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Home My WebLink About219-0611. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: CTU FCO w/ N2 Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 16,306 feet N/A feet true vertical 3,901 feet N/A feet Effective Depth measured 16,280 feet 5,726 & 6,467 feet true vertical 3,901 feet 3,610 & 3,790 feet 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 6,581' 3,802' 7" Retrievable & Packers and SSSV (type, measured and true vertical depth)9-5/8" SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone:777-8343 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi 5,410psi 3,470psi Burst N/A 5,750psi 7,240psi 6,090psi 20" x 34" 9-5/8" 7" 6-5/8" 3,810' 3,800' 3,901' Length 80' 6,657' 6,528' Surface Tie-Back N/A measured 9,736' N/A Liner (Pre-Drilled) Casing Conductor Size 3,209 MILNE PT UNIT M-16 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 1,280 Gas-Mcf 2,972 Casing Pressure Tubing Pressure 162 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-274 286 Authorized Signature with date: Authorized Name: David Haakinson dhaakinson@hilcorp.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-061 50-029-23631-00-00 Plugs ADL0025514 / ADL0025515 5. Permit to Drill Number: MILNE POINT / SCHRADER BLUFF OI Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 357 Representative Daily Average Production or Injection Data 296329 1,168 Oil-Bbl measured true vertical Packer 16,285' WINJ WAG 104 Water-Bbl MD 114' 6,691' 6,562' TVD 114' Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:42 pm, Jul 17, 2020 Chad A Helgeson 2020.07.17 14:23:07 -08'00' RBDMS HEW 7/20/2020 L SFD 7/20/2020DSR-7/20/2020MGR21JUL2020 _____________________________________________________________________________________ Revised By: TDF 7/17/2020 SCHEMATIC Milne Point Unit Well: MPU Moose Pad M-16 Last Completed: 5-22-19 PTD: 219-061 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor (Insulated) 215.5 / A-53 / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.679” Surface 6,691’ 0.0758 7” Tieback 26 / L-80 / TXP 6.151” Surface 6,562’ 0.0382 6-5/8” Liner (PreDrilled) 20 / L-80 / Hydril 563 5.924” 6,549’ 16,285’ 0.0355 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 2.867” Surf 6,581’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4” 1st stage L – 540 sx, T – 400 Sx 12-1/4” 2nd stage L – 415 sx / T – 415 sx 8-1/2” Cementless Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 507’ Max Hole Angle = 63° @ Jet Pump Max Hole Angle = 67° @ XN profile Max Hole Angle = 84° @ Tubing tail Max Hole Angle = 95.3° @ 13,624’ MD TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 3 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 30’ Tubing Hanger (3-1/2” TC-II Top & Btm) w/ Blast Rings on hanger pup 2.867” 2 2707’ 3.5” Patco GLM w/ 1.5” Dummy GLV set 5-22-19 2.867” 3 5632’ 3.5” SLB Gauge Mandrel w/ ¼” Wire (Discharge Gauge) 2.875” 4 5643 3.5” XD Sliding Sleeve 2.813” Packing Bore;3,688’ TVD; 70°(10C Set 07/08/20)2.813” 5 5652’ 3.5” SLB Gauge Mandrel w/ ¼” Wire (Intake Gauge) 2.875” 6 5673’ 3.5” X Nipple (2.813” Packing Bore) 2.813” 7 5726’ 7” x 3.5” PHL Retrievable Packer, 50k Shear to Release 2.885” 8 5783’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go)Min ID = 2.750”2.750” 9 6580’ 3.5” WLEG (Btm @ 6,581’) 2.867” Lower Completion 10 6,467’ BOT SLZXP Liner Top Packer w/BD Slips 7” x 9-5/8” (11.5’ Tieback Sleeve) 6.170” 11 6,467’ 7” Tieback Assy. (8.25” OD No-Go @ 6,457’) 6.090” 12 6,475’ 7” Hydril 563 L-80 x 6-5/8” Hydril 563 L-80 XO 5.924” 13 6,500’ 6-5/8” Pre-Drilled Liner (72 holes per ft) w/ 1 straight-vane centralizer per jt Blank liner from 7,106’ – 7,227’ & 13,238’-13,676’5.924” 14 16,366’ WIV (Wellbore Isolation Valve) 1.000” 15 16,371’ Shoe;Btm @ 16,371’- TD =16,306’ (MD) / TD =3,901’(TVD) 20” Orig. KB Elev.:59’/ GL Elev