541,172.23 541,254.63 541,335.82 541,414.96 541,494.94 541,573.47 541,651.31 541,729.30 541,806.24 0.87 0.29 1.51 0.67 1.87 1.26 0.58 1.67 0.66 0.97 2.24 3.87 2.64 0.53 1.87 3.27 2.07 2.05 4.72 3.65 4.15 2.51 1.12 2.16 1.06 0.20 1.61 3.14 Vertical Section (ft) Survey Tool Name 6,267.22 2_MWD+IFR2+MS+Sag(2) 6,365.08 2_MWD+IFR2+MS+Sag(2) 6,457.90 2_MWD+IFR2+MS+Sag (2) 6,551.48 2_MWD+IFR2+MS+Sag (2) 6,647.53 2_MWD+IFR2+MS+Sag(2) 6,745.37 2_MWD+IFR2+MS+Sag (2) 6,840.49 2_MWD+IFR2+MS+Sag (2) 6,934.28 2_MWD+IFR2+MS+Sag (2) 7,029.76 2_MWD+IFR2+MS+Sag (2) 7,125.00 2_MWD+IFR2+MS+Sag(2) 7,219.78 2_MWD+IFR2+MS+Sag (2) 7,315.38 2_MWD+IFR2+MS+Sag(2) 7,410.82 2_MWD+IFR2+MS+Sag (2) 7,505.70 2_MWD+IFR2+MS+Sag(2) 7,601.33 2_MWD+IFR2+MS+Sag(2) 7,696.25 2_MWD+IFR2+MS+Sag (2) 7,791.60 2_MWD+IFR2+MS+Sag (2) 7,886.74 2 MWD+IFR2+MS+Sag(2) 7,983.11 2_MWD+IFR2+MS+Sag (2) 8,078.12 2_MWD+IFR2+MS+Sag(2) 8,173.33 2_MWD+IFR2+MS+Sag (2) 8,268.38 2_MWD+IFR2+MS+Sag (2) 8,363.53 2_MWD+IFR2+MS+Sag(2) 8,459.40 2_MWD+IFR2+MS+Sag(2) 8,554.07 2_MWD+IFR2+MS+Sag(2) 8,648.33 2_MWD+IFR2+MS+Sag(2) 8,743.87 2_MWD+IFR2+MS+Sag (2) 8,839.33 2_MWD+IFR2+MS+Sag(2) 8,933.53 2_MWD+IFR2+MS+Sag(2) 9,029.09 2_MWD+IFR2+MS+Sag(2) 9,124.36 2_MWD+IFR2+MS+Sag (2) 9,219.18 2_MWD+IFR2+MS+Sag (2) 9,313.91 2_MWD+IFR2+MS+Sag (2) 9,409.34 2_MWD+IFR2+MS+Sag (2) 9,503.06 2_MWD+IFR2+MS+Sag (2) 9,599.13 2_MWD+IFR2+MS+Sag(2) 9,694.78 2_MWD+IFR2+MS+Sag(2) 9,789.72 2_MWD+IFR2+MS+Sag(2) 9,885.54 2_MWD+IFR2+MS+Sag(2) 9,981.05 2_MWD+IFR2+MS+Sag (2) 422/1019 2:34:52PM Page 5 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 Survey MD Inc Azi TVD TVDSS (usft) (°) (°) (usft) (usft) 12,581.33 91.68 126.32 3,932.04 3,873.27 12,675.14 91.00 125.86 3,929.85 3,871.08 12,771.92 90.14 126.84 3,928.88 3,870.11 12,866.79 89.64 128.32 3,929.07 3,870.30 12,961.05 89.33 127.56 3,929.91 3,871.14 13,056.39 88.96 124.06 3,931.34 3,872.57 13,151.08 88.28 123.75 3,933.62 3,874.85 13,245.66 86.31 123.23 3,938.08 3,879.31 13,336.43 86.62 123.94 3,943.68 3,884.91 13,433.84 88.41 124.20 3,947.90 3,889.13 13,528.23 87.73 124.81 3,951.08 3,892.31 13,624.18 89.21 125.67 3,953.64 3,894.87 13,718.99 91.50 125.43 3,953.05 13,813.97 90.56 125.07 3,951.35 13,908.62 89.46 125.09 3,951.33 14,003.81 86.68 124.50 3,954.54 14,098.58 85.63 124.15 3,960.89 14,192.41 85.69 14,287.47 86.06 14,383.10 86.49 14,476.89 85.74 14,573.50 85.68 14,669.74 88.04 14,764.81 89.34 14,860.40 87.72 14,954.06 87.11 15,050.21 87.24 15,144.57 86.61 15,240.04 86.62 15,334.98 89.89 15,429.71 93.85 15,525.29 97.33 15,619.98 95.21 15,714.50 92.36 15,808.99 88.84 15,904.47 91.50 15,999.22 95.28 16,094.94 96.01 16,189.48 92.18 16,282.91 89.64 125.71 126.04 126.07 126.21 125.63 124.15 123.49 123.73 125.33 126.57 126.54 127.21 127.55 126.64 125.34 124.60 123.28 122.83 124.31 125.45 124.97 124.65 124.44 3,967.99 3,974.83 3,981.04 3,987.40 3,994.62 3,999.89 4,002.07 4,004.52 4,008.74 4,013.48 4,018.55 4,024.18 4,027.07 4,023.98 4,014.67 4,004.33 3,998.09 3,997.10 3,996.82 3,991.22 3,981.80 3,975.05 3,973.57 3,894.28 3,892.58 3,892.56 3,895.77 3,902.12 3,909.22 3,916.06 3,922.27 3,928.63 3,935.85 3,941.12 3,943.30 3,945.75 3,949.97 3,954.71 3,959.78 3,965.41 3,968.30 3,965.21 3,955.90 3,945.56 3,939.32 3,938.33 3,938.05 3,932.45 3,923.03 3,916.28 3,914.80 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map +N/ -S +EI -W Northing (usft) (usft) (ft) -6,212.41 7,951.83 6,021,590.18 -6,267.65 8,027.61 6,021,535.29 -6,325.01 8,105.55 6,021,478.29 -6,382.87 8,180.74 6,021,420.79 -6,440.82 8,255.07 6,021,363.18 -6,496.59 8,332.37 6,021,307.77 -6,549.39 8,410.93 6,021,255.33 -6,601.52 8,489.72 6,021,203.57 -6,651.64 8,565.19 6,021,153.80 -6706.15 8,645.80 6,021,099.66 -6,759.59 8,723.54 6,021,046.58 -6,814.93 8,801.88 6,020,991.60 -6,870.05 8,879.01 6,020,936.84 -6,924.86 8,956.56 6,020,882.39 -6,979.26 9,034.02 6,020,828.35 -7,033.54 9,112.13 6,020,774.43 -7,086.86 9,190.22 6,020,721.48 -7,140.43 9,266.93 6,020,668.26 -7,195.99 9,343.75 6,020,613.06 -7,252.16 9,420.90 6,020,557.25 -7,307.34 9,496.47 6,020,502.41 -7,363.86 9,574.49 6,020,446.26 -7,418.82 9,653.30 6,020,391.66 -7,471.72 9,732.27 6,020,339.13 -7,524.61 9,811.85 6,020,286.60 -7,577.65 9,888.92 6,020,233.93 -7,634.02 9,966.66 6,020,177.91 -7,690.14 10,042.35 6,020,122.14 -7,747.33 10,118.59 6,020,065.31 -7,804.94 10,193.99 6,020,008.05 -7,862.03 10,269.49 6,019,951.31 -7,917.92 10,346.44 6,019,895.77 -7,971.86 10,423.57 6,019,842.19 -8,024.51 10,501.80 6,019,789.90 -8,076.04 10,580.98 6,019,738.74 -8,128.83 10,660.53 6,019,686.32 -8,182.91 10,738.11 6,019,632.60 -8,237.83 10,815.93 6,019,578.04 -8,291.65 10,893.34 6,019,524.58 -8,344.62 10,970.29 6,019,471.97 Well MPU M-14 MPU M-14 Actual RKB @ 58.77usft MPU M-14 Actual RKB @ 58.77usfl True Minimum Curvature NORTH US+CANADA Map Vertical Easting DLS Section (ft) (°Ifoo,) (ft) Survey Tool Name 541,883.08 0.65 10,076.40 2_MWD+IFR2+MS+Sag (2) 541,959.11 0.88 10,170.16 2_MWD+IFR2+MS+Sag (2) 542,037.30 1.35 10,266.90 2_MWD+IFR2+MS+Sag(2) 542,112.74 1.65 10,361.67 2_MWD+IFR2+MS+Sag (2) 542,187.33 0.87 10,455.79 2_MWD+IFR2+MS+Sag(2) 542,264.87 3.69 10,551.10 2_MWD+IFR2+MS+Sag(2) 542,343.67 0.79 10,645.74 2_MWD+IFR2+MS+Sag(2) 542,422.69 2.15 10,740.18 2_MWD+IFR2+MS+Sag(2) 542,498.38 0.85 10,830.76 2_MWD+IFR2+MS+Sag(2) 542,579.23 1.86 10,928.06 2_MWD+IFR2+MS+Sag (2) 542,657.20 0.97 11,022.39 2_MWD+IFR2+MS+Sag (2) 542,735.78 1.78 11,118.30 2_MWD+IFR2+MS+Sag(2) 542,813.16 2.43 11,213.10 2_MWD+IFR2+MS+Sag (2) 542,890.95 1.06 11,308.06 2_MWD+IFR2+MS+Sag (2) 542,968.64 1.16 11,402.71 2_MWD+IFR2+MS+Sag (2) 543,047.00 2.99 11,497.83 2_MWD+IFR2+MS+Sag (2) 543,125.32 1.17 11,592.38 2 MWD+IFR2+MS+Sag (2) 543,202.26 1.66 11,685.94 2_MWD+IFR2+MS+Sag (2) 543,279.34 0.52 11,780.74 2_MWD+IFR2+MS+Sag (2) 543,356.73 0.45 11,876.15 2_MWD+IFR2+MS+Sag (2) 543,432.54 0.81 11,969.71 2_MWD+IFR2+MS+Sag (2) 543,510.81 0.60 12,066.03 2_MWD+IFR2+MS+Sag (2) 543,589.87 2.89 12,162.12 2 MWD+IFR2+MS+Sag (2) 543,669.06 1.53 12,257.14 2_MWD+IFR2+MS+Sag (2) 543,748.88 1.71 12,352.67 2_MWD+IFR2+MS+Sag (2) 543,826.19 1.83 12,446.23 2_MWD+IFR2+MS+Sag (2) 543,904.18 1.30 12,542.25 2_MWD+IFR2+MS+Sag (2) 543,980.11 0.67 12,636.43 2_MWD+IFR2+MS+Sag (2) 544,056.60 0.70 12,731.68 2_MWD+IFR2+MS+Sag (2) 544,132.25 3.46 12,826.48 2_MWD+IFR2+MS+Sag (2) 544,208.01 4.29 12,921.07 2_MWD+IFR2+MS+Sag (2) 544,285.21 3.88 13,016.16 2_MWD+IFR2+MS+Sag (2) 544,362.57 2.37 13,110.28 2_MWD+IFR2+MS+Sag (2) 544,441.04 3.32 13,204.57 2 MWD+IFR2+MS+Sag(2) 544,520.44 3.76 13,298.98 2_MWD+IFR2+MS+Sag (2) 544,600.22 3.19 13,394.43 2_MWD+IFR2+MS+Sag (2) 544,678.04 4.17 13,488.99 2_MWD+IFR2+MS+Sag (2) 544,756.11 0.91 13,584.25 2_MWD+IFR2+MS+Sag (2) 544,833.75 4.07 13,678.53 2_MWD+IFR2+MS+Sag (2) 544,910.93 2.73 13,771.93 2_MWD+IFR2+MS+Sag (2) 4/22/2019 2:34:52PM Page 6 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 Survey MD Inc Azi TVD TVDSS (usft) (°) (') (usft) (usft) 16,379.73 88.59 125.16 3,975.07 3,916.30 16,475.41 87.92 125.41 3,977.98 3,919.21 16,570.01 88.10 125.66 3,981.26 3,922.49 16,664.67 88.96 125.57 3,983.69 3,924.92 16,760.36 92.12 125.01 3,982.79 3,924.02 16,855.41 93.10 124.67 3,978.46 3,919.69 16,952.19 91.56 124.39 3,974.53 3,915.76 17,045.18 91.50 124.54 3,972.04 3,913.27 17,069.48 90.94 124.43 3,971.53 3,912.76 17,139.00 90.94 124.43 3,970.39 3,911.62 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map +Nl-S +E/ -W Northing (usft) (usft) (ft) -8,399.87 11,049.78 6,019,417.09 -8,455.11 11,127.84 6,019,362.21 -8,510.06 11,204.78 6,019,307.61 -8,565.16 11,281.71 6,019,252.87 -8,620.44 11,359.80 6,019,197.96 -8,674.68 11,437.73 6,019,144.07 -8,729.49 11,517.39 6,019,089.63 -8,782.10 11,594.03 6,019,037.38 -8,795.85 11,614.06 6,019,023.72 -8,835.15 11,671.39 6,018,984.68 Well MPU M-14 MPU M-14 Actual RKB @ 58.77usft MPU M-14 Actual RKB @ 58.77usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (-/100-) (ft) Survey Tool Name 544,990.66 1.31 13,868.74 2_MWD+IFR2+MS+Sag(2) 545,068.97 0.75 13,964.37 2_MWO+IFR2+MS+Sag(2) 545,146.15 0.33 14,058.91 2_MWD+IFR2+MS+Sag(2) 545,223.32 0.91 14,153.53 2_MWD+IFR2+MS+Sag(2) 545,301.65 3.35 14,249.20 2_MWD+IFR2+MS+Sag(2) 545,379.82 1.09 14,344.15 2_MWD+IFR2+MS+Sag(2) 545,459.73 1.62 14,440.85 2_MWD+IFR2+MS+Sag (2) 545,536.60 0.17 14,533.80 2_MWD+IFR2+MS+Sag (2) 545,556.68 2.35 14,558.10 2_MWD+IFR2+MS+Sag (2) 545,614.19 0.00 14,627.60 PROJECTEDto TD Checked By: Chelsea Wright w, ".,^�^•^ Approved By: Mitch Laird Date: 04-22-2019 4222019 2.34:52PM Page 7 COMPASS 5000.15 Build 91 Lease 8 Well No. County HJlcorp E.My Company CASING & CEMENTING REPORT MP M-14 Date Run 10 -Apr -19 State Alaska Sup, Yessak/Demoki CASING RECORD wdare � TD 4,86&00 Shoe Depth: 41855.00 No. Jo. Delivered 146 No, Jts. Run PBTD: 122 No. Jts. Returned 24 Dag Wt. On Hack: 120,000 Type Float Collar Innovex No. Hm to Run: Casing (Or Liner) Detail Dag W. On Slips: 80,000 Type of Shoe: Innovex Serino Depths Jts. Component Size W4. Grade THD Make Length Bottom Tap 1 Shoe 103/4 50.0 Floats Held TXP BTC -SR Innovex 1.63 4,855.00 4,853.37 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 79.54 4,853.37 4,773.83 1 Float Collar 103/4 50.0 TXP BTC -SR Innovex 1.30 4,773.83 4,772.53 1 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 39.10 4,772.53 4,733.43 1 Baffle Adapter 103/4 50.0 TXP BTC -5R HES 1.47 4,733.43 4,731.96 62 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,438.14 4,731.96 2,293.82 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 18.57 2,293.82 2275.25 1 ES Cementer 103/4 TXP BTC -SR HES 3.13 2,275.25 2,272.1 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 17.60 2,272.12 2,254.52 56 Casing 95/8 40.0 L-80 T%P BTC -5R Tenaris 2,186.62 2,254.52 67.90 1 Casing Cut Joint 95/8 40.0 L-80 TXPBTC-SR Tubular Sol. 38.01 67.90 29.89 Dag Wt. On Hack: 120,000 Type Float Collar Innovex No. Hm to Run: 15 Dag W. On Slips: 80,000 Type of Shoe: Innovex Casing Crew: Doyon Rotate Csg X Yes No Recip Gag X Yes_ No 20 Ft. Min. 93 PPG Fluid Description: Spud MW 0 : In Place At. 1222 Liner hanger Into(MakelModel): Liner tap PackeR: _Yes _No Liner hangar test pressure: Calculation / Trace cement to surface Floats Held X Yes _ No Centralizer Placement: 8o each 95/8' x 12-1/4' Expand- hzer cerNalbers and 10 stop rings total ran. 2 centralizers on joint #1 and one each on joints #2 to 25. 1 centralizer on every other joint 1127 to 59. 1 centralizer on every joint #62 to 74. 1 centralizer on the Pup joints above and below the ES cementer. 1 centralizer on every other joint #76 to 118. CEMENTING REPORT Shoe Q 4855 FC 4,722.53 Top of IJner ush (Spacer) Clean Spacer 111 Density (ppg) 10 Volume pumped (BBLs) I Slurry Lead Cement Sacks: 331 Yield: lity (ppg) 12 Volume pumped (BBLs) 138.8 Mixing / Pumping Rate (bpm): Tail Cement Sacks: 40) Yield: _ ity (ppg) 15.8 Volume pumped (BBLs) 82.4 Mixing / Pumping Rate (bpm)'. Flush (Spacer) Density (ppg) Rale (bpm): Volume: Spud Mud Density (ppg) 9.3 Rate (bpm): 5 Volume (actual / calculated): 34f ;1): 580 Pump used for disp: Rig Bump Plug? X Yes No Bump press Rotated? X Yes Reciprocated? X Yes _No %Retums during job L returns to surface? X _No Yes _No Spacer retums? X Yes _ No Vol to Surf: 0 : In Place At. 1222 Dale. Vll1 019 Estimated TOC: 2,272 Used To Detemme TOC: Calculation / Trace cement to surface to surface Stage Collar@ 2272.12 Type ES Cementer Closure OK Y 're0ush (Spacer) ype: Clean Spacer III Density (ppg) 10 Volume pumped (BBLs) ead Slurry ype: Perm L Sacks: 439 Yield'. tensity (ppg) 10.7 Volume pumped! (BBLs) 344.3 Mixing / Pumping Rate (bpm)'. Premium G Sacks: 270 Yield, _ (ppg) 15.8 Volume pumped (BBLs) 56.2 Mixing / Pumping Rate (bpm): can (Spacer) Density (ppg) Rate (0m): Volume: Spud Mud Density (ppg) 9.1 Rate (bpm): 7.3 Volume (actual / calculated): 171 psi): 583 Pump used for lisp: Rig Bump Plug? X Yes No Bump press gFolated? X No Reciprocated? X No % Returns during job ii _Yes M returns to surface? X Yes _Yes _ No Spacerretums? X Yes _No Vol to Surf: 262.4 nt In Place At: 1:55 Date: 4/122019 Estimated TOC: Id Used To Detemtlne TOC: Returns to surface Post Job Calculations: Calculated Cant Vol @ Ma excess: 295.33 Total Volume end Pumped: 621.7 Cmt returned to surface: 262.4 Calculatetl cement left in wellbore: 359.3 r1H volume r:aln,lar 9x455 r1H vMumB xN,.I KS 52 Aetnal%Washcutl 24 rs DATE: 5/15/2019 De -ea Oudean Hilcorp Alaska, LLC AK_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 Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU E-11. PTD 219-040 CD: HALLIBURTON 29 Apr 2019 FEB 2019 M-14 DGR ABG EWR ADR MD & TVD Please include current contact information if different from above. 21 90 d;0 60832 RECEIVED MAY 11 1019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-14 Permit to Drill Number: 219-040 Sundry Number: 319-243 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www, oogc c. a laska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this l If day of May, 2019. 113DMS 4FOA✓ MAY 1 51019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 70 AAC 25 780 RECEIVE® MAY 10 2019 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ aj-' MsRa, rhofi ll§Mte�(!(" Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Temp Flow Back ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ DevelopmentQ • Stratigraphic ElService ❑ 219-040 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23625-00-00 0 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ MPU M-14 9. Property Designation (Lease Number): 10. Field/Pool(s): I ADL025514, ADLO25515 Milne Point Field I Schrader Bluff Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 17,139' 3,970' 17,134' 3,970' 1,537 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 114' 20" x 34" 80' 80' N/A N/A Surface 4,822' 9-5/8" 4,855' 3,864' 5,750psi 3,090psi Tieback 4,633' 7" 4,664' 3,836' 7,240psi 5.410psi Liner 12,482' 6-5/8" 17,139' 3,970' 6,090psi 3,470psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.3# L-80 / ELIE 8rd 4,710 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" x 3.5" PHL Ret. & BOT SLZXP and N/A 4,537 MD/ 3,803 TVD & 4,657 MD/ 3,834 TVD and N/A 12. Attachments: Proposal Summary Q Wellbore schematic © 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 5/12/2019 OIL WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: AA!!, / o 7 Z61,7 Commission Representative: uas-�--+-I GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing isitrue and the krojeedure approved herein will not be deviated from without prior written approval Authorized Name: Chad Helgeson Contact Name: David Haakinson Authorized Title: Operations Manager lye Contact Email: dhaakinson 0 hi cor .Com as &#9 ARA460PJ Contact Phone: 777-8343 Authorized Signature: Date: 5/10/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: n i+, �t ( 15 (_�/1 G Plug Integrity ❑ BOP Test Mechanical Integrity Test Location Clearance El/✓, n❑ �j /❑/ Other: Ft—,Co ". ', �' F � 0'/C �' d -y S 6 GLS.-cr S s/E a / c • t � ILL S, e. r 1� 2-iJ. Tom•— J�.S(� l ll Post Initial Injection MIT Req'd? Yes ❑ No ❑/ Spacing Exception Required? Yes El No [ Subsequent Form Required: j6 - y�� ;1BDMS '" MAY 15 2019 / tVt•7 APPROVED BY THE COMMISSION Date: j tl 1 Approved by: COMMISSIONER Submit Form and F rm 10-403 Revised 4/2017 Approved applicatio f oMt Are of approval. W Attachments m Du licate U Hilo J, Alaska, LL Temporary Flow Well: MPU M-14 Date:05/9/19 Well Name: MPU M-14 API Number: 50-029-23625-00 Current Status: Shut in Producer Pad: M -Pad Estimated Start Date: May 12, 2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-040 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: N/A Job Type: Temporary Flow Current Bottom Hole Pressure: 1,927 psi @ 3,901' TVD Downhole Gauge (4/29/19) 19.5 PPG EMW Maximum Expected BHP: 1,927 psi @ 3,901' TVD Stable SBHP @ Res. Depth 19.5 PPG EMW MPSP: 1,537 psi (0.1psi/ft gradient to surface) Brief Well Summary: MPU M-14 was drilled and completed as a Schrader Bluff OA production well. The well was completed with a jet pump artificial lift mechanism in early May 2019. The fluid flow path after commissioning the Moose Pad facility, is to comingle with F&L fluids at Moose Pad Facility, separate out and dispose of the water before shipping the combined oil/gas to the Milne Central Plant. As time has progressed the Moose Pad Facility commissioning date has slipped. At present time, M -pad producers are in need of power fluid supply from high-pressure pump trucks and water trucked from the main facility since power -fluid water cannot be fully separated at this time. Notes Regarding Wellbore Condition: • The 3-1/2"x7" casing passed an MIT -IA to 3,600psi on 4/29/19 (during the original completion). • The 7"x9-5/8" casing passed an MIT -IA to 1,200psi on 4/28/19 (during the original completion). • Producer M -14's SVS system will be in service at the time the well is brought online. • M-14 production will flow through its designed piping flow path. o The temporary 2" hardline jumpers will be removed and M -pad producers will flow through the M -Pad separator. o M-10 and M-12 production will also flow-through their normal flow path. Objective: Produce the well under temporary flow operations until Moose Pad Facility is fully operational and 'normal' power -fluid operation of the well is possible. Temporary Flow System Description: Temporary PiOng Facility tie-in optimization has reduced the use of temporary hardline down to 2" hardline sections to the individual producer's power fluid tie-in. These installed sections will be monitored for leaks during operation. 1. 2" hardline from the pump truck to the power fluid line upstream of the check valve for M-14 (highlighted on sheet #1 or Drawing # PI -MOM -10005 of the P&ID's attached). 2. 2" Production hardline will be removed and M-10, M-12, and M-14 will all flow through their normal designed flow path. Production will flow through the M -pad separator; however, no separation will occur and all fluids will be passed through downstream to the main MPU facility. The change is highlighted on Sheet #5 or Drawing # PI -MOM -00007-002. R llila¢p Alaska, LU Temporary Flow Well: MPU M-14 Date: 05/9/19 Well Testing We will obtain a well test on these wells by month end. We are currently working the details on this with options including the following. - Primary Option: Have Moose Pad Facility commissioned and able to use the pad test separator. If the facility is not looking to be completed, we will contact ahead of time for discussion on approved test method. - Third -party portable test separator. Attachments: 1. As -built Schematic 2. P&ID / Drawings H crorn Alaska. LLC Orig. KB Elev.: 593/ GL Elev.: 25 TD = 17,1391 (MD) / TD = 3,97(Y(TVD) PBTD=17,]34' (MD) / TD = 3,97U(TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-14 Last Completed: 4/30/19 PTD: 219-040 Tree Cameron 3 1/8" SM 12-1/4" 1st stage FMC 11" 5M TC-lA w/11" x 31/2" TC -II Top and Bottom Tubing Wellhead Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4" 1st stage 331 sx 12.0# Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 439 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift I Top Btm BPF 20"x34" Conductor (Insulated) 215.5 /A-53/Weld N/A Surface 40' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 4,855' 0.0758 7" Tieback 26/L-80/TXP 6.151"Surface 4,464' 4,664' 0.0383 6-5/8" Liner (Pre -Drilled) 20/L-80/HydriI 563 5.924" 4,657' 17,139' 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 1 2.867" Surf 1 4,710' 1 0.0087 WELL INCLINATION DETAIL KOP @ 380' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hole Angle = 75.00 deg. @ XN profile Max Hole Angle = 80.00 deg. @ Tubing tail Max Hole Angle = 93.4 deg. @ 9,532' MD JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 29' Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 2,289' 3.5" Patco GLM w/ 1.5" SOGLV set (2,000 psi shear) 2.867" 3 4,443' 3.5" SLB Gauge Mandrel w/Y."Wire (Discharge Gauge) 2.875" 4 4,454' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,776' TVD; 69° (Sleeve Closed) 2.813" 5 4,464' 3.5" SLB Gauge Mandrel wl Y.." Wire (Intake Gauge) 2.875" 6 4,484' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 4,537' 7" x 3.5" PHIL Retrievable Packer (50k Shear Release) 2.885" 8 4,594' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" RHC -P set 2.750" 9 4,709' 3.5" WLEG (Btm @ 4,710') 2.867" Lower Completion 10 4,657' BOT SLZXP Liner Top Packer w/8D Slips 7" x 9-5/8" (11.24' Tieback Sleeve) 6.170" 11 4,664' 7" Tieback Assy. (8.25" OD No -Go @ 4,654) 6.090" 12 4,679' 7" H dril 563 L-80 x 6-5/8" HydriI 563 L-80 XO 5.924" 13 5,325' 6-5/8" Pre -Drilled Liner (72 holes per ft) w/ 1 straight -vane centralizer perjt Blank liner from 15,248'-15,608' & 15,771'-16,125' 5.924 14 17,134' WIV (Wellbore Isolation Valve) 1.000" 15 17,139' Shoe; Btm @ 17,139') - GENERAL WELL INFO API: 50-029-23625-00-00 Drilled and Completed by Doyon 14-4/30/2019 Revised By: STP 5/03/2019 .._ D T n ml uwl wt nIn gI a>w ssa xn m xwo ar IM1x mm XR >m9E° mv°x4 Ire 94°66 NE gWFL KW Vt atAM 9IIIA IX E,AM R31 NM R! 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PMp1 CL KAOfn A M )EST HFA R A n]w ]RxA ltc w m1. vcAA.rr rSn [rr.fO.bT we o�.or:rw ar rn: t wn]�u�rvrw ttuE: norA PNY I'P W" ca wv -TmsmP PI-uaH-aoaov-Dol. _. a - - w-Yq]-Oq'm-WI .-.. '';P-� 1 --MNli�l M -n -4 - Nti�4MMY - %-kW-CWTI-N IFMiK-[ PI---- ---- Altl-mvxirti li.0i .'_ r AW AS RA I _ L q Uve IRYnw, �'J eoxv wm 91e j i Tf P-NIMI-UWY'<-Po w u®vleuw 1 _,F � 1 _ - �9 I 1 1 I I N-Wf-W00]- ------ _ ___ _ J2 ry PI-KKN-W]12 rvm, v✓mm [w rml rtNY� ;_W w ,. I eP�i dla I I fwRU I I i. - An'6Autli lYKKP-WM-M131-W1 10.V 0.f1 tA MASTER COPY 01232018 8:57:57 AM Sy:Kathle n5chsnz y oa HilcoxpwsELa pm LLC Z Pm_ umn. m PRWUCfIa! FAaUW �\ wnAn• PI%Hs ANp wsmuualrAnaR sIA[xw Xnsna FRC6UCMN HF.IAER A .WD rLST HFAOER A mw aarR uc i�pinv w 14: c — av ist6sls �rmP-xuu-ooOR>-tlax w I-� -_. _ wnR Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, May 10, 2019 12:25 PM To: David Haakinson Cc: Tom Fouts; Taylor Wellman; Roby, David S (DOA); Regg, James B (DOA) Subject: Re: Approval Request for MPU M-14 (PTD 219-040) Start-up David, You have verbal approval to produce M-14 with temporary piping & flow back configuration as proposed in your sundry application. Notify Inspectors to witness testing of SVS system as required under 20 AAC 25. 265. Regards, Guy Schwartz AOGCC Sent from myiPhone On May 10, 2019, at 11:07 AM, David Haakinson <dhaakinson@hilcorp.com> wrote: Mr. Schwartz, Thank you again for your time this week with discussions regarding our M -Pad production challenges. We are seeking approval to start flow -back operations on M-14 (PTD 219-040) in coordination with the existing M-10 and M-12 flow -back operations. We expect that the producer (M-14) will be ready for production on Sunday, May 12th and would appreciate verbal approval for a weekend start-up. Our sundry application is attached and the official printed documentation will be mailed directly. Our operations crews and engineering worked diligently up through this morning to improve and optimize our flow -back operations, resulting in the ability to produce M-14. Regarding our improvements: SVS System & Testing M-14 will have its SVS systems placed into service and comply with the regulations set forth in 20AAC25.265. These systems will be tested within the standard timeframe of the well start- up. Notifications to Inspectors will be provided as per normal protocol for witnessing tests. Removal of temporary production piping The temporary production piping (two 2" hardline sections) will be removed and all three M -pad producer (M-10, M-12, and M-14) will flow through their originally designed production flow path through the M -pad facility. The M -pad separator will be a pass-through vessel, sending all fluids through the oil -leg downstream to the main MPU facility (CFP) for processing. Remaining Temporary Operations: Power Fluid Temporary Piping Temporary Y' hardline piping will continue to be rigged up to each indiviaual producer's (M-10, M-12 & M-14) IA, upstream of each producer's check valve and IA SSV. A high-pressure pump truck will remain in the same location to supply water power fluid to each well with hardline rigged up off of a manifold. Well Testing With utilization of the normal production flow -path for the M -pad producers, current plans are to be able to flow production wells into the Moose Pad test separator. If complications arise, a portable test separator will be utilized for monthly testing. David Haakinson Operations Engineer I North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 1 Cell: (307) 660-4999 d haakinsonah i Icorp.com From: Schwartz, Guy L (DOA) (mailto:guy.schwartz@alaska.gov] Sent: Thursday, May 9, 2019 9:51 AM To: Taylor Wellman <twellman@hilcorp.com>; Roby, David S (DOA) <dave.robv@alaska.gov>; Regg, James B (DOA) <lim.regg@alaska.gov> Cc: David Haakinson <dhaakinson@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: (EXTERNAL] RE: MPU M-10 (PTD 218-165) and M-12 (PTD 218-176) Temporary Flow Sundries 319-170 & 319-171 Taylor, You have approval to continue flowback operations on M-30 and M-12 as proposed below for an additional 30 days. Notify inspectors to witness initial SVS system tests and continue to update the commission weekly on Moose Pad operational status. M-14 will require a separate sundry if production is started on this well. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793- 1226) or (Guv.schworfz@alasko.aov(. From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, May 8, 2019 3:33 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Roby, David S (DOA) <dave.robv@alaska.gov>; Regg, James B (DOA) <jim.regg@alaska.gov> Cc: David Haakinson <dhaakinson@hilcorp.com>; Tom Fouts <tfouts@hilcorp.conp Subject: MPU M-10 (PTD 218-165) and M-12 (PTD 218-176) Temporary Flow Sundries 319-170 & 319- 171 Gentlemen, Thank you for taking the time to meet yesterday to discuss the Temporary Flow Sundries (319-170 & 319-171) for Milne Point Wells M-10 (PTD 218-165) & M-12 (PTD 218-176). We would like to extend the Approved Sundry durations for these wells beyond the current 30 days. Moose Pad Facility As an update to the progress of the Moose Pad facilities, we are experiencing difficulties with higher than anticipated backpressure through the de -oiling portion of the processing facility. This additional backpressure increases backpressure back through all wells at F&L pads. To alleviate this we are currently bypassing the Moose Pad facility until the internals to the de -oiler can be machined and re- installed. Barring other issues, this should allow us to begin flowing F&L production back through the facility. SVS System & Testing The wells have had their SVS systems placed into service and comply with the regulations set forth in 20AAC25.265. These systems will be tested within the standard timeframe of the wells being online and swapped over. Notifications to Inspectors will be provided as per normal protocol for witnessing tests. Temporary Piping Dependent upon the duration of the bypass of fluids through the Moose Pad Facility and/or additional production wells being brought online, a better flow path may be determined. If an optimized path is found, the temporary piping configuration may change and applicable P&ID's will be updated. Well Testing Current plans are to be able to flow production wells into the Moose Pad test separator. If this is not achievable, a portable test separator will be utilized for monthly testing. M-14 The intent is to bring this well online utilizing a similar setup as M-10 & M-12. This will be the subject of another Sundry Application. If you have any questions or would like to discuss this please reach out and I will provide anything needed. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com 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 WATERWOLFTM Model DOR-175 e� a 0 3 ovErwi uaiGaN?arfreaal Ship Weight: 9 tons Termination Point Table Size Service Connection 'X Y. T 6" Inlet ANSI 150# RF 90.7/8" 2-7/8" 21-1/2" 6° Water Outlet ANSI 150# RF 77" 2-7/8" 21-1/2" 2" Oily Reject ANSI 150# RF 166-3/8' 23/8" 17-1/8" 1" Slurry Outlet ANSI 150# RF 42" 1-5/8" 15-5/8" 3- Pressure Relief ANSI 150# RF 29-3/4" 2-7/8" 21-1/2' 2° Skid Drain NPT 3000# 17' j 1-1/8' j 4-7/8" 2' Skid Drain NPT3000# 246-1/4' 1-1/8" 4-7/8" 2- Skid Drain NPT 3000# 17" 86-7/8" 4-7/8" 2" Skid Drain NPT 3000# 246-1/4" 86-7/8" 4-7/8" wWW.nov.co n/waterwolf pft@nov.00m '' II (u)f r Configuration Table DOR-175- A B CI Gross Flow Rate (BPD) 18,020 14,510 11,605 Net Treated Water Capacity(BPD) 16,390 13,170 10.530 Oily Reject Flow Rate(BPD) 1,630 1,340 1.073 Power Consumption (kW) 50.4 40.0 32.0 24.9 Ory 2" Ceramic Desanding Cyclones 31 25 20 15 Ory 2" Desanding Blanks 0 6 11 16 Ory 1.5' Deolling Cyclones 43 35 28 22 Ory 1.5" Deolling Blanks 0 8 15 21 `The model DOR-175 can be configured for different flow rates per the configuration table. Optimum water quality is achieved with a configured flow rate that is greater than the maximum instantaneous flow raze of water to be treated. 0 NATIONAL OILWELL VARCO ® 2014 NaUanal Oilwell Varca. All Rlghn Reurved D,1'5RO300EB-MKTM1Pw. 03 WATERWOLF'M Dynamic Oil Recovery System The WaterWolf Dynamic Oil Recovery (DOR) system is a complete water treatment system that recovers oil and removes suspended solids from produced water in a single stage of treatment without the use of chemicals. Effluent water quality from the WaterWoff DOR is equal to or better than the quality produced from most conventional gas flotation systems and it can handle produced water directly from separators and crude treaters with no intermediate oil skimming step. The WaterWolf DOR combines deoiling and desanding hydrocyclones with the non -shearing action of Moyno' ' progressing cavity pumps. Produced water is partially recirculated within the system in a Dynamic Loop which maintains ideal process conditions for both hydrocyclones with optimum efficiency and 100% turndown. The WaterWolf DOR does not rely on upstream separator pressure and will provide consistent performance regardless of variations in flowrate or pressure from the upstream water source. Since solids are removed from the water separately from the oil, the discharged solids are practically oil free, eliminating the oil contaminated, chemical sludge that is produced by the gas flotation process. The recovered oil is also uncontaminated by chemicals or solids and can be returned directly to the separation process, bypassing a dosed drains or slops handling system. WaterWolf DOR models with up to 16,000 BPD capacity per skid can be shipped to location in a standard shipping container or flatbed truck. Higher capacity models can be delivered by non -permit loads to most locations. The WaterWolf DOR offers significant construction cost savings by eliminating pumps, tanks, controls, vapor recovery, gas blanketing, and air emissions permitting. Installation requires a small level site, 3 main process connections and a 480V, 3 phase power supply. Most onshore DOR installations can be completed in a day with a modest work crew and crane truck. Start-up and operation is simple and on-site training for operators can be accomplished in ohmst an hr ..r WaterWolf'" Dynamic Oil Recovery System SPECIFICATIONS -MODEL 0011 175 Pressure Vessels Vessel Design: ASME Section VIII, Div. 1 Design Pressure: 260 psig @ 200°F Materials: Carbon steel shell and heads, cast iron victaulic Couplings with machined coupling ring grooves, and 316 SS cyclone support plates External Coating: 2 coat blue epoxy Internal Coating: 2 coat immersion grade epoxy Progressing Cavity Pumps Manufacturer: NOV/Moyno Casing Material: Carbon steel with cast iron discharge flange Drive Mechanism: Stainless steel flexi-shaft Stator: Performance Oilfield Buns (POB) Rotor: Low alloy tool steel with hard chrome plating Seal: Cartridge mechanical seal on gland end External Coating: 2 coat blue enamel Piping Design: ANSI 831.3 Materials: Carbon steel Connections: ANSI 150# flanges for 2" and larger and solids slurry lines, socket weld for under 2" External Coating: 2 coat blue epoxy Internal Coating: None Valves: Isolation valves: 3" and larger to be lug body, resilient seated butterfly valves, 2° and smaller to be ball valves with carbon steel body/stainless steel trim. Slurry discharge to be full bore ball with hardfaced firm. Instrument Connections: 1/2" stainless steel ball valves Controls and Electrical Area Classification: Class 1, Div. 2 - intrinsically safe PLC and Display: Allen-Bradley panelview Enclosure: Nema U stainless steel Process Transmitters: 4-20 mA HART protocol Wiring: Class 1, Div. 2 with cable tray support Electric Motor Drive: 100 HP TEFC, 1800 rpm, 1.15 SF, Class F insulation Structural Design: Robust oitield skid, carbon steel i -beam construction, checkered deckplate, welded pipe and equipment supports, 4" perimeter combining, 2" threaded drain connections at each comer, pull bars at each end. Coating: Two coats blue epoxy www.nov.com/waterwohf pft@nov.com 19 NATIONAL OILWELL VARCO THE STATE °fALASKA 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.aiasko.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-14 Hilcorp Alaska, LLC Permit to Drill Number: 219-040 Surface Location: 4913' FSL, 261' FEL, SEC. 14, TI 3N, R9E, UM, AK Bottomhole Location: 911' FSL, 1535' FWL, SEC. 20, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Se2Mourit, Jr. Commissioner �� DATED this'= day of March, 2019. STATE OF ALASKA AL,,-t(A OIL AND GAS CONSERVATION COMMI"iON �� ; ; ;� PERMIT TO DRILL 20 AAC 25.005 Ia. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas 0 Service - WAG ❑ Service - Disp ❑ 1c. Specify (well is proposed for: Drill ❑✓ Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑✓ Service - Winj ❑ Single Zone ❑✓ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU M-14 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,900' TVD: 3,960' Milne Point Field Schrader Bluff Oil Pool i 4a. Location of Well (Governmental Section): 7. Property Designation:, Surface: 4913' FSL, 261' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL025515 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 2454' FNL, 1756' FWL, Sec 13, T13N, R9E, UM, AK LONS 16-004 4/1/2019 i Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 911' FSL, 1525' FWL, Sec 20, T13N, R10E, UM, AK 5104 3,018' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.4 15. Distance to Nearest Well Open Surface: x-533903 y- 6027765 Zone -4 GL / BF Elevation above MSL (ft): 24.7 to Same Pool: 1,600' to MPU M-12 16. Deviated wells: Kickoff depth: 380 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: 1718 Surface: 1332 O 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cord 20" 78.6# A-53 Weld 113' Surface Surface 113' 113' ±270 ft3 Sig 1 L - 755 ft3 / T - 458 ft3 12-1/4" 9-518" 40# L-80 TXP SR 5,353' Surface Surface 5,353' 3,918' Sig 2 L - 1937 ft3 / T - 314 ft3 Tieback 7" 26# L-80 TXP SR 5,200' Surface Surface 5,200' 3,902' Tieback Assy. 8-1/2" 6-518" 20# L-80 Hyd 563 12,700' 5,200' 3,902' 17,900' 3,960' Cementless PreDrilled Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑✓ 20. Attachments: Property Plat ❑✓ BOP Sketch Shallow Hazard ysis Drilling Program eFluidPrtog Divertter Sketch L4 Seabed Report e Drilling atm ✓ 20 AAC 25.050 requiremot ents B 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilCof .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 Fdk M01,TY M yEQ$ Authorized Signature: Date: Commission Use Only Permit to Drill API Number: Permit Approv See cover letter for other Number: Q 50- ��p 0—p Date: ( requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Lryv Other: ✓ aDQ� O �S Samples req'd: Yes ElNo2 Mud log req'd: Yes ❑ No L7 7V J /0J/Jv 1 HiS measures: Yes L] No [� Directional svy req'd: Yes [� No ❑ // bTe_rn —4_ 5 SV r Spacing exception req'd: Yes ❑ No C]' Inclination -only svy req'd: Yes ❑ No [§} CO) Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: `v / Form -4 1 Revis 512 17 This permit is valid for 2 s r t e a royal per 20 AAC 25.005(g) tta mens i u rcate �� 3�1tA � 3 2tv ,� Q°F� � 1 Ni►t 'fly �Y' 8- H Hilcorp E' C-Vffy 3.15.2019 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU M-14 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'M' Pad, well slot 14. Drilling operations are intended to commence approximately April 1st, 2019, pending rig schedule. MPU M-14 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M- 14 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU M-14, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, F oe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-14 Drilling Program Version 1 3/15/19 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP NIU and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Pre -Drilled Liner...................................................................................31 17.0 Run 7" Tieback..............................................................................................................................36 18.0 Run Jet Pump Completion...........................................................................................................39 19.0 RDMO............................................................................................................................................39 20.0 Doyon 14 Diverter Schematic.......................................................................................................40 21.0 Doyon 14 BOP Schematic.............................................................................................................41 22.0 Wellhead Schematic......................................................................................................................42 23.0 Days Vs Depth................................................................................................................................43 24.0 Formation Tops & Information...................................................................................................44 25.0 Anticipated Drilling Hazards.......................................................................................................45 26.0 Doyon 14 Layout............................................................................................................................48 27.0 FIT Procedure................................................................................................................................49 28.0 Doyon 14 Choke Manifold Schematic..........................................................................................50 29.0 Casing Design.................................................................................................................................51 30.0 8-1/2" Hole Section MASP............................................................................................................52 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................53 32.0 Surface Plat (As Built) (NAD 27).................................................................................................54 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................55 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50...............................................................56 n Hilcorp 1.0 Well Summary Milne Point Unit M-14 SB Producer Drilling Procedure Well MPU M-14 Pad Milne Point "M" Pad Planned Completion Type Jet Pump on 3-1/2" Production Tubing Target Reservoirs Schrader Bluff OA Sand Planned Well TD, MD / TVD 17,900' MD / 3,960' TVD PBTD, MD / TVD 17,880' MD / 3,960' TVD Surface Location Governmental 4913' FSL, 261' FEL, Sec 14, T13N, R9E, UM, AK Surface Location AD 27) X= 533,903.8, Y= 6,027,765.6 Top of Productive Horizon (Governmental) 2454' FNL, 1756' FWL, Sec 13, T13N, R9E, UM, AK TPH Location AD 27) X= 535,932 Y= 6,025,687 BHL (Governmental) 911' FSL, 1525' FWL, Sec 20, T13N, RI OE, UM, AK BHL AD 27) X= 546,249.6, Y=6,018,550 AFE Number 1814314 AFE Drilling Das 23 days AFE Completion Das 5 days AFE Drilling Amount $4,878,730 AFE Completion Amount $2,066,294 AFE Facility Amount $391,000 Maximum Anticipated Pressure Surface 1332 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1718 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.0 ft = 58.7 ft GL Elevation above MSL: 25.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information H Hilcorp Alaska, LLC '�CO' Changes to Approved Permit to Drill Date: 311412019 Subject: Changes to Approved Permit to Drill for MPU M-141 File #: MPU M-14 Drilling and Completion Program Any modifications to MPU M-14 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Date Date Milne Point unit M-14 SB Producer Hilco2 Drilling Procedure 2.0 Management of Change Information H Hilcorp Alaska, LLC '�CO' Changes to Approved Permit to Drill Date: 311412019 Subject: Changes to Approved Permit to Drill for MPU M-141 File #: MPU M-14 Drilling and Completion Program Any modifications to MPU M-14 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Date Date Milne Point unit M-14 SB Producer Hilco Drilling Procedure �� 3.0 Tubular Program: 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 in - in - ft - X-52 Weld rs: si aps 1 Cond 20" 19.25" 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 Tieback 7" 6.276" 6.151" 7.656 26 L-80 TXP 7,240 5410 604 8-1/2" 6-5/8 Pre -drilled 6.049 5.924 7.390 20 L-80 Hydri1563 6,090 3,470 459 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 n Hilcorp &� wrp 5.0 Internal Reporting Requirements Milne Point Unit M-14 SB Producer 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 pmazzolinighilcoM com mmyers hilcom, a eneel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp.corn iencel@hilcorp.com and cdinger@hilcgM.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mm ers hilcorp.com 4engel@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 lengel(a@hilcorp.com Completion Engineer Stan Porhola 907.777.8412 907.331.8228 sporhola@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 kflemina hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 1 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 1 cdinrer@hilcorp.com Page 5 n HilcoT &�C,L 6.0 Planned Wellbore Schematic Qg IlB �+Y:502Y/ GLEev.:21d Milne Point Unit M-14 SB Producer Drilling Procedure IvIdne Point Unit Well: MPU Moose Pad M-14 PROPOSED SCHEMATIC Last Completed: Proposed PTD: TBD TREE & WELLHEAD Tree Cameron 31/9' SM WelBread FMC163J4'3Mxll"SMpy Wbudw(11'x31/2"EUETapand Bottum with 3'DW"11'BPV p.file. Zea WN'NPr.M.Ii.. TD -17,9U' YV0 /TD=3,SWV VCj P8(D=ll,8t9' Nq/TD=3,9aCf" Page 6 OPEN HOLE / CEMENT DETAIL 6Y 50 yNk(fO Yards BBKtYlCdurnped ebwn backsidal 12-1/4"Is[page 755N311.7NLggada.45B ft315.ea $yd(LCCA7 12-IVr2rd supe I 1937ft31O7NPRmL,314ft3lS-MSe(lCM 8-1/2" Cet9ea[1Y35 Uner in &1j2" hale CASING DETAIL Size Type YAl Grade/ Conn Drift ID I TOP Uper Cpmpleticn .'x34" Conductor(I sWaledl 79,61 A-53/WPId N/A 5urfax 2 TBD 9 -sir Surtax 40/L-80/T%PSR &679" Surface 2.813" A17,�90WQOD355 Y Tieback 26/L-8J/71(PSR &151" Surfa:e 3.3'G a NSndreI w/%" Wne Bntake Gau rl 6-50 Un.R( Drilledf 20/L-8Dj UW1LIS63 SAM' 5,205 TBD TUBING DETAIL 3-d/1" Tubing 9.3/L-80/CUE-fXD 2B67' 1 Surf I 25,201Y I OM7 WELL INCLINATION DETAIL XOP @ ear Max iIokAn a=TBD. La Jet Pump MaxilakAn e=TBD.@1X1JPmfiIe MaxlloleAn e=TBD.@Tubi tail Max Jfuk An&=TAO. @ TBDMD JEWELRY DETAIL Na. I Tap MD I Ir Odft 10 Uper Cpmpleticn 1 2Y Tubin Ilaner(3-1/2'EUC-MOD T.PB 286Y 2 TBD 3.5"GLhlx;/1.5"CGLY.JRKLnech 2.867 3 TBD 3.5"External Pr=ssure Gaqm Wrdrel MWMW Gau ) 2.813" 4 T80 3.5" let Puma CsitY, forward QmJec Pump atewAnnulus),"TVD 2813" 5TB2 3.3'G a NSndreI w/%" Wne Bntake Gau rl 2.813" 6 TBD 7' x 35" PHIL 11etrierable Paler 2913" 7 TBD 1 3.5"107 Nipple, Mn 10=2-750'IbC.P, 2.913" P.&..g Brie 2750' 9 TBD I 3.5"WLEG 18101 P 4: 286Y 9 5,205 YTeb=k .(9.25"00 N.G Eal 10 5.203' BOT SU* Low Top Packer w/BD SII,7"= 35/8" 111.5'Tebad 5keuel 11 5,250' Y 563 L-Wx&VIr U 625 L-W%O jNZ4W' 12 5.255' 6-578"Pn,0ri9WW. 13 17,895 4 -Yr LFillable Sub 14 17.995' WV V.Nv LTC Bdk(i S" Ball m SNat/ClPaod) H Hilcorp 7.0 Drilling / Completion Summary Milne Point Unit M-14 SB Producer Drilling Procedure MPU M-14 is a grassroots iet pump producer planned to be drilled in the Schrader Bluff OA sand. M-14 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately April 1 st, 2019, pending rig schedule. Surface casing will be run to 5,353 MD / 3,918' 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, NIU & test 13-5/8" x 5M BOP 5. Drill 8-1/2" lateral to well TD. Run 6-5/8" production liner 6. Run 7" tieback 7. Run completion 8. 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 H Hilcorp Milne Point Unit M-14 5B Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-14. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. j 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 respectfully requests a variance to 20 AAC 25.265 (c)(1), requiring the surface I safety valve be located in the vertical run of the well tree. Due to the jet pump production method and horizontal tree configuration, Hilcorp Alaska proposes that the surface safety valve be installed horizontally. Page 8 Milne Point unit M-14 SB Producer 2 Hilc.Drilling Procedure it Cap�vy Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP D • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/4968' o Blind ram in him cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/4996" 3.V° • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reggnn alaskaeov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixsegalaska.gov Primary Contact for Opportunity to witness: AOGCC.Insi2ectors@alaska.gov Test/Inspection notification standardization format: b—ft://doa.alaska.gov/oge/fonns/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 0 Hilcorp �. 9.0 R/U and Preparatory Work Milne Point Unit M-14 SB Producer Drilling Procedure 9.1 M-14 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 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 H Hilcorp 10.0 N/U 21-1/4" 2M Diverter System Milne Point Unit M-14 SB Producer 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. 10.4 Set wear bushing in wellhead. Page 1 I 10.5 Rig & Diverter Orientation: • May change on location i M-10 m M-11 ■ M-13 M-12 M-14 M-18 + 75' Radius Clear of Ignition Sources Diverter Line Drawing Not To Scale MPU M -Pad Diverter Line May Be Oriented Different On Location Page 12 Milne Point unit M-14 SB Producer Hilco Drilling Procedure 10.5 Rig & Diverter Orientation: • May change on location i M-10 m M-11 ■ M-13 M-12 M-14 M-18 + 75' Radius Clear of Ignition Sources Diverter Line Drawing Not To Scale MPU M -Pad Diverter Line May Be Oriented Different On Location Page 12 n Hilcorp ��42 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-14 SB Producer 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# S-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DL < 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 H Hilcorp Milne Point Unit M-14 SB Producer Drilling Procedure Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW to 9.8 ppg 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. 11.4 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ Depth Interval MW ( g) 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. Page 14 H Hilcorp .e c22 Milne Point Unit M-14 SB Producer Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do notjeopardize 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 Densi Viscosity Plastic Viscosity Yield Point API FL I pH Tem Surface J 8.8-9.8 1 175-175 20-40 25-45 <10 1 8.5-9.0 0.08 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or M liquids) M-1 Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH 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 H Hilco�r 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. 12.3 12.4 Milne Point Unit M-14 SB Producer Drilling Procedure • 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. P/U shoe joint, visually verify no debris inside joint. Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe I joint — 9-5/8" TXT, 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 Ada for • Ensure bypass baffle is correctly installed on top of float collar. This end up. —, Bypass Baffle W • 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 H Hilcorp �..s c®p.ey 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 (d used) ID Depth Bypass or Shut-off Baffle to Depth Float Collar Depth Float Shoe AT Depth Hole TO 'Reference Cavng Sales Manual Section 5 Page 17 "A Overall Length B hgm. ID After Dtillout C Mat. Tool OD D Opening Seat ID E Closing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit M-14 SB Producer Drilling Procedure H&orp pill Bunning Draw WlCement. : sm,t off mug Batik Adapter a .. t� By-0assplug i By pass Saff e Float Collar Float Shoe H Hilcorp Milne Point Unit M-14 SB Producer 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: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist • 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 10 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" 409 L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 Milne Point Unit M-14 SB Producer Hil 2Drilling Procedure it «P�,w TXP® BTC Outside Diameter 9.625 in. Min. Wall 87.5% CMIaclim 00 51ake-up Loss ThioFress Couplrc g Leagah Threse. per in I -) Grad. LSD connection 10 Connection OD Option 8.823 ., REGULAR Type t Well Thickness 0.395;1. Connection OD REGULAR Option COUPL111G Ealy Rad Grade L80 Type i• Drie API $t]ndard list bard- Brown 2nd Bard: - Type, Casing 3m Band: - GEOMETRY Nominal OD 9.625 in, iiommid wttigln do I1,51 Drift Nominal ID e836in. yJaL TMan.. 0395 i-. Pktr. End Might OD Telsrsnce AN Page 19 11/0842018 PIPE BOOT 19 Blind Red 2nd sand: Bane, 3rd Eand: - 4th. Sand: - 8.679 m. 38.97 ®s8 PERFORMANCE Body Yield strength 916 x1000 Box inlemal YriN 5750 psi SMYS 80000 psi Collapse 3090 psi GEOMETRY CMIaclim 00 51ake-up Loss 10.625 o, 4.891 in. Couplrc g Leagah Threse. per in 10825A 5 connection 10 Connection OD Option 8.823 ., REGULAR PERFORMANCE Tension Eficiency 100.0% d mryesid Stmsgm 916.000x1000 Internal Pressureapao4ylll 5750000 psi lbs Compression Effipiency 10% Compression smarsoh 916.000 x1000 Max. isowable Sending 39';100 ft Ibs Exo mal Pressure Cawdy 3090.000 psi MAKE-UP TORQUES hrmunum 18860 d-ks Optimum 20360 ft -ms Ataximum 23060 ft4bs OPERATION LIMB TORQUES Operating Toraue 356008-ts Yield Toque 8740oft-Ibs Notes This connection is fully interchangeable with: TXP& BTC - 9-625 in - 36143.5147153.5158.4 Ib@sM [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C31 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. I/ n Hilcorp .. mrp Milne Point Unit M-14 SB Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 n Hilcorp ft� a 13.0 Cement 9-5/8" Surface Casing Y Milne Point Unit M-14 SB Producer 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. L 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 RILJ 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 11t Stage Total Cement Volume: Page 21 17 S s'- iH Sti Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" (4,353'- 2500') x .0558 bpf x 1.3 = 134.4 754.7 J Casing Total Lead 134.4 754.7 12-1/4" OH x 9-5/8" (5,353'- 4,353') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 17 S s'- iH Sti n Milne Point unit M-14 SB Producer Hiloorp Drilling Procedure Cement Slurry Design (1St Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,233' x.0758 bpf = 396.6 bbls 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 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. Page 22 Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM'm System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 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. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5,233' x.0758 bpf = 396.6 bbls 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 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. Page 22 n Hilcorp Milne Point Unit M-14 SB Producer Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II stage tool 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Second Stage Surface Cement Job: Milne Point Unit M-14 SB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. (If ESIPC is used and packer element inflated, CBU x 1 minimum before pumping second stage). 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 curt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: 2?w7.. Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM'm System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 a 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 i Lead Slurry Tail Slurry System Permafrost L SwiftCEM'm System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 i 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 It. 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 iengel@hilcorp. com and cdin.eer@hilcoW.com com This will be included with the EOW documentation that goes to the AOGCC Page 25 Milne Point unit M-14 SB Producer Hilcorp �T X22 Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x .0758 bpf= 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement It. 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 iengel@hilcorp. com and cdin.eer@hilcoW.com com This will be included with the EOW documentation that goes to the AOGCC Page 25 H Hilcorp 14.0 BOP N/U and Test Milne Point Unit M-14 SB Producer Drilling Procedure 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5" BOP test plug 14.4 Test BOP to 250/300 _psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. �� • Test 5" test joints V • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. V/ Page 26 n Hilcorp 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-14 SB Producer 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 or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/11 and test casing to 2500 psi / 30 min. Ensure to record volume/ pressure (every'/4 bbl) and �1( 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 tri (J pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry l! 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 im 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 RAJ and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 27 H Hilcorp ee c= Milne Point Unit M-14 SB Producer 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 PrnnP_rtlPs- /I� Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Productio 8.9-9.5 -25 - ALAP 1 15-30 4-6 <10% <8 1 <1 1.0 1 <100 System Fo ulat' . Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Page 28 n Hilc�r 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-14 SB Producer Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to sectionTD 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 OAl & 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 • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% • Offset injection and abnormal pressure has been seen on M-10 & M-12. MPD will be utilized to monitor pressure build up on connections. 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 ovenhole sidetrack is achieved. Page 29 H Hilcorp Milne Point Unit M-14 SB Producer Drilling Procedure 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 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 15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOK 15.19 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.20 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 15.21 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.22 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 30 H Hilcorp 16.0 Run 6-5/8" Production Pre -Drilled Liner Milne Point Unit M-14 SB Producer Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and with 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW. • Proceed with well kill operations. 16.2. Well control preparedness: In the event of an influx of formation fluids while running the 3- 1/2" inner string inside the 6-5/8" pre drilled liner: • P/U & M/U the 5" safety joint (with 6-5/8" x 3-1/2" triple connect crossover installed on bottom, TIW valve in open position on top, 3-1/2" handling joint above TIW). M/U 3-1/2" and then 6-5/8" to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • 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. 16.3. Pick up and rack back as much 3-1/2" inner string as possible. Ensure to check over pull limitations with drill pipe in the derrick. 16.4. R/U 6-5/8" pre -drilled liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing 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 6-5/8" pre -drilled production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 6-5/8" pre -drilled liner will auto —fill • 6-5/8" Liner will be centralized with 1/joint free floating • If needed, install swell packers as per the lower completion tally. Remove protective packaging on swell packers just prior to picking up Do not place tongs or slips on the packer element 6-5/8" 20 # H dri1563 Torque OD Minimum Optimum Maximum Yield Torque 6-5/8 5,900 ft -lbs 7,100 ft -lbs 10,300 ft -lbs 36,000 ft -lbs Page 31 OF Milne Point unit M-14 SB Producer HilcoT�p Drilling Procedure a�� Wedge 5638 Page 32 .- 11=Q01S Outside OumNtt 8.835 m. Nin. Wall 87.5`6 LOpn¢lIMW Opam REGULAR Thicaxss (') Grade LSD sow PERFORMANCE Tanslw EBCMnty 9iT2 -. nl'lsldelrergld Type i vdemm F..rcLapac[r Wall Thickness D288 n. Correction OD REGULAR 1¢L C¢mpmi.Y EAcl v Option ..ampres.4an slnnryL, CQ 1-1140 M iiB 53.9'l1Mn Body Red Is Bala Red Gndc LBO Type 1- Drift API SlarWard la Band: Brown 2rd Bald: 2rd Bald. - Brown MAKE-UP TORQUES TTP¢ Caslna 3,d Bal@ • 3rd Bard. - Blcimum 59em Z-bs Optlmum 71"t -M Mh Ezrd PIPE BODY DATA GEOMETRY N¢mTaloo 6.625 1nH..m lydWem 30.0e1W. Omit 5.9u.n. Meminalc LM in 'i an Tnvi:n¢ss Qmais R.M End W.W. 19-S11tc:n ODT¢I.. API PERFORMANCE E., Ve S."In a58 x+M+C•los 11'bmal vt¢+d sd90 psl 5NYs Been" Lplapi¢ UM NI COP:NEC?ION DAT GEOMETRY cp,_.-.ca ..3r _,�ci.--=nqm 9.7EIn. cpnn¢c1nn lD S.Tn m. IMI.,! -..a CaSi r. inmuds per In 3.39 LOpn¢lIMW Opam REGULAR PERFORMANCE Tanslw EBCMnty 9iT2 -. nl'lsldelrergld ¢39261 OW3 vdemm F..rcLapac[r fie90ABD pu 1¢L C¢mpmi.Y EAcl v 1*114 ..ampres.4an slnnryL, 4S9 -w.,=) Ma•Atavatb ec 4 53.9'l1Mn IOs £al¢rna1W¢rsv¢ Lapxlry 38Telea pt: L¢upinA caz¢ Loud 311106 Ss MAKE-UP TORQUES Blcimum 59em Z-bs Optlmum 71"t -M wdmum ld3 i, Ips OPERATION LIMIT TORQUES OF¢raleq Tn¢ua 31mt—bs V ti TeM. 36001 SUCK -ON Ltmmum 1eep^.-Ms SWlmum MOD ft a Notes Ttds wnneciron is iuRy interchan8aabie with- Wedge 563E - 6.625 in. - 24 128 ? 32 Ibs1Yl Connections with DopelessS Technology are fulty mnipatible with the same mrinaction in its Standard version Milne Point Unit M-14 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. • Consider having a joint of solid pipe across BOPE Stack while running inner string 16.7. R/U false rotary and run 3-1/2" 9# Inner String • Ensure inner string is drifted for WIV closing ball OD 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 6-5/8" liner. Fill liner tieback sleeve with "Xanplex", 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 PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on 5" HWDP no faster than 30 fl/min — this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The inner string will prevent the DP from auto filling. Fill DP with mud 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. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Rig up to pump down the work string with the rig pumps. NOTE: The wellbore will be swapped over to brine after the liner has reached TD to remove mud cake from the well bore. Mud cake will cause facility upsets. Page 33 n Hilcorp Milne Point Unit M-14 SB Producer Drilling Procedure 16.18. Break circulation and circulate out the mud. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. Displace well to brine (-9.2 ppg KCl/NaCl). , over displace well by at least 100+ bbl. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. 16.19. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all losses. Confirm all pressures with Baker. 16.20. Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. 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. 16.21. Displace 1.5 OH + Liner volume. 16.22. 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. 16.23. 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. 16.24. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP liner hanger to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4500 psi to release the HRDE running tool. 16.25. 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, 16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.27. 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. 16.28. P/U pulling 3-1/2" out of the pack off & displace out liner with two volumes at max rate. 16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 3-1/2" inner string. Leave enough 5" DP racked back to trip back to 9- 5/8" shoe. 16.30. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. Page 34 H Hit=E, pmy Milne Point Unit M-14 SB Producer Drilling Procedure 16.31. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.32. POOH & L/D remaining 5" HWDP & Inner string 16.33. Once inner string is L/D, swap to the completion AFE Page 35 Milne Point unit M-14 SB Producer Hilco Drilling Procedure �P 17.0 Run 7' Tieback 17.1 RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. POOH. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 psi) solid body casing rams. 17.2 R/U 7" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.4 M/U first joint of 7" to seal assy. 17.5 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 36 CONNECTION DATA GEOMETRY Connection OD TAM in. Coaling Length 10.200 in. Connection ID 6266 ii. Maka-up Loss 4-14 in. Tlrteads per is 5 Connection OD Option REGULAR PERFORMANCE Milne Point unit Tension Effxa v 100.0% Join Yaeld Soength 004.000 x1000 lnlemal PressureCapacity l' � 7240.000 psi M-14 SB Producer Hite Hilco Compression EFxienmy 100% Compression Strength 604.000 x1000 Drilling Procedure lbs TXPO BTC 12-08;2018 Outside Diameter 7.000 in. Min. Wall 87.5% Thickness (') Grade LBO low Type 1 Wall Thickness 0.362 in Connection OD REGULAR Option CWPIJNG PIPE BODY Body: Red Iat Band: Red I Grade LBO Type t' Drift AN Standard '. tat Band: Brown 2nd Bandro 2nd Band:- B wn Type Oases 3rd Band:- 3rd Band-- 4 ih Band: - ` PIPE BODY DATA GEOMETRY Nominal OD 7.000 in Nominal Vveirght 26 lbsift Qin 6151 iti Nominal [D 6276m. Wali Thickness 0.362m. Plan End Weight 25.69 ban OD Telerarce API PERFORMANCE Body Yield Strength 604x10001bs Intemat Yield 7240 psi sws 00000 psi Collapse 5410 psi CONNECTION DATA GEOMETRY Connection OD TAM in. Coaling Length 10.200 in. Connection ID 6266 ii. Maka-up Loss 4-14 in. Tlrteads per is 5 Connection OD Option REGULAR PERFORMANCE Tension Effxa v 100.0% Join Yaeld Soength 004.000 x1000 lnlemal PressureCapacity l' � 7240.000 psi lbs Compression EFxienmy 100% Compression Strength 604.000 x1000 Max. Alo sable Berc ing 52';100h lbs External Pressure Capacity 5410.000 psi -MAKE43PTORQUEs y---- — --- ------ `- J k6nimum 13200 ft -lbs Optrn m, 14750 ftJbs Ma!5rxm 102306-.ts OPERATION LIMIT TORQUES Operating Torque 20000 ftdbs Yell Torque 234000 -lbs Notes This connection is fully interchangeable with: TXP@O BTC - 7 in. - 231 29132135138 IbsM [t] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C31190 10400 - 2007. Page 37 17.6 M/U 7" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 PIU string & remove unnecessary 7" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly I ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.16 Slack off and land hanger. 17.17 Confine hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. i 17.20 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min. 17.3 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 Milne Point Unit M-14 SB Producer Hill corp �T 202 Drilling Procedure 17.6 M/U 7" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 PIU string & remove unnecessary 7" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly I ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.16 Slack off and land hanger. 17.17 Confine hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. i 17.20 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min. 17.3 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 H Hilcorp 18.0 Run Jet Pump Completion Milne Point Unit M-14 SB Producer Drilling Procedure 18.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test same. Verify the Jet pump components. 18.2 Run the 3-1/2" Jet Pump Completion as noted by completion engineer. 18.3 M/U Jet Pump assembly and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 MU tubing hanger and landing joint. Terminate control lines. 18.6 Land tubing hanger. 18.7 Drop ball and rod, pressure up to 1,700 psi to start setting of PHL packer. 18.8 Continue to pressure up to 3,000 psi to set packer. 18.9 Pressure's to 3.500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. 18.11 Pressure up annulus to 3,500 psi to test casig(packer for 30 minutes and chart 18.12 Bleed tubing to 0 psi. Pop shear valve from annulus to tubing (2,500 psi differential). 18.13 RILDS and test hanger. LD landing joint. 18.14 Install BPV. Pressure up on 3-1/2" x 7" annulus to 500psi, to test BPV from below. 5 min. 18.15 N/D BOP. 18.16 WU tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.17 Circulate diesel freeze protection down 3-1/2" x 7" annulus (Volume should equal capacity of tubing to 2500' + tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. Note — this may be done post -rig. 18.18 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.19 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.20 Notify AOGCC of SVS testing Test SVS on horizontal run of tree within 5 days of the start of production Set low pressure trip below 275 psi Moose Pad header & separator pressure 19.0 RDMO 19.1 RDMO Doyon 14 Page 39 0 HilcoT amu. 20.0 Doyon 14 Diverter Schematic 21.V4* 2M R.w- 21 1/4.2M— Di soar r 21-1,4'V Spo rSpa 167.¢• 3M: 21-114'2M OSI Page 40 Milne Point Unit M-14 SB Producer Drilling Procedure -W FW Opening KnEC VVN `16 -Dry ff Llr Milne Point unit M-14 SB Producer Hilo 22 Drilling Procedure � 21.0 Doyon 14 BOP Schematic K,:I Une----_ Page 41 2-7/8" x 5" VBR Blind Rams x SM HCR hoku Line al Gate Valve 2-7/8" x 5" VBR Milne Point unit M-14 SB Producer HilcoT Drilling Procedure 22.0 Wellhead Schematic GEH 5 SI -111 HOLT. L 1 1 rlh L .Pwwa waLY ncY c ...I —w.lep..A sll[51JfTA_v.� -. c�aLP 'u' •Y Page 42 L:tl. '.E-SIl 51PL' G[xfi • •� rt. Itl rnx sL bem ��1LC�n. :rtar savor sss�. 01JJ d0. HCI iIY IAL Y'1'1 -p "131u G'�]II RL L 3 26A LBaI �FId'V iue.2r..Lal n>Ia� aJ A14'CV YUD�EI.I VlCIYC =1M1G I5.}i p-0Yl. 96J .Y .vrn:n. SAV2-2C'Lx ..F�. AOY M.fO.Y S[Ar- PG[F :f/' f9) .WK {IY FXCP • LY IfL� 14 P. X521 C:m, OWU LG!pbl T' PEc:Ownpl9JGl r M b ROLE- GEH 5 SI -111 HOLT. L 1 1 rlh L .Pwwa waLY ncY c ...I —w.lep..A sll[51JfTA_v.� -. c�aLP 'u' •Y Page 42 L:tl. '.E-SIl 51PL' G[xfi • •� rt. Itl rnx sL bem ��1LC�n. :rtar savor sss�. 01JJ d0. HCI iIY IAL Y'1'1 -p "131u G'�]II RL L 3 26A LBaI �FId'V iue.2r..Lal n>Ia� aJ A14'CV YUD�EI.I VlCIYC =1M1G I5.}i p-0Yl. 96J .Y .vrn:n. SAV2-2C'Lx ..F�. AOY M.fO.Y S[Ar- PG[F :f/' f9) .WK {IY FXCP • LY IfL� 14 P. X521 C:m, OWU LG!pbl PEc:Ownpl9JGl r M b ROLE- a?_25-17 Mc!!L S dl -2 r Pld wl? 25-I I G LYYv, o EIwYS xrr- J.G4P 't 25 r CIM00272r�7J II LCP1P:Exl t��mbM[ 23.0 Days Vs Depth 0 2000 Page 43 Milne Point Unit M-14 SB Producer Drilling Procedure MPU M-14 SB OA Producer Days vs Depth 5 10 15 20 25 30 Days 4000 6000 5000 s L v Q 10000 (7 12000 14000 16000 Page 43 Milne Point Unit M-14 SB Producer Drilling Procedure MPU M-14 SB OA Producer Days vs Depth 5 10 15 20 25 30 Days Milne Point Unit M-14 SB Producer Hill co Drilling Procedure ��E®x 24.0 Formation Tops & Information MPU M-14 Formations (wp04) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2268 -2039 2094 921.36 8.46 LA3 3667 -3246 3301 1452.44 8.46 Schrader Bluff NA 4400 -3691 3749 1649.56 8.46 Schrader Bluff OA 5236 -3847 3906 1718.64 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL COMMENTS TVD FM LITH DESCRIPTION as oaa NOTE: See IndNidual mil Program for Oipei a. . Guhik specific casing design, depths, sizes. 600 weights, grades and connections. o Unconsolidated coarse m rreENm sandandimal gravel g whin"nor whir... NIFICANT GRAVEL NTSWHEN 1,000' S n D ARE ENCOUNTERED WHEN DRILLING THE A E ENCOUNTERED SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. ,Iso Base permafrost knorboda offend. clay. and aeslores with oolasional 2,000 show of coal. Wath possibb slddncking while wasNnyrx"ng. LJ3 & L•15. s,>p. u„�, -44. No hydrates encountered on L -Pad wells drilled to date. CgMimmd Intercede of"nd, clays and Solutiones with occasional shows of coal. Traces of p,ahe at H- 3100 it 3,000' Interval at *1. 1100 it can be SCcky and tighl(Ld1). Gay Slemads between 3000 and 4500 ft C 1472- L A 3657' sane. Y UGNU: sariIs of cwrswing award vends whlcharo (A&CD, nada up of: (from top to balom) wan. srnst fire sand. ghysh.W Boder developed intervwIN.Iralesasyw UGNU progress Into the Land IS(deaper), Ugm and Schrader Slat. Possible hydracartons i"led twn> mSWcornirof Mllned.wlepmant NonMmareals 1 -MI doenst.aeand vest. '3719' Wanas (-Ae.tl s0°° INA) Schrader Bluff Sands: 4,000' N$Ws 1 -Waco. Continued ayedng c"roanhp upward sands m.bwe -41111�10 Schrader Bluff: Possible lost circulation 6.Fl mceptmorscwdensed.m.1th oc"aenalcoah. zone white drilling long strings and running '4170• osne. Gay rich shale Imirval 1100 to 4600 R Lig" and Schrader Blunt P"silAo hydrocarbons 11"ted casing. Recommend deep setting surface (OA) I-AaG WSWcomarofeldred.wlopment 1.47andl.l aro casing for Kuparuk long strings. Also, the OE.Fl wnnplatedlntho Sands'Blalsand Nonh.m sued Schrader Bluff sands are a potential Schrader L -Ped Is dowm4uauro and "I. differential stuck pipe interval it left un -cased Bluff. C safaca"SIN point F shill, below for Kupwuk long strings. Sands:sander Bluff sand for toupet reach waft. 1 Page 44 H Hilcorp 25.0 Anticipated Drilling Hazards Milne Point Unit M-14 SB Producer Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 45 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 46 Milne Point Unit M-14 SB Producer Hilcorp Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 46 n Hilc ft�,22rp 8-1/2" Hole Section: Milne Point Unit M-14 SB Producer Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No 142S 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 112S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure has been seen on M -Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision There are no offset wells with a CF of>1.0. 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. Page 47 H HilcoT 26.0 Dovon 14 O � I- III' Page 48 o � o WIN Milne Point Unit M-14 SB Producer Drilling Procedure N J n Hilcorp �T .M, 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-14 SB Producer 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 49 28.0 Doyon 14 Choke Manifold Schematic Milne Point unit M-74 SB Producer QdGI Hil=Drilling Hilt Procedure 28.0 Doyon 14 Choke Manifold Schematic Page 50 d�ddO QdGI yN N (1 Z� z5 N p p 3 m z y c+ v p o y 3 3 n a v n d 0 n� W P W< P rt n n Q a p N N n N A R W n < J 6 N 3 D 3 c n u n Q A� dn 3 �I �dE �a W Z W o • Jd� o w r o o' 0% t7 �l w = J b r _r V D 0 Q w o CL w Page 50 n Hilcorp 29.0 Casing Design Milne Point Unit M-14 SB Producer Drilling Procedure Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 3/15/2019 WELL: MPU M-14 DESIGN BY: Joe Engel Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1332 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1332 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 51 Casing Section Calculation/Specification 1 2 3 4 Casing OD 95/8" 65/8" Top (MD) 0 5,353 Top (TVD) 0 3,918 Bottom (MD) 5,353 17,900 Bottom (ND) 3,918 3,9611 Length 5,353 12,547 Weight (ppi) 40 20 Grade L-80 L-80 Connection TV H583 Weight w/o Bouyancy Factor (lbs) 214,120 250,940 Tension at Top of Section (Ibs) 214,120 250,940 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 4.28 1.83 Collapse Pressure at bottom (Psi) 1,935 1,956 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.60 1.77 MASP (psi) 1,332 1,332 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 4.32 4.57 Page 51 H Hilcorp 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 14 8-1/2" Hole Section HllmT MPU M 14 Milne Point Unit MD TVD Planned Top: 5353 3918 Planned TD: 17900 3960 Milne Point Unit M-14 SB Producer Drilling Procedure a Anticipated Formations and Pressures: V Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 1 3,918 1 3,860 1 1724 1 Oil 8.46 0.440 Offset Well Mud Densities Wall MW ranee Too (TVDI 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 forthe 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,918 (ft) x 0.78(psi/ft)= 3056 3056(psi) - [0.1(psi/ft)*3918(ft)]= 2664 psi MASPfrom pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) J 3918 (ft) x 0.44(psi/ft)= 1724 psi / 1724(psi)-0.1(psi/ft)*3918(ft) 1332 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore togas at 0.1 psi/ft. Page 52 H HilmTate, 31.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-14 SB Producer Drilling Procedure FBiA +r Sec. n ADL388235 Sec: t2 ' ADL025509i(62l) I Ly:. '� ��' ,fir \r ✓' •/ /^i.•.. ;', ,``. ,..t'P6' ��,.��lru of -f4 SHL . •,'1—r/ ' ` r ' KEt:1 PA - 1 ADL025519 Sec. 26 Sec. 25 r KUPARUK RNER UNIT l aim ,• r Page 53 ..--_-___--- - J-0Y11a 4CR Legend \ • MPUM-14-SHL • 41her Surface Hales {SHQ ' •1? s, ADL X MPU M-74_TPH Other Bottom Holes {BHL) s�z - - - other Wel Paths + MPU M-14_BHL Cosses,, (USGS 7:63k) F��r 1:301 and Gas Une Boundary \'* Pad Fo 4 mt i R, Milne Point Unit MPU M-14 Well wD04 0 1-250 2,500 Feet `DESA ",1 VD.'t r/! � '17 Sect 14 A7PU M-14 -TPH Sec, 13 Se- ` t6301 MILISE POINT UNR uaa� U013N00SE ' ' 1 , 1,U013N010E ._L. �-- � DL025515—,--1 ADL -025514 , 1 11 r aur -JAL J .-'RC2 . L' Sec 23 l r Sec '24 I SP1633-33 1 4 riz Sc 20 KEt:1 PA - 1 ADL025519 Sec. 26 Sec. 25 r KUPARUK RNER UNIT l aim ,• r Page 53 ..--_-___--- - J-0Y11a 4CR Legend \ • MPUM-14-SHL • 41her Surface Hales {SHQ ' •1? s, ADL X MPU M-74_TPH Other Bottom Holes {BHL) s�z - - - other Wel Paths + MPU M-14_BHL Cosses,, (USGS 7:63k) F��r 1:301 and Gas Une Boundary \'* Pad Fo 4 mt i R, Milne Point Unit MPU M-14 Well wD04 0 1-250 2,500 Feet 32.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-14 SB Producer Drilling Procedure Page 54 12 TM PROJECT _ 9'_G 13 ( SEC fl MIS pp 9 I M -f& ■ X P 1 Y-11 IS I + M-13 Y -1i ■ M-14 I M-18 + I 23 1 v1E E I + M-15 .(rwIE+E U M-16 VICINITY MAP HIS I I �P•�E.sF•A.<9S�F s>r .... .............. ....... .,. �, I I Y -N ■ I Tim981 . Bmtart M_� ■ 10200 GRAPHIC SCALE[ MOOSE PAD / D IOD m0 Am "TESICMK { N EE ) I wm .ADD n. SURVEYOR'S CERTIFICATE; C/�Cw�A' I EGEND• �,,.ITCL' yyyy� ,6,P(9. IERTN'T T T 1 /JI .ai-fJRT CWDMCTPI 1. ALASKA STATE 0.ANE WDSH m ARE NAC27, 1DNE A flNCm R MD SIl AIO LIRA N TD PRIAM 2 OEODE9C POS9g1J ME RADJ7. A41D KA AND THI S IL AE ARO ■ EASTNE C4IWCTCR J SASS DE N:01 Mk ND Y9f m CEATRIX R AS -BUILT MES A W RVEY WM o B" m UW�d In DKV SM_nLCAY SAND AE SWERY190N MND MAT MLI. & MN M001E AIERCME PAC) S FAC 3R 6 C.HkN111 OWDSIONS AND OWER DETAILS ARE WNPECT AS 6 iESSYA0.Y 2E, ]CAA 5 001E OE "W MONYMT M =a S RETWICE F' • NOGIL ml -W P 11"1& LOCATED WITHIN PROTRACTED SEC. 14, T. 13 N., R. 9 E., UMIAT MERIDIAN, ALASKA WELL A.SY. PLANT I GEODETIC GEODETIC SECTION PAD CELLAR NQ COORDINATES COORDINATES I POSITION DNS POSITION D.Db OFFSETS ELEVATION BOX EL M-73 Y- 6,027.765.70 N- 1,16804 7079'12-776' 7D.4868822' 4.913' FSL 25.0' 24.7' X= 533,993.84 E= 1,995.03 149'43'19.788" 149.7221572' 171' FEL M-14 Y= 6,027,765.67 N- 1,16&02 70'29'12.780" 7D.4868833' 4,913' FSL yS0' 21.7' X- 533,903.60 E- 1,9D4.98 149'43'22.415" 149.7228931' 281' FEL M-15 Y= 6.027,765.69 N= 1,168.04 7079'12.784" 70.4888845' 4,914' FSL 23.1' 24.Y X- 533.813.87 E- 1.815.05 149'4325.061" 149.7236281' 351' FEL N-16 Y- 6.027.755.37 N- 1.167.73 7029'12.785" 70.4868847 4.914' FSL 25,1' 24.9' X= 533,724.10 E= 1,725.26 149'43'27.703' 149.7243619' 441' FEL M-16 Y= 6,027,889.58 N- 1,291.95 7029'14.001" 70.4872226' 5,037 FSL 2S 0' 24.9' X- 533,843.66 E- 1,844.84 149'43'24.168' 149.7233800' 32Y FEL aska • 2 bell �RmkOrpAI MPU MOOSE PAD �r - ADC AS -BUILT CONDUCTORS WELLS 13,14,15,16.18 1 s l Page 54 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD Mw, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 ,-.r , 500 1000 1500 2000 x 0 2500 3000 3500 4000 4500 Page 55 —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-14 SB Producer Hilco ee e Drilling Procedure 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD Mw, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 ,-.r , 500 1000 1500 2000 x 0 2500 3000 3500 4000 4500 Page 55 —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) K Hilcc,2 eon c.,. Milne Point Unit M-14 SB Producer Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD In. 5.000 Pipe Body Wall TNclmess 0.362 Pipe Body Grade S-135 Drill Pipe Length RVW2 Connection GPDS50 Tod Joint 00 6.625 Tool Joint ID In 3250 Pin Tong 9 Box Tong 1n: 12 60 % IMectlon Class Nominal Weight Designation 19.50 Ddll Pipe Approximate Length fro 31.5 SmooBefAge Height tun 3(32 Raised Tool Joint SMYS 120 DOD Upset Type IEU Max Upset OD (DTE) u015"125 Friction Factor 11.0 Ntle'. TOnq..[. may and. ..n9 Drill Pipe Performance Drill -Pips Length Range2 100 100 Connection Performance Pipe with Pipe Body at Nominal (. zarsW) 2329 0.36 0.0085 072 0.0172 Tension Only 0560.800 Drill Size _ 11113.125 mnNnee�32.100 467.400 1Ndld.oelaid darmldduamaxusdal- I,nim orll q,d ass Ny valu, art Best n,amxs and nvyv ydl.em qR mss' RIII blfmrtt, lnlemul G1a'c oWind and oder na Ym. GPDS50 ( 6.625 m) OD X 3250 ral ID ) 120,000 clop �A-d-d IT..., T`"Se"a Tool Joint Dimensions 9alenced 00 nn 6.435 Woad nT,AJms100brAPl 5,930 PmGmrt.. In, Nlrenldn TdAJdsnaofa 5.93 cdan. 111 Elevator OD 3732 Raised Win TJ OD for ,emtum Class NO1e.ak•,'1c"1pa""ea:ee dd ra.na Ele.me.edK.nd.�a. raew,aw emm:o-esdr lio.loly:l. Assumed Elevator Bore Diameter I'++5219 Ndle:arIDaM et..Les oo moda:e:aia.xrc�mrr..rmwl adn�no l.dxe-,le mlen<. Pipe Body Slip Crushing Capacity Pipe Body Configurafion ( 5 r^) OD 0.362 (") Wall S-135) Pipe Body Performance I ^' 1 I .Gran; Page 56 Pile Body Configuration ( 5 (n) OD 0.362 rid) Wall S-135) ""m Tu """, canne[Im oaeMvnal "asled lfJi,T11 � 3`r.!Cd (IIAaSI msuN Ee aGGlkt1 API Premium Class Pipe Tensile §jMa Tod Joint Torsional Strength nucal 71,800 Pipe Torsional Strength (a-,- 74,100 To.Jdnt Tensile Strength can 1,250.000 0.97 Elevator Shoulder Information 124 80% Pipe Torsional Strength SmoothEdge Height 46.500 3132 Raised Burst r 17.105 Boz OD 1101 6.812 Collapse Iodl 15.672 Elevator Capad nada 1,658,000 Elevator OD 3732 Raised Win TJ OD for ,emtum Class NO1e.ak•,'1c"1pa""ea:ee dd ra.na Ele.me.edK.nd.�a. raew,aw emm:o-esdr lio.loly:l. Assumed Elevator Bore Diameter I'++5219 Ndle:arIDaM et..Les oo moda:e:aia.xrc�mrr..rmwl adn�no l.dxe-,le mlen<. Pipe Body Slip Crushing Capacity Pipe Body Configurafion ( 5 r^) OD 0.362 (") Wall S-135) Pipe Body Performance I ^' 1 I .Gran; Page 56 Pile Body Configuration ( 5 (n) OD 0.362 rid) Wall S-135) NIXe: NrnLui eua adind4 an e6Ra'N Pd API Nominal 80 % Inspection Class API Premium Class Pipe Tensile §jMa oval 712100 560810 560,800 Pipe Torsional Strength (a-,- 74,100 56.100 58,100 TJIPipeBody Torsional Ratio 0.97 1.24 124 80% Pipe Torsional Strength 59.300 46.500 46.500 Burst r 17.105 15.638 15638 Collapse Iodl 15.672 10.029 10.029 Pipe OD IN) 5.000 4.855 4.855 Wall Thickness an 0-362 0290 0290 Nominal Pips to (aa 4276 4276 4276 Cross Sectional Area of Pipe Body na^21 5.275 4.154 4.154 Cmss Sectional Area of GD n^2) 19.635 18.514 18.514 Cross Sectional Area of ID 11.21 14.360 14.360 14.360 $action Modulus cn•s 5.708 14A76 4.476 Polar Section Modulus n,A3, 11.415 1&953 8.953 NIXe: NrnLui eua adind4 an e6Ra'N Pd API H Hilcorp � C�, Milne Point Unit M-14 SB Producer Drilling Procedure 500204050016200 Weatherford 5" 19.50 Ib/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5' XH & 4-12" IF Upset Type IEU Nominal Weight per Foot 1950.lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4' API Drift 3-1/8' Rabbit OD. Suggested 3-1/16' Minimum Make-up Torque 25,900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Strength 51.700 ft -lbs Tensile Strength 1.269.000 lbs TUBE DATA New Premium Outside Diameter 5.000" 4.855" Inside Diameter 4.276" 4.276' Wall Thickness 0.362' 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Loatlrrensile Strength 712.000 lbs 560,800 lbs Slip rushing/ Slip Type (SDXL) 572,100 lbs 453,500 Itis Burst Pressure 17,100 psi 16.100 psi Collapse Pressure 15,700 psi 10.000 psi Torsional Yield Strength 74,100 ft -lbs 58.100 ft -lbs Capacity W/ Tool Joint 0.726 US gaVtt 0.726 US gallft Dis lacement W/ Tool Joint 0.353 US oaVft 0.322 US galtft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 57 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-14 MPU M-14 Plan: MPU M-14 wp04 Standard Proposal Report 14 March, 2019 HALLIBURTON Sperry Drilling Services JCV IMV UCIMILJ Project., Milne Point Site: MPt Moose Pad sec l Inc .00 ND +N/ -S +0.00 ( )leg TFace VSect0.00 Target P 1 3-.. J 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 Well: Plan: MPU M-14 2 380.00 0.00 0.00 380.00 0.00 0.00 0.00 0.00 0.00 fellbore: MPU M-14 3 580.00 6.00 144.00 579.63 -8.46 6.15 3.00 144.00 9.89 E 4 1165.38 29.42 144.22 1133.41 -151.84 109.62 4.00 0.27 176.82 E Design: MPUM-14wp04 5 3440.74 29.42 144.22 3115.43 -1058.44 763.00 0.00 0.00 1231.59 E 6 4852.95 84.00 124.94 3866.14 -1803.31 1611.27 4.00 -23.19 2353.53 E ALLIBURTON 7 5352.95 84.00 124.94 3918.40 -2088.10 2018.90 0.00 0.00 2850.80 McClellan Heel wp02 S 8 5498.98 89.84 124.93 3926.24 -2171.57 2138.39 4.00 -0.06 2996.55 E 9 17096.66 89.84 124.93 3958.40 -8812.72 11646.30 0.00 0.00 14594.19 McClellan toe wp02 10 17900.00 89.84 124.93 3960.63 -9272.73 12304.88 0.00 0.00 15397.52 T ® WELL DETAILS: Plan: MPU W14 DDI = 7.074 Gmund Level: 24.70 T REFERENCE INFORMATION +N/ -S aEl-W Nonhing Eazting LatiOude Longitude 3878 0,00 0.00 602M.6] 533903.80 7W 29' 12.7]98 N 149' 43' 22.4151 W 3960. -ordinate (N/E) Reference: Well Plan: MPU M-14, True North Vertical TVD) Reference: M-14 wp04 RKB @ 58.40usft easuned Depth Reference: M-14 wp04 RKB @ 58.40usft calculation Method: Minimum Curvature Hilcerp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Enor Surface: Pedal Curve Warning Method: Error Ratio _1000- 4 1000 me 00 Start Dir 3°/100' : 380' MD, 380'ND �O �yq 0 r �O Start Dir 4°/100' :580' MD, 579.63'ND ^?^' S� � 5W End Dir : 1165.38' MD, 1133.41' ND O n p. 1000 o,^. 45� b N 0 oy IV a 20 s o°h O' y 2000 `' 0 00 . p b 0 046 p m 5 a gOOQ NO ` Op ck0 D 3000'3y0� - a , ' a Q� 0 0 0 454 a Ipe $ �c 9 5/8' 12 1/4" 5000 McClellan Heel wp02 - -1000 0 1000 2000 3000 4000 5000 6000 O O N N lJ fJ A A N N Ol N O N O N O N O 41 O N O N O N O O O O O O O O O O O O O O O O O O O O O O O O O O O O Me 7000 8000 9000 10000 11000 12000 13000 140, Vertical Section at 124.93° (2000 usft/in) Data: 2018-10-02T00:0f Depth From Depth To 33.70 5352.95 5352.95 179G0.00 O O N N lJ fJ A A N N Ol N O N O N O N O 41 O N O N O N O O O O O O O O O O O O O O O O O O O O O O O O O O O O Me 7000 8000 9000 10000 11000 12000 13000 140, Vertical Section at 124.93° (2000 usft/in) 0 -750 -3000 Sun Din 3-1100': 380' Nm, 389TVD oo ---Sun Dir 4°/100': 580' MD, 579.63T �5 ryS� Sun Du 4°/100': 3440.74' MD, 3115.43'TVD h5 A�yo End Dir :4852.95'MD, 3866.14 -TVD- Stud ESP ungenc Sun Dir 4°/100' : 5352.95' MD, 3918.4'TVD 9 5/8' 12 1/4"- - - - - - - - - - End Dir : 5498.98' MD, 3926.24' TVD WC1.11an Hce1 w,02 - CASING DETAILS vD TVDSS MD Size Name 3918.40 3860.00 5352.95 9-5/8 95/8'121/4" 3960.63 390223 17900A0 6-5/8 6 5/8" x 8 1/2" HALLIBURTON � 1 BPerry 0,1111ng +NI -S +E/ -W 0.00 0.00 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 West( -)/East(+) (1500 usft/in) Gro NOMing 6027765.67 Ce M C 9750 f050 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-14 M-14 wp04 IRKS @ 58.40usft M-14 wp04 RKB @ 58.40usft True Minimum Curvature project Milne Point, ACT, MILNE POINT Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: From: Map Position Uncertainty: Northing: Easting: 0.00 usft Slot Radius: 6,027,877.65usft Latitude: 70° 29' 13.9052 N 533,363.92 usft Longitude: 149' 43'38.2855 W 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M-14 Well Position +N/ -S 0.00 usft Northing: 6,027,765.67 usfl Latitude: 70° 29' 12.7798 N +E1 -W 0.00 usft Easting: 533,903.80 usfl Longitude: 149'43'22.4151 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 24.70 usft Wellbore MPU M-14 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2018 4/112019 16.71 80.96 57,430.93568750 Design MPU M-14 wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +NIS +EI -W Direction (usft) (usft) (usft) (I 33.70 0-00 0-00 124.93 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/S +E/ -W Rate Rate Rate Tool Face (usft) (") (") (usft) usft (usft) (usft) (°/100usft) ("/100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -2470 0.00 0.00 0.00 0.00 0.00 0.00 380.00 0.00 0.00 380.00 321.60 0.00 0.00 0.00 0.00 0.00 0.00 580.00 6.00 144.00 579.63 521.23 -8.46 6.15 3.00 3.00 0.00 144.00 1,165.38 29.42 144.22 1,133.41 1,075.01 -151.84 109.62 4.00 4.00 0.04 0.27 3,440.74 29.42 144.22 3,115.43 3,057.03 -1,058.44 763.00 0.00 0.00 0.00 0.00 4,852.95 84.00 124.94 3,866.14 3,807.74 -1,803.31 1,611.27 4.00 3.87 -1.37 -23.19 5,352.95 84.00 124.94 3,918.40 3,860.00 -2,088.10 2,018.90 0.00 0.00 0.00 0.00 5,498.98 89.84 124.93 3,926.24 3,867.84 -2,171.57 2,138.39 4.00 4.00 0.00 -0.06 17,096.66 89.84 124.93 3,958.40 3,900.00 -8,812.72 11,646.30 0.00 0.00 0.00 0.00 17,900.00 89.84 124.93 3,960.63 3,902.23 -9,272.73 12,304.88 0.00 0.00 0.00 0.00 3/14/2019 12:41:13PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (I (usft) usft 33.70 0.00 0.00 M-14 wp04 RKB @ 58.40usft 33.70 -24.70 100.00 0.00 0.00 Easting 100.00 41.60 200.00 0.00 0.00 (usft) 200.00 141.60 300.00 0.00 0.00 533,903.80 300.00 241.60 380.00 0.00 0.00 533,903.80 380.00 321.60 Start Dir 3°/100' : 380' MD, 380'TVD 533,903.80 400.00 0.60 144.00 0.00 400.00 341.60 500.00 3.60 144.00 0.00 499.92 441.52 580.00 6.00 144.00 0.06 579.63 52123 Start Dir 40/100' : 580' MD, 579.63'TVD 2.22 6,027,762.63 600.00 6.80 144.03 -8.46 599.51 541.11 700.00 10.80 144.12 -10.27 698.31 639.91 800.00 14.80 144.16 -22.66 795.81 737.41 900.00 18.80 144.19 -40.61 891.52 833.12 1,000.00 22.80 144.20 -64.04 984.98 926.58 1,100.00 26.80 144.21 -92.83 1,075.74 1,017.34 1,165.38 29.42 144.22 -126.85 1,133.41 1,075.01 End Dir : 1165.38' MD, 1133.41' TVD 109.62 1,200.00 29.42 144.22 176.81 1,163.56 1,105.16 1,300.00 29.42 144.22 192.86 1,250.67 1,192.27 1,400.00 29.42 144.22 239.22 1,337.78 1,279.38 1,500.00 29.42 144.22 285.57 1,424.89 1,366.49 1,600.00 29.42 144.22 331.93 1,512.00 1,453.60 1,700.00 29.42 144.22 378.29 1,599.11 1,540.71 1,800.00 29.42 144.22 424.64 1,686.21 1,627.81 1,900.00 29.42 144.22 471.00 1,773.32 1,714.92 2,000.00 29.42 144.22 517.36 1,860.43 1,802.03 2,100.00 29.42 144.22 563.71 1,947.54 1,889.14 2,200.00 29.42 144.22 610.07 2,034.65 1,976.25 2,300.00 29.42 144.22 656.42 2,121.76 2,063.36 2,400.00 29.42 144.22 702.78 2,208.86 2,150.46 2,500.00 29.42 144.22 749.14 2,295.97 2,237.57 2,600.00 29.42 144.22 795.49 2,383.08 2,324.68 2,700.00 29.42 144.22 841.85 2,470.19 2,411.79 2,800.00 29.42 144.22 888.21 2,557.30 2,498.90 2,900.00 29.42 144.22 934.56 2,644.40 2,586.00 3,000.00 29.42 144.22 980.92 2,731.51 2,673.11 3,100.00 29.42 144.22 1,027.27 2,818.62 2,760.22 3,200.00 29.42 144.22 1,073.63 2,905.73 2,847.33 3,300.00 29,42 144.22 1,119.99 2,992.84 2,934.44 3,400.00 29.42 144.22 1,166.34 3,079.95 3,021.55 3,440.74 29.42 144.22 1,212.70 3,115.43 3,057.03 Start Dir 4°/100' : 3440.74' MD, 3115.43'TVD 3,500.00 31.61 142.44 3,166.49 3,108.09 3,600.00 35.35 139.89 3,249.88 3,191.48 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-14 TVD Reference: M-14 wp04 RKB @ 58.40usft MD Reference: M-14 wp04 RKB @ 58.40usft North Reference: True Survey Calculation Method: Minimum Curvature -1,082.56 780.98 6,026,686.78 534,689.63 4.00 1,260.13 -1,125.48 815.60 6,026,644.03 534,724.44 4.00 1,313.09 3/142019 12:41:13PM Page 3 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -24.70 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 0.00 0.00 6,027,765.67 533,903.80 0.00 0.00 -0.08 0.06 6,027,765.59 533,903.86 3.00 0.10 -3.05 2.22 6,027,762.63 533,906.03 3.00 3.56 -8.46 6.15 6,027,757.23 533,909.99 3.00 9.89 -10.27 7.46 6,027,755.44 533,911.31 4.00 12.00 -22.66 16.43 6,027,743.09 533,920.33 4.00 26.44 -40.61 29.41 6,027,725.20 533,933.39 4.00 47.36 -64.04 46.32 6,027,701.85 533,950.41 4.00 74.64 -92.83 67.09 6,027,673.15 533,971.30 4.00 108.16 -126.85 91.61 6,027,639.25 533,995.98 4.00 147.74 -151.84 109.62 6,027,614.35 534,014.10 4.00 176.81 -165.63 119.56 6,027,600.60 534,024.11 0.00 192.86 -205.48 148.28 6,027,560.89 534,053.00 0.00 239.22 -245.32 176.99 6,027,521.18 534,081.89 0.00 285.57 -285.16 205.71 6,027,481.47 534,110.79 0.00 331.93 -325.01 234.43 6,027,441.76 534,139.68 0.00 378.29 -364.85 263.14 6,027,402.06 534,168.57 0.00 424.64 -404.70 291.86 6,027,362.35 534,197.47 0.00 471.00 -444.54 320.57 6,027,322.64 534,226.36 0.00 517.36 -484.39 349.29 6,027,282.93 534,255.26 0.00 563.71 -524.23 378.00 6,027,243.22 534,284.15 0.00 610.07 -564.08 406.72 6,027,203.51 534,313.04 0.00 656.42 -603.92 435.43 6,027,163.80 534,341.94 0.00 702.78 -643.77 464.15 6,027,124.09 534,370.83 0.00 749.14 -683.61 492.86 6,027,084.38 534,399.72 0.00 795.49 -723.46 521.58 6,027,044.67 534,428.62 0.00 841.85 -763.30 550.29 6,027,004.96 534,457.51 0.00 888.21 -803.14 579.01 6,026,965.25 534,486.41 0.00 934.56 -842.99 607.72 6,026,925.54 534,515.30 0.00 980.92 -882.83 636.44 6,026,885.83 534,544.19 0.00 1,027.27 -922.68 665.15 6,026,846.12 534,573.09 0.00 1,073.63 -962.52 693.67 6,026,806.42 534,601.98 0.00 1,119.99 -1,002.37 722.58 6,026,766.71 534,630.88 0.00 1,166.34 -1,042.21 751.30 6,026,727.00 534,659.77 0.00 1,212.70 -1,058.44 763.00 6,026,710.82 534,671.54 0.00 1,231.59 -1,082.56 780.98 6,026,686.78 534,689.63 4.00 1,260.13 -1,125.48 815.60 6,026,644.03 534,724.44 4.00 1,313.09 3/142019 12:41:13PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-14 TVD Reference: M-14 wp04 RKB @ 58.40usft MD Reference: M-14 wp04 RKB @ 58.40usft 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) (1) (") (usft) usft (usft) (usft) (usft) (usft) 3,271.08 3,700.00 39.14 137.77 3,329.48 3,271.08 -1,170.99 855.47 6,026,598.70 534,764.51 4.00 1,371.84 3,800.00 42.96 135.97 3,404.88 3,346.48 -1,218.89 900.38 6,026,551.02 534,809.64 4.00 1,436.08 3,900.00 46.81 134.42 3,475.71 3,417.31 -1,268.92 950.12 6,026,501.22 534,859.60 4.00 1,505.51 4,000.00 50.68 133.05 3,541.65 3,483.25 -1,320.86 1,004.45 6,026,449.53 534,914.16 4.00 1,579.79 4,100.00 54.55 131.82 3,602.35 3,543.95 -1,374.44 1,063.10 6,026,396.22 534,973.04 4.00 1,658.55 4,200.00 58.45 130.71 3,657.54 3,599.14 -1,429.42 1,125.78 6,026,341.54 535,035.97 4.00 1,741.42 4,300.00 62.35 129.68 3,706.93 3,648.53 -1,485.51 1,192.19 6,026,285.76 535,102.63 4.00 1,827.98 4,400.00 66.25 128.73 3,750.29 3,691.89 -1,542.44 1,262.00 6,026,229.15 535,172.69 4.00 1,917.82 4,500.00 70.16 127.83 3,787.41 3,729.01 -1,599.95 1,334.88 6,026,171.98 535,245.83 4.00 2,010.49 4,600.00 74.08 126.98 3,818.10 3,759.70 -1,657.74 1,410.47 6,026,114.54 535,321.67 4.00 2,105.56 4,700.00 78.00 126.15 3,842.22 3,783.82 -1,715.53 1,488.41 6,026,057.11 535,399.86 4.00 2,202.55 4,800.00 81.92 125.36 3,859.65 3,801.25 -1,773.06 1,568.30 6,025,999.96 535,480.01 4.00 2,300.98 4,852.95 84.00 124.94 3,866.14 3,807.74 -1,803.31 1,611.27 6,025,969.90 535,523.11 4.00 2,353.53 End Dir : 4852.95' MD, 3866.14' TVD - Start ESP tangent 4,900.00 84.00 124.94 3,871.05 3,812.65 -1,830.11 1,649.63 6,025,943.28 535,561.59 0.00 2,400.32 5,000.00 84.00 124.94 3,881.51 3,823.11 -1,887.06 1,731.15 6,025,886.70 535,643.37 0.00 2,499.78 5,100.00 84.00 124.94 3,891.96 3,833.56 -1,944.02 1,812.68 6,025,830.12 535,725.14 0.00 2,599.23 5,200.00 84.00 124.94 3,902.41 3,844.01 -2,000.98 1,894.21 6,025,773.54 535,806.92 0.00 2,698.68 5,300.00 84.00 124.94 3,912.86 3,854.46 -2,057.94 1,975.73 6,025,716.96 535,888.70 0.00 2,798.13 5,352.95 84.00 124.94 3,918.40 3,860.00 -2,088.10 2,018.90 6,025,687.00 535,932.00 0.00 2,850.79 Start Dir 40/100' : 5352.95' MD, 3918.4'TVD - 9 518'12 1/4" 5,400.00 85.88 124.94 3,922.55 3,864.15 -2,114.94 2,057.32 6,025,660.34 535,970.53 4.00 2,897.66 5,498.98 89.84 124.93 3,926.24 3,867.84 -2,171.57 2,138.39 6,025,604.09 536,051.85 4.00 2,996.55 End Dir : 5498.98' MD, 3926.24' TVD 5,500.00 89.84 124.93 3,926.24 3,867.84 -2,172.15 2,139.22 6,025,603.50 536,052.69 0.01 2,997.57 5,600.00 89.84 124.93 3,926.52 3,868.12 -2,229.42 2,221.21 6,025,546.62 536,134.93 0.00 3,097.57 5,700.00 89.84 124.93 3,926.80 3,868.40 -2,286.68 2,303.19 6,025,489.74 536,217.16 0.00 3,197.57 5,800.00 89.84 124.93 3,927.08 3,868.68 -2,343.94 2,385.17 6,025,432.86 536,299.39 0.00 3,297.57 5,900.00 89.84 124.93 3,927.35 3,868.95 -2,401.20 2,467.15 6,025,375.97 536,381.62 0.00 3,397.57 6,000.00 89.84 124.93 3,927.63 3,869.23 -2,458.47 2,549.13 6,025,319.09 536,463.86 0.00 3,497.57 6,100.00 89.84 124.93 3,927.91 3,869.51 -2,515.73 2,631.11 6,025,262.21 536,546.09 0.00 3,597.57 6,200.00 89.84 124.93 3,928.19 3,869.79 -2,572.99 2,713.09 6,025,205.33 536,628.32 0.00 3,697.57 6,300.00 89.84 124.93 3,928.46 3,870.06 -2,630.25 2,795.07 6,025,148.44 536,710.56 0.00 3,797.57 6,400.00 89.84 124.93 3,928.74 3,870.34 -2,687.52 2,877.05 6,025,091.56 536,792.79 0.00 3,897.57 6,500.00 89.84 124.93 3,929.02 3,870.62 -2,744.78 2,959.04 6,025,034.68 536,875.02 0.00 3,997.56 6,600.00 89.84 124.93 3,929.29 3,870.89 -2,802.04 3,041.02 6,024,977.79 536,957.26 0.00 4,097.56 6,700.00 89.84 124.93 3,929.57 3,871.17 -2,859.31 3,123.00 6,024,920.91 537,039.49 0.00 4,197.56 6,800.00 89.84 124.93 3,929.85 3,871.45 -2,916.57 3,204.98 6,024,864.03 537,121.72 0.00 4,297.56 6,900.00 89.84 124.93 3,930.13 3,871.73 -2,973.83 3,286.96 6,024,807.15 537,203.96 0.00 4,397.56 7,000.00 89.84 124.93 3,930.40 3,872.00 -3,031.09 3,368.94 6,024,750.26 537,286.19 0.00 4,497.56 7,100.00 89.84 124.93 3,930.68 3,872.28 -3,088.36 3,450.92 6,024,693.38 537,368.42 0.00 4,597.56 7,200.00 89.84 124.93 3,930.96 3,872.56 -3,145.62 3,532.90 6,024,636.50 537,450.66 0.00 4,697.56 7,300.00 89.84 124.93 3,931.24 3,872.84 -3,202.88 3,614.88 6,024,579.61 537,532.89 0.00 4,797.56 7,400.00 89.84 124.93 3,931.51 3,873.11 -3,260.14 3,696.87 6,024,522.73 537,615.12 0.00 4,897.56 7,500.00 89.84 124.93 3,931.79 3,873.39 -3,317.41 3,778.85 6,024,465.85 537,697.36 0.00 4,997.56 31142019 12.,41:13PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 7,600.00 89.84 124.93 3,932.07 3,873.67 7,700.00 89.84 124.93 3,932.34 3,873.94 7,800.00 89.84 124.93 3,932.62 3,874.22 7,900.00 89.84 124.93 3,932.90 3,874.50 8,000.00 89.84 124.93 3,933.18 3,874.78 8,100.00 89.84 124.93 3,933.45 3,875.05 8,200.00 89.84 124.93 3,933.73 3,875.33 8,300.00 89.84 124.93 3,934.01 3,875.61 8,400.00 89.84 124.93 3,934.29 3,875.89 8,500.00 89.84 124.93 3,934.56 3,876.16 8,600.00 89.84 124.93 3,934.84 3,876.44 8,700.00 89.84 124.93 3,935.12 3,876.72 8,800.00 89.84 124.93 3,935.39 3,876.99 8,900.00 89.84 124.93 3,935.67 3,877.27 9,000.00 89.84 124.93 3,935.95 3,877.55 9,100.00 89.84 124.93 3,936.23 3,877.83 9,200.00 89.84 124.93 3,936.50 3,878.10 9,300.00 89.84 124.93 3,936.78 3,878.38 9,400.00 89.84 124.93 3,937.06 3,878.66 9,500.00 89.84 124.93 3,937.34 3,878.94 9,600.00 89.84 124.93 3,937.61 3,879.21 9,700.00 89.84 124.93 3,937.89 3,879.49 9,800.00 89.84 124.93 3,938.17 3,879.77 9,900.00 89.84 124.93 3,938.44 3,880.04 10,000.00 89.84 124.93 3,938.72 3,880.32 10,100.00 89.84 124.93 3,939.00 3,880.60 10,200.00 89.84 124.93 3,939.28 3,880.88 10,300.00 89.84 124.93 3,939.55 3,881.15 10,400.00 89.84 124.93 3,939.83 3,881.43 10,500.00 89.84 124.93 3,940.11 3,881.71 10,600.00 89.84 124.93 3,940.39 3,881.99 10,700.00 89.84 124.93 3,940.66 3,882.26 10,800.00 89.84 124.93 3,940.94 3,882.54 10,900.00 89.84 124.93 3,941.22 3,882.82 11,000.00 89.84 124.93 3,941.49 3,883.09 11,100.00 89.84 124.93 3,941.77 3,883.37 11,200.00 89.84 124.93 3,942.05 3,883.65 11,300.00 89.84 124.93 3,942.33 3,883.93 11,400.00 89.84 124.93 3,942.60 3,884.20 11,500.00 89.84 124.93 3,942.88 3,884.48 11,600.00 89.84 124.93 3,943.16 3,884.76 11,700.00 89.64 124.93 3,943.44 3,885.04 11,800.00 89.84 124.93 3,943.71 3,885.31 11,900.00 89.84 124.93 3,943.99 3,885.59 12,000.00 89.84 124.93 3,944.27 3,885.87 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-14 M-14 wp04 RKB @ 58.40usft M-14 wp04 RKB @ 58.40usft True Minimum Curvature 3/142019 12:41:13PM Page 5 COMPASS 5000.15 Build 91 Map Map +NI -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,873.67 -3,374.67 3,860.83 6,024,408.97 537,779.59 0.00 5,097.56 -3,431.93 3,942.81 6,024,352.08 537,861.82 0.00 5,197.56 -3,489.20 4,024.79 6,024,295.20 537,944.06 0.00 5,297.56 -3,546.46 4,106.77 6,024,238.32 538,026.29 0.00 5,397.56 -3,603.72 4,188.75 6,024,181.44 538,108.52 0.00 5,497.56 -3,660.98 4,270.73 6,024,124.55 538,190.76 0.00 5,597.56 -3,718.25 4,352.71 6,024,067.67 538,272.99 0.00 5,697.56 -3,775.51 4,434.70 6,024,010.79 538,355.22 0.00 5,797.56 -3,832.77 4,516.68 6,023,953.90 538,437.45 0.00 5,897.56 -3,890.03 4,598.66 6,023,897.02 538,519.69 0.00 5,997.56 -3,947.30 4,680.64 6,023,840.14 538,601.92 0.00 6,097.56 -4,004.56 4,762.62 6,023,783.26 538,684.15 0.00 6,197.56 -4,061.82 4,844.60 6,023,726.37 538,766.39 0.00 6,297.56 4,119.09 4,926.58 6,023,669.49 538,848.62 0.00 6,397.56 -4,176.35 5,008.56 6,023,612.61 538,930.85 0.00 6,497.56 -4,233.61 5,090.54 6,023,555.72 539,013.09 0.00 6,597.55 -4,290.87 5,172.53 6,023,498.84 539,095.32 0.00 6,697.55 -4,348.14 5,254.51 6,023,441.96 539,177.55 0.00 6,797.55 -4,405.40 5,336.49 6,023,385.08 539,259.79 0.00 6,897.55 -4,462.66 5,418.47 6,023,328.19 539,342.02 0.00 6,997.55 -4,519.92 5,500.45 6,023,271.31 539,424.25 0.00 7,097.55 4,577.19 5,582.43 6,023,214.43 539,506.49 0.00 7,197.55 4,634.45 5,664.41 6,023,157.55 539,588.72 0.00 7,297.55 -4,691.71 5,746.39 6,023,100.66 539,670.95 0.00 7,397.55 -4,748.98 5,828.37 6,023,043.78 539,753.19 0.00 7,497.55 -4,806.24 5,910.36 6,022,986.90 539,835.42 0.00 7,597.55 4,863.50 5,992.34 6,022,930.01 539,917.65 0.00 7,697.55 4,920.76 6,074.32 6,022,873.13 539,999.89 0.00 7,797.55 4,978.03 6,156.30 6,022,816.25 540,082.12 0.00 7,897.55 -5,035.29 6,238.28 6,022,759.37 540,164.35 0.00 7,997.55 -5,092.55 6,320.26 6,022,702.48 540,246.58 0.00 8,097.55 -5,149.81 6,402.24 6,022,645.60 540,328.82 0.00 8,197.55 -5,207.08 6,484.22 6,022,588.72 540,411.05 0.00 8,297.55 -5,264.34 6,566.20 6,022,531.83 540,493.28 0.00 8,397.55 -5,321.60 6,648.19 6,022,474.95 540,575.52 6.00 8,497.55 -5,378.87 6,730.17 6,022,418.07 540,657.75 0.00 8,597.55 -5,436.13 6,812.15 6,022,361.19 540,739.98 0.00 8,697.55 -5,493.39 6,894.13 6,022,304.30 540,822.22 0.00 8,797.55 -5,550.65 6,976.11 6,022,247.42 540,904.45 0.00 8,897.55 -5,607.92 7,058.09 6,022,190.54 540,986.68 0.00 8,997.55 -5,665.18 7,140.07 6,022,133.66 541,068.92 0.00 9,097.55 -5,722.44 7,222.05 6,022,076.77 541,151.15 0.00 9,197.54 -5,779.70 7,304.03 6,022,019.89 541,233.38 0.00 9,297.54 -5,836.97 7,386.02 6,021,963.01 541,315.62 0.00 9,397.54 -5,894.23 7,468.00 6,021,906.12 541,397.85 0.00 9,497.54 3/142019 12:41:13PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Vertical Northing Easting Di Depth Inclination Azimuth Depth TVDss +NIS +E/ -W (usft) (°) (°) (usft) usft (usft) (usft) 12,100.00 89.84 124.93 3,944.54 3,886.14 -5,951.49 7,549.98 12,200.00 89.84 124.93 3,944.82 3,886.42 -6,008.76 7,631.96 12,300.00 89.84 124.93 3,945.10 3,886.70 -6,066.02 7,713.94 12,400.00 89.84 124.93 3,945.38 3,886.98 -6,123.28 7,795.92 12,500.00 89.84 124.93 3,945.65 3,887.25 -6,180.54 7,877.90 12,600.00 89.84 124.93 3,945.93 3,887.53 -6,237.81 7,959.88 12,700.00 89.84 124.93 3,946.21 3,887.81 -6,295.07 8,041.86 12,800.00 89.84 124.93 3,946.49 3,888.09 -6,352.33 8,123.85 12,900.00 89.84 124.93 3,946.76 3,888.36 -6,409.59 8,205.83 13,000.00 89.84 124.93 3,947.04 3,888.64 -6,466.86 8,287.81 13,100.00 89.84 124.93 3,947.32 3,888.92 -6,524.12 8,369.79 13,200.00 89.84 124.93 3,947,60 3,889.20 -6,581.38 8,451.77 13,300.00 89.84 124.93 3,947.87 3,889.47 -6,638.65 8,533.75 13,400.00 89.84 124.93 3,948.15 3,889.75 -6,695.91 8,615.73 13,500.00 89.84 124.93 3,948.43 3,890.03 -6,753.17 8,697.71 13,600.00 89.84 124.93 3,948.70 3,890.30 -6,810.43 8,779.69 13,700.00 89.84 124.93 3,948.98 3,890.58 -6,867.70 8,861.68 13,800.00 89.84 124.93 3,949.26 3,890.86 -6,924.96 8,943.66 13,900.00 89.84 124.93 3,949.54 3,891.14 -6,982.22 9,025.64 14,000.00 89.84 124.93 3,949.81 3,891.41 -7,039.48 9,107.62 14,100.00 89.84 124.93 3,950.09 3,891.69 -7,096.75 9,189.60 14,200.00 89.84 124.93 3,950.37 3,891.97 -7,154.01 9,271.58 14,300.00 89.84 124.93 3,950.65 3,892.25 -7,211.27 9,353.56 14,400.00 89.84 124.93 3,950.92 3,892.52 -7,268.53 9,435.54 14,500.00 89.84 124.93 3,951.20 3,892.80 -7,325.80 9,517.52 14,600.00 89.84 124.93 3,951.48 3,893.08 -7,383.06 9,599.51 14,700.00 89.84 124.93 3,951.75 3,893.35 -7,440.32 9,681.49 14,800.00 89.84 124.93 3,952.03 3,893.63 -7,497.59 9,763.47 14,900.00 89.84 124.93 3,952.31 3,893.91 -7,554.85 9,845.45 15,000.00 89.84 124.93 3,952.59 3,894.19 -7,612.11 9,927.43 15,100.00 89.84 124.93 3,952.86 3,894.46 -7,669.37 10,009.41 15,200.00 89.84 124.93 3,953.14 3,894.74 -7,726.64 10,091.39 15,300.00 89.84 124.93 3,953.42 3,895.02 -7,783.90 10,173.37 15,400.00 89.84 124.93 3,953.70 3,895.30 -7,841.16 10,255.36 15,500.00 89.84 124.93 3,953.97 3,895.57 -7,898.42 10,337.34 15,600.00 89.84 124.93 3,954.25 3,895.85 -7,955.69 10,419.32 15,700.00 89.84 124.93 3,954.53 3,896.13 -8,012.95 10,501.30 15,800.00 89.84 124.93 3,954.80 3,896.40 -8,070.21 10,583.28 15,900.00 89.84 124.93 3,955.08 3,896.68 -8,127.48 10,665.26 16,000.00 89.84 124.93 3,955.36 3,896.96 -8,184.74 10,747.24 16,100.00 89.84 124.93 3,955.64 3,897.24 -8,242.00 10,829.22 16,200.00 89.84 124.93 3,955.91 3,897.51 -8,299.26 10,911.20 16,300.00 89.84 124.93 3,956.19 3,897.79 -8,356.53 10,993.19 16,400.00 89.84 124.93 3,956.47 3,898.07 -8,413.79 11,075.17 16,500.00 89.84 124.93 3,956.75 3,898.35 -8,471.05 11,157.15 Halliburton Standard Proposal Report Well Plan: MPU M-14 M-14 wp04 RKB @ 58.40usft M-14 wp04 RKB @ 58.40usft True Minimum Curvature Map Map Northing Easting Di Vert Section (usft) (usft) 3,886.14 6,021,849.24 541,480.08 0.00 9,597.54 6,021,792.36 541,562.32 0.00 9,697.54 6,021,735.48 541,644.55 0.00 9,797.54 6,021,678.59 541,726.78 0.00 9,897.54 6,021,621.71 541,809.02 0.00 9,997.54 6,021,564.83 541,891.25 0.00 10,097.54 6,021,507.94 541,973.48 0.00 10,197.54 6,021,451.06 542,055.72 0.00 10,297.54 6,021,394.18 542,137.95 0.00 10,397.54 6,021,337.30 542,220.18 0.00 10,497.54 6,021,280.41 542,302.41 0.00 10,597.54 6,021,223.53 542,384.65 0.00 10,697.54 6,021,166.65 542,466.88 0.00 10,797.54 6,021,109.77 542,549.11 0.00 10,897.54 6,021,052.88 542,631.35 0.00 10,997.54 6,020,996.00 542,713.58 0.00 11,097.54 6,020,939.12 542,795.81 0.00 11,197.54 6,020,882.23 542,878.05 0.00 11,297.54 6,020,825.35 542,960.28 0.00 11,397.54 6,020,768.47 543,042.51 0.00 11,497.54 6,020,711.59 543,124.75 0.00 11,597.54 6,020,654.70 543,206.98 0.00 11,697.54 6,020,597.82 543,289.21 0.00 11,797.53 6,020,540.94 543,371.45 0.00 11,897.53 6,020,484.05 543,453.68 0.00 11,997.53 6,020,427.17 543,535.91 0.00 12,097.53 6,020,370.29 543,618.15 0.00 12,197.53 6,020,313.41 543,700.38 0.00 12,297.53 6,020,256.52 543,782.61 0.00 12,397.53 6,020,199.64 543,864.85 0.00 12,497.53 6,020,142.76 543,947.08 0.00 12,597.53 6,020,085.88 544,029.31 0.00 12,697.53 6,020,028.99 544,111.55 0.00 12,797.53 6,019,972.11 544,193.78 0.00 12,897.53 6,019,915.23 544,276.01 0.00 12,997.53 6,019,858.34 544,358.24 0.00 13,097.53 6,019,801.46 544,440.48 0.00 13,197.53 6,019,744.58 544,522.71 0.00 13,297.53 6,019,687.70 544,604.94 0.00 13,397.53 6,019,630.81 544,687.18 0.00 13,497.53 6,019,573.93 544,769.41 0.00 13,597.53 6,019,517.05 544,851.64 0.00 13,697.53 6,019,460.16 544,933.88 0.00 13,797.53 6,019,403.28 545,016.11 0.00 13,897.53 6,019,346.40 545,098.34 0.00 13,997.53 3/1412019 12:41:13PM Page 6 COMPASS 5000.15 Build 91 31142019 12:41:13PM Page 7 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Coordinate Reference: Well Plan: MPU M-14 Company: Hilcorp Alaska, LLC TVD Reference: M-14 wp04 RKB @ 58.40usft Project: Milne Point MD Reference: M-14 wp04 RKB @ 58.40usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-14 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-14 Design: MPU M-14 wp04 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) 3,898.62 16,600.00 89.84 124.93 3,957.02 3,898.62 -8,528.31 11,239.13 6,019,289.52 545,180.58 0.00 14,097.53 16,700.00 89.84 124.93 3,957.30 3,898.90 -8,585.58 11,321.11 6,019,232.63 545,262.81 0.00 14,197.53 16,800.00 89.84 124.93 3,957.58 3,899.18 -8,642.84 11,403.09 6,019,175.75 545,345.04 0.00 14,297.53 16,900.00 89.84 124.93 3,957.85 3,899.45 -8,700.10 11,485.07 6,019,118.87 545,427.28 0.00 14,397.52 17,000.00 89.84 124.93 3,958.13 3,899.73 -8,757.37 11,567.05 6,019,061.99 545,509.51 0.00 14,497.52 17,096.66 89.84 124.93 3,958.40 3,900.00 -8,812.72 11,646.30 6,019,007.00 545,589.00 0.00 14,594.19 17,100.00 89.84 124.93 3,958.41 3,900.01 -8,814.63 11,649.03 6,019,005.10 545,591.74 0.00 14,597.52 17,200.00 89.84 124.93 3,958.69 3,900.29 -8,871.89 11,731.02 6,018,948.22 545,673.98 0.00 14,697.52 17,300.00 89.84 124.93 3,958.96 3,900.56 -8,929.15 11,813.00 6,018,891.34 545,756.21 0.00 14,797.52 17,400.00 89.84 124.93 3,959.24 3,900.84 -8,986.42 11,894.98 6,018,834.45 545,838.44 0.00 14,897.52 17,500.00 89.84 124.93 3,959.52 3,901.12 -9,043.68 11,976.96 6,018,777.57 545,920.68 0.00 14,997.52 17,600.00 89.84 124.93 3,959.80 3,901.40 -9,100.94 12,058.94 6,018,720.69 546,002.91 0.00 15,097.52 17,700.00 89.84 124.93 3,960.07 3,901.67 -9,158.20 12,140.92 6,018,663.81 546,085.14 0.00 15,197.52 17,800.00 89.84 124.93 3,960.35 3,901.95 -9,215.47 12,222.90 6,018,606.92 546,167.38 0.00 15,297.52 17,900.00 89.84 124.93 3,960.63 3,902.23 -9,272.73 12,304.88 6,018,550.04 546,249.61 0.00 15,397.52 Total Depth : 17900' MD, 3960.63' TVD - 6 518" x 8 1/2" Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting - Shape (') (1) (usft) (usft) (usft) (usft) (usft) McClellan Heel wp02 0.00 0.00 3,918.40 -2,088.10 2,018.90 6,025,687.00 535,932.00 - plan hits target center - Circle (radius 50.00) McClellan toe wp02 0.00 0.00 3,958.40 -8,812.72 11,646.30 6,019,007.00 545,589.00 - plan hits target center - Circle (radius 50.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name C) ( ) 5,352.95 3,918.40 9 5/8' 12 1/4" 9-5/8 12-1/4 17,900.00 3,960.63 6 5/8" x 8 1/2" 6-5/8 8-1/2 31142019 12:41:13PM Page 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-14 Wellbore: MPU M-14 Design: MPU M-14 wp04 Plan Annotations Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-14 TVD Reference: M-14 wp04 RKB @ 58.40usft MD Reference: M-14 wp04 RKB @ 58.40usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 380.00 380.00 0.00 0.00 Start Dir 301100': 380' MD, 380'TVD 580.00 579.63 -8.46 6.15 Start Dir 40/100': 580' MD, 579.63'TVD 1,165.38 1,133.41 -151.84 109.62 End Dir : 1165.38' MD, 1133.4l'TVD 3,440.74 3,115.43 -1,058.44 763.00 Start Dir 401100': 3440.74' MD, 3115.43'TVD 4,852.95 3,866.14 -1,803.31 1,611.27 End Dir : 4852.95' MD, 3866.14' TVD - Start ESP tangent 5,352.95 3,918.40 -2,088.10 2,018.90 Start Dir 40/100' : 5352.95' MD, 3918.4'TVD 5,498.98 3,926.24 -2,171.57 2,138.39 End Dir : 5498.98' MD, 3926.24' TVD 17,900.00 3,960.63 -9,272.73 12,304.88 Total Depth : 17900' MD, 3960.63' TVD 3/1412019 12:41:13PM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-14 MPU M-14 MPU M-14 wp04 Sperry Drilling Services Clearance Summary Anticollision Report 14 March, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 Well Coordinates: 6,027,765.67 N, 533,903.80 E (700 29' 12.78" N, 1490 43' 22.42" W) Datum Height: M-14 wp04 RKB @ 58.40usft Scan Range: 33.70 to 5,352.95 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: • • ' Scan Type: 25.00 H Sp HALLIBURTON Anticollision Report for Plan: MPU M -14 -MPU M-14 wp04 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-14- MPU W14 -MPU M-14 wp04 Scan Range: 33.70 to 5,352.95 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summ Site Name Depth Distance Depth Separation Depth Factor A Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M Pt L Pad MPL-20 - MPL-20 - MPL-20 5,352.95 768.90 5,352.95 664.84 12,474.32 7.389 Clearai M Pt Moose Pad MPU M-12 - MPU M-12 - MPU M-12 153.71 127.67 153.71 125.85 154.56 70.320 Centre MPU M-12 - MPU M-12 - MPU M-12 358.70 128.37 358.70 124.75 358.18 35.494 Ellipse MPU M-12 - MPU M-12 - MPU M-12 633.70 158.01 633.70 152.05 615.03 26.490 Clearat MPU M-12 - MPU M-12PB1 - MPU M-12PB1 153.71 127.67 153.71 125.85 154.56 70.320 Centre MPU M-12 - MPU M-12PB1 - MPU M-12PB1 358.70 128.37 358.70 124.75 358.18 35.494 Ellipse MPU M-12 - MPU M-12PB1 - MPU M-12PB1 633.70 158.01 633.70 152.05 615.03 26.490 Clearat MPU M-12 - MPU M-12PB2 - MPU M-12PB2 153.71 127.67 153.71 125.85 154.56 70.320 Centre MPU M-12 - MPU M-12PB2 - MPU M-12PB2 358.70 128.37 358.70 124.75 358.18 35.494 Ellipse MPU M-12 - MPU M-12PB2 - MPU M-12PB2 633.70 158.01 633.70 152.05 615.03 26.490 Clearai Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 723.10 82.58 723.10 76.74 714.42 14.152 Centre Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 733.70 82.60 733.70 76.69 724.64 13.971 Ellipse Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 5,352.95 811.43 5,352.95 707.65 5,443.72 7.819 Clearai Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 358.70 90.68 358.70 87.41 355.00 27.689 Centre Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 408.70 90.83 408.70 8720 405.14 25.037 Ellipse Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 1,958.70 155.24 1,958.70 131.38 1,997.68 6.506 Clearai Plan: MPU M-16 - MPU M-16 - MPU M-16 wp02 358.70 179.72 358.70 176.48 358.90 55.430 Centre Plan: MPU M-16 - MPU M-16 - MPU M-16 wp02 408.70 179.85 408.70 176.25 408.90 50.023 Ellipse Plan: MPU M-16 - MPU M-16 - MPU M-16 wp02 1,708.70 261.11 1,708.70 241.14 1,754.43 13.079 Clearat Rig: MPU M-11 - MPU M-11 - MPU M-11 416.56 167.19 416.56 163.88 418.10 50.511 Centre Rig: MPU M-11 - MPU M-11 - MPU M-11 433.70 167.23 433.70 163.81 434.61 48.837 Ellipse Rig: MPU M-11 - MPU M-11 - MPU M-11 758.70 199.77 758.70 194.17 726.69 35.673 Clearat Rig: MPU M-11 - MPU M-11 - MPU M-11 wp08A 358.70 172.59 358.70 169.34 359.00 53.225 Centre Rig: MPU M-11 - MPU M-11 - MPU M-11 wp08A 383.70 172.61 383.70 169.19 383.28 50.490 Ellipse 14 March, 2019 - 12:43 Page 2 of 5 HALLIBURTON Anticollision Report for Plan: MPU M-14 - MPU M-14 wp04 358.70 194.45 358.70 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 321.30 59.975 Centre Slot 52 - Placeholder - Slot 52 - Placeholder - Slot 52 - Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 194.90 533.70 190.44 496.13 Scan Range: 33.70 to 5,352.95 usft. Measured Depth. Ellipse Slot 52 - Placeholder - Slot 52 - Placeholder - Slot 52 - 1,033.70 239.03 Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft 230.81 978.49 Measured Minimum @Measured Ellipse @Measured Clearance Summ Site Name Depth Distance Depth Separation Depth Factor A Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 260.69 Rig: MPU M-11 - MPU M-11 - MPU M-11 wp08A 783.70 223.60 783.70 217.46 743.12 36.438 Clearer Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 358.70 123.03 358.70 119.78 321.30 37.945 Centre Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 408.70 123.20 408.70 119.60 371.30 34.263 Ellipse Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 733.70 152.38 733.70 146.48 693.94 25.834 Clearai Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 358.70 137.14 358.70 133.89 321.30 42.297 Centre Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 408.70 137.24 408.70 133.64 371.30 38.169 Ellipse Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 833.70 172.88 833.70 166.24 790.89 26.046 Clearai Slot 52 - Placeholder - Slot 52 - Placeholder - Slot 52 - 358.70 194.45 358.70 191.21 321.30 59.975 Centre Slot 52 - Placeholder - Slot 52 - Placeholder - Slot 52 - 533.70 194.90 533.70 190.44 496.13 43.647 Ellipse Slot 52 - Placeholder - Slot 52 - Placeholder - Slot 52 - 1,033.70 239.03 1,033.70 230.81 978.49 29.076 Clearai Slot 58 - Placeholder - Slot 58 - Placeholder - Slot 58 - 763.59 266.93 763.59 260.80 723.09 43.521 Centre Slot 58 - Placeholder - Slot 58 - Placeholder - Slot 58 - 808.70 267.16 806.70 260.69 766.81 41.257 Ellipse Slot 58 - Placeholder - Slot 58 - Placeholder - Slot 58 - 1,058.70 284.11 1,058.70 275.59 1,000.00 33.335 Clearar Survey tool program From To SurveylPlan Survey Too (usft) (usft) 33.70 5,352.95 MPU M-14 wp04 2_MWD+IFR2+MS+. 5,352.95 17,900.00 MPU M-14 wp04 2_MWD+IFR2+MS+. 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. 14 March. 2019 - 12.43 Page 3 of 5 HALLIBURTON Sps—, Ltrllnng SI X150.0 jMPU 0 p 20.0 G) o S 90.a a 0 U d 60.0 m U 0 30.0 c 0 U 0.0 Project: is Point -- - — -- _m - - Site: Pt Moose Pad C.Minele(NIE) Referenw: l ,an: MPNM-14, Trve NanM1 MPU ,,, Vertical (ND) Reference M14 "04 RKB g 58.40usft Well: Plan: MPU M-14 Measured Depth Reference: M-14 ws"RKB@6840usf1 Wellbore: MPU M-14 calculation Method: Minimum CunaWre Plan: MPU M-14 wp04 SURVEY PROGRAM Date:2018-1"2T00:0000 Validated: Yes Version: Ladder/S.F. Plots Depth From Depth To Suwey/Plan Tool I 33.70 5352.95 MPU M-14 wp04 (MPU M-14) 2_MWD+IFR �1 SH (1 OI 2 ) 5352.95 17900.00 MPU M-14 wp04 (MPU M-14) 2_MW D+IFR WELL DUA05:Plan: M +N/-8 +&-W N, 0.00 0.00 6027 11 NO GLOBAL F TVD T 3918.40 38 3960.63 39 of 0 o 0 6 - Placeholder 2 - Piacehplder t� I _ A-15 15 (Brag Inj) wp03 l0 I (Stone II Inj) wp I )2 T i , I 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 Measured Depth (600 usf /in) `o 3.00 LL 0 Collision Risk Procedures Req. M Collision Avoidance Req. !! U 1.50 No -Go Zone - Stop Drilling 1NOERRORS r 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 Measured Depth (600 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-14 MPU M-14 MPU M-14 wp04 Sperry Drilling Services Clearance Summary Anticollision Report 14 March, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 Well Coordinates: 6,027,765.67 N, 533,903.80 E (70* 29' 12.78" N, 149° 43'22.42" W) Datum Height: M-14 wp04 RKB @ 58.40usft Scan Range: 5,352.95 to 17,900.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: ZM Scan Type: 25.00 M Sp HALLIBURTON Anticollision Report for Plan: MPU M-14 - MPU M-14 wp04 9,385.85 9,385.85 586.56 11,834.14 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 498.88 11,834.14 9,402.95 6.690 Centre Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 Ellipse 586.81 9,677.95 9,402.95 498.83 Scan Range: 5,352.95 to 17,900.00 usft. Measured Depth. 11,827.88 6.670 Ellipse MPL-35 - MPL-35A - MPL-35A 9,677.95 9,385.85 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft 9,677.95 551.30 11,827.88 9,402.95 Measured Minimum @Measured Ellipse @Measured Clearance Summ Site Name Depth Distance Depth Separation Depth Factor A Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 498.72 11,833.76 M Pt J Pad 6.662 Ellipse MPL-35 - MPL-35APB1 -MPL-35APSI 9,677.95 655.23 MPJ-19-MPJ-19-MP.L19 17,900.00 1,183.96 17,900.00 952.65 8,940.28 5.119 Clearai MPJ -24 -MPJ -24A -MPJ -24A 17,900.00 1,323.24 17,900.00 714.77 8,070.58 2.175 Clearai MPJ -24 -MPJ -241 -1 -MPJ -24L1 17,900.00 1,250.46 17,900.00 602.81 8,242.58 1.931 Clearai MPJ -24 -MPJ -241-1 PB1-MPJ-241-1 PBI 17,900.00 1,250.46 17,900.00 602.01 8,242.58 1.928 Clearai MPJ -24 -MPJ -241-1 PB2-MPJ-241-1 PB2 17,900.00 1,250.46 17,900.00 602.70 8,242.58 1.930 Clearai MPJ -24 - MPU J-24 - MPJ -24 17,900.00 1,250.46 17,900.00 602.70 8,242.58 1.930 Clearai MPJ -25 -MPJ -25 -MPJ -25 17,900.00 1,307.63 17,900.00 1,220.65 8,348.00 15.034 Clearai M Pt L Pad MPL-20 - MPL-20 - MPL-20 5,960.35 500.75 5,960.35 421.98 12,274.44 6.357 Centre MPL-20 - MPL-20 - MPL-20 6,002.95 502.39 6,002.95 421.07 12,261.26 6.178 Ellipse MPL-20 - MPL-20 - MPL-20 6,252.95 573.59 6,252.95 468.76 12,188.08 5.472 Clearai MPL-35 - MPL-35 - MPL-35 9,385.85 586.56 9,385.85 498.88 11,833.34 6.690 Centre MPL-35 - MPL-35 - MPL-35 9,402.95 586.81 9,402.95 498.83 11,832.96 6.670 Ellipse MPL-35 - MPL-35 - MPL-35 9,677.95 655.23 9,677.95 551.31 11,827.08 6.305 Clearat MPL-35 - MPL-35A - MPL-35A 9,385.85 9,385.85 586.56 11,834.14 9,385.85 498.88 11,834.14 9,402.95 6.690 Centre MPL-35 - MPL-35A - MPL-35A 9,402.95 Ellipse 586.81 9,677.95 9,402.95 498.83 11,833.76 11,827.88 6.670 Ellipse MPL-35 - MPL-35A - MPL-35A 9,677.95 9,385.85 655.23 11,834.14 9,677.95 551.30 11,827.88 9,402.95 6.304 Clearat MPL-35 - MPL-35APB1 -MPL-35APB1 9,385.85 Ellipse 586.56 9,677.95 9,385.85 498.77 11,834.14 11,827.88 6.682 Centre MPL-35 - MPL-35APB1 -MPL-35APB1 9,402.95 7,015.58 586.81 12,270.75 9,402.95 498.72 11,833.76 6.662 Ellipse MPL-35 - MPL-35APB1 -MPL-35APSI 9,677.95 655.23 9,677.95 551.19 11,827.88 6.298 Clearat MPL-35 - MPL-35APB2 - MPL-35APB2 9,385.85 586.56 9,385.85 498.77 11,834.14 6.682 Centre MPL-35 - MPL-35APB2 - MPL-35APB2 9,402.95 586.81 9,402.95 498.72 11,833.76 6.662 Ellipse MPL-35 - MPL-35APB2 - MPL-35APB2 9,677.95 655.23 9,677.95 551.19 11,827.88 6.298 Clearat MPL-35 - MPL-35APB3 - MPL-35APB3 9,385.85 586.56 9,385.85 498.77 11,834.14 6.682 Centre MPL-35 - MPL-35APB3 - MPL-35APB3 9,402.95 586.81 9,402.95 498.72 11,833.76 6.662 Ellipse MPL-35 - MPL-35APB3 - MPL-35APB3 9,677.95 655.23 9,677.95 551.19 11,827.88 6.298 Clearai MPL-36 - MPL-36 - MPL-36 7,015.58 398.21 7,015.58 326.32 12,270.75 5.540 Centre 14 March, 2019 - 12:41 Page 2 of 6 HALLIBURTON Anticollision Report for Plan: MPU M-14 - MPU M-14 wp04 12,002.95 248.67 12,002.95 109.69 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 1.789 Clearai MPU L-51 - MPU L-51 - MPU L-51 12,077.95 209.45 Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 1.913 Ellipse MPU L-51 - MPU L-51 - MPU L-51 12,179.92 186.88 Scan Range: 5,352.95 to 17,900.00 usft. Measured Depth. 118.85 12,553.62 2.747 Centre MPU L-52 - MPU L-52 - MPU L-52 10,452.95 237.78 Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft 119.61 12,710.56 2.012 Clearar MPU L-52 - MPU L-52 - MPU L-52 Measured Minimum @Measured Ellipse @Measured Clearance Summ Site Name Depth Distance Depth Separation Depth Factor A Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 2.596 Ellipse MPL-36 - MPL-36 - MPL-36 7,052.95 399.89 7,052.95 325.14 12,263.84 5.349 Ellipse MPL-36 - MPL-36 - MPL-36 7,302.95 488.26 7,302.95 377.32 12,220.11 4.401 Clearar MPL-36 - MPL-361-1 - MPL-361-1 7,015.58 398.21 7,015.58 326.31 12,270.75 5.538 Centre MPL-36 - MPL-361-1 - MPL-361-1 7,077.95 402.89 7,077.95 324.83 12,259.29 5.161 Ellipse MPL-36 - MPL-361-1 - MPL-361-1 7,302.95 488.26 7,302.95 374.32 12,220.11 4.285 Clearar MPL-36 - MPL-36L1 PB1 - MPL-361-1 PBI 7,015.58 398.21 7,015.58 326.29 12,270.75 5.537 Centre MPL-36 - MPL-361-1 PB1 - MPL-36L1 PB1 7,077.95 402.89 7,077.95 324.48 12,259.29 5.138 Ellipse MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 7,302.95 488.26 7,302.95 372.06 12,220.11 4.202 Clearai MPL-36 - MPL-36PB1 - MPL-36PB1 7,015.58 398.21 7,015.58 326.32 12,270.75 5.540 Centre MPL-36 - MPL-36PB1 - MPL-36PB1 7,052.95 399.89 7,052.95 325.14 12,263.84 5.349 Ellipse MPL-36-MPL-36PB1-MPL-36PB1 7,302.95 488.26 7,302.95 377.32 12,220.11 4.401 Clearai MPU L-51 - MPU L-51 - MPU L-51 12,002.95 248.67 12,002.95 109.69 12,487.14 1.789 Clearai MPU L-51 - MPU L-51 - MPU L-51 12,077.95 209.45 12,077.95 99.98 12,514.93 1.913 Ellipse MPU L-51 - MPU L-51 - MPU L-51 12,179.92 186.88 12,179.92 118.85 12,553.62 2.747 Centre MPU L-52 - MPU L-52 - MPU L-52 10,452.95 237.78 10,452.95 119.61 12,710.56 2.012 Clearar MPU L-52 - MPU L-52 - MPU L-52 10,502.95 211.51 10,502.95 111.23 12,722.57 2.109 Ellipse MPU L-52 - MPU L-52 - MPU L-52 10,603.31 187.76 10,603.31 124.34 12,746.31 2.960 Centre MPU L-53 - MPU L-53 - MPU L-53 8,952.95 188.60 8,952.95 115.96 13,060.46 2.596 Ellipse MPU L-53 - MPU L-53 - MPU L-53 8,960.17 188.49 8,960.17 116.02 13,063.12 2.601 Centre MPU L -53 -MPU L -53 -MPU L-53 9,102.95 230.61 9,102.95 131.05 13,115.53 2.316 Clearar MPU L-54 - MPU L-54 - MPU L-54 12,952.95 219.24 12,952.95 68.22 12,877.88 1.452 Clearar MPU L-54 - MPU L-54 - MPU L-54 12,977.95 205.02 12,977.95 64.63 12,887.97 1.460 Ellipse MPU L -54 -MPU L -54 -MPU L-54 13,107.49 166.49 13,107.49 93.10 12,938.39 2.269 Centre MPU L-56 - MPU L-56 - MPU L-56 9,652.95 248.61 9,652.95 129.85 12,790.86 2.093 Clearar MPU L-56 - MPU L-56 - MPU L-56 9,727.95 209.58 9,727.95 117.17 12,813.37 2.268 Ellipse MPU L -56 -MPU L -56 -MPU L-56 9,822.18 189.45 9,822.18 129.48 12,841.96 3.159 Centre MPU L -57 -MPU L -57 -MPU L-57 11,202.95 258.36 11,202.95 126.07 12,586.52 1.953 Clearai MPU L-57 - MPU L-57 - MPU L-57 11,277.95 218.52 11,277.95 113.43 12,613.39 2.079 Ellipse MPU L-57 - MPU L-57 - MPU L-57 11,386.45 193.86 11,386.45 128.78 12,653.77 2.979 Centre MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,202.95 258.36 11,202.95 126.07 12,586.52 1.953 Clearai 14 March, 2019 - 12:41 Page 3 of 6 HALLIBURTON Anticollision Report for Plan: MPU M-14 - MPU M-14 wp04 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp04 Scan Range: 5,352.95 to 17,900.00 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summ Site Name Depth Distance Depth Separation Depth Factor A Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,277.95 218.52 11,277.95 113.43 12,613.39 2.079 Ellipse MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,386.45 193.86 11,386.45 128.78 12,653.77 2.979 Centre M Pt Moose Pad Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 5,491.08 811.17 5,491.08 703.93 5,581.59 7.564 Centre Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 16,327.95 813.98 16,327.95 221.08 16,403.37 1.373 Clearat Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 5,352.95 798.32 5,352.95 687.99 5,185.57 7.236 Centre Plan: MPU M-15 - M-15 - M-15 (Bragg Inj) wp03 17,252.95 821.07 17,252.95 227.08 17,134.12 1.382 Clearai Plan: MPU M-16 - MPU M-16 - MPU M-16 wp02 5,352.95 1,380.20 5,352.95 1,282.10 4,924.11 14.069 Ellipse Plan: MPU M-16 - MPU M-16 - MPU M-16 wp02 5,902.95 1,499.88 5,902.95 1,382.56 5,335.78 12.785 Clearai From To SurveylPlan Survey Too (usft) (usft) 33.70 5,352.95 MPU M-14 wp04 2_MWD+IFR2+MS+. 5,352.95 17,900.00 MPU M-14 wp04 2_MWD+IFR2+MS+. 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. 14 March, 2019 - 12:41 Page 4 of 6 HALLIGURTON Sperry Oriiling `o 3.00 LL Project: .e Point - Site: Pt Moose Pad Op -a dlna@ (NIE) Reference: W. an MPU M-14, Time With Im Vimmal CI VD) Reference: M-14 wp01 RKB @ W9 ft Well: Plan: MPU M-14 Messuied! Depth Reference: W4 wp04 RK8@M.40usff Wellbore: MPU M-14 calomauon Memos: Minimum Our stun Plan: MPUM-14 wp04 SURVEY PROGRAM Date: 2018-10-D2T00:00:00 Validated: Yes Version: Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool 33.70 5352.95 MPUM-14wpD4(MPUM-14) 2 -MD -IFR PH (2 of 2) 5352.95 17900.00 MPUM-14wp04(MPUM-14) 2_MWD+IFR WELL DETA➢S:Ptan: M +WS *F! -W p 0.00 0.00 602' NO GLOBAL TVD 3918.40 38 3960.63 39 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 11 Measured Depth (1500 usfttin) -� Collision Risk Procedures Req. n Collision Avoidance Re . 0 1.50 00 No -Go Zone - Stop Drilling 5600 6300 7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 1 Measured Depth TRANSMITTAL LETTER CHECKLIST WELL NAME: ! I Pu, M— 11-4— PTD: TPTD: 1 9 — O q— O -,`Development —Service —Exploratory _ Stratigraphic Test —Non -Conventional FIELD: ti I I V- e� Poi tg-i- POOL: Sc �ya-� Q.' S/u Ac% 0 i 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 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. (Companv 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 Transform Points Q Source coordinate systemTarget coordinate system State Plane 1927 - Alaska Zone 4 Albers Equal Area 050) Datum: ru_ M � Datum: NAD 1927 - North America Datum of 1927 {Mean) NAD 1927 - Nodh America Datum of 1927 (Mean) --- Type values into the spreadsheet or copy and paste -columns -of -data from a spreadsheet using the keyboard shortcuts Ctd+C to copy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. < Back Finish Cancel Help WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Yes 20 inch.conductor set at 113 It Surface casing. protects all known USDWs NA Well Name: MILNE P7 UNIT M-14 Program DEV Well bore seg PTD#:2190400 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Dispos. Administration 1 Permit fee attached _ _ __ _ _ .... _ _ _ _ _ __ NA CMT. will cover all known productive horizons... - - . . . . ... . 2 Lease number appropriate... - - . _ .. _ _ . .. . . . . . . . ... Yes - - - - ... Yes - 3 Unique well name number ____---- - --Yes --.. --. -..-...--. Rig has steel pits.. 4 m Well located .adefined pool- - - - - - -- - - -- - - - - - - - - - - - - - - - ---- - - .................... .. .... ... Yes - - - - - - - - - - Adequate wellbore separation proposed - - _ _ 5 Well located proper distance from drilling unit boundary- - . - - _ _ ... Yes - .. Yes 6 Well Jocated proper distance from other wells . . .. . . . . . .. . . ... . .. . . Yes _ - Max form press= 1718_psi( 8.5 ppg EMW) will drill with 8.9-9.5 pgp mud 7 Sufficient acreage available in drilling unit. _ - . . . . ..... . .. . . . . - Yes BOPE press rating appropriate; test to (put psig in comments). 8 If. deviated, is wellbore platincluded -- - - - - - - - - -- - - - - -- - Yes _ Yes 9 Operator only affected party - - _ - - _ - - - - - - .... _ _ . _ . _ . - - - Yes 10 Operator has appropriate bond in force - - - - . . . .. . . .. . . . ... Yes Mechanteal.condi0on of wells within AOR verified (For setvice well only) - - 11 Permit can be issued without conservation order - - . - - - - - .. ... - - - - .. Yes Appr Date 12 Permit. can be issued without administrative approval - - - - - Yes - - DLB 3/18/2019 13 Can permit be approved before 15 -day wait - - - . Yes - - - 14 Well located within area and strata authorized by. Injection Order # (put. 10# in. comments) (For- NA, 15 All wells. within 1/4 -mile area of review identified (For service well only). - - - _ NA.. - - 16 Preproduced injector; duration of pre production less than 3 months (For service well only) - . NA - - 17 Nonoonven. gas conforms to AS31,05,030Q.1.A),(j,2.A-0) - NA- _ Engineering I20 21 22 123 24 125 26 27 Appr Date �28 GLS 3/26/2019 I29 30 31 32 33 34 Conductor stringprovided- - - - - - - --- - - - - - Yes 20 inch.conductor set at 113 It Surface casing. protects all known USDWs NA - No aquifers... permafrost area - - CMT vol adequate. to circulate on conductor& surf csg - - ... - - _ ... - - - Yes - _ using 2 stage cement for 9 5/0" surface casing ... ES at 2500 ft CMT vol adequate to tie-in long string to surf csg - - ... - - - .... Yes . Horz lateral will be slotted liver. 6 5/8" OD CMT. will cover all known productive horizons... - - . . . . ... . . ... . . . Yes Casing designs adequate for C, T, B &. permafrost - - - - - - .. ... Yes - _ BTG supplied..._ meels industry standards. Adequate tankage. or reserve pit - - - - ... - - - . _ - _ - Yes Rig has steel pits.. If a -re -drill, has.a 10-403 for abandonment been approved _ - .. - - - . _ NA. - Adequate wellbore separation proposed - - _ _ ..... - - Yes - - - - - If diverter required, does itmeet regulations - - - - - .. Yes - - Using -diverter to drill to top of Schrader Bluff ..- BOPE to drill lateral in zone. Drilling fluid. program schematic & equip list adequate- - - _ .... - Yes _ - Max form press= 1718_psi( 8.5 ppg EMW) will drill with 8.9-9.5 pgp mud BOPEs, do they meet regulation _ - _ - _ - _ _ _ _ _ - _ Yes - Doyon 14 has _135/8" BOPE -5000 psi WP BOPE press rating appropriate; test to (put psig in comments). - - - Yes _ - AMSP = 1332.psf Will. test BOPE to 3000 psi (annular to2500 psi). Choke. manifold complies w/API RP -53 (May 84) - - - - Yes Work will occur without operation shytdown- - _ - - Yes Is presence of H2S gas. probable - - - - - - .. - - No. - - - . - H2S on pad.. Rig has sensors and. alarms.. Mechanteal.condi0on of wells within AOR verified (For setvice well only) - - NA 35 Permit can be issued w/o hydrogen sulfide measures .. _ Yes _ _ H2S not anticipated from drilling of offset wells; however, dg will have H2S sensors and alarms. Geology 36 Datapresentedon potential overpressure zones.. - - - - - _ .... _ _ _ Yes Appr Date 37 Seismic analysis of shallow gas. zones - - _ - NA. DLB 3/18/2019 38 Seabed condition survey (if off -shore) _ ..... - - - - - - - .... - - - _ - - NA. - - - - - - 39 Contact name/phone for weekly. progress reports [exploratory only] - - - NA... Geologic Engineering Public Will be normal flow Jet Pump well. Requires SSV to be on horz run of tree. Variance required. GIs Commissioner: Date: Commissioner: Date Commissioner Date JA:� �201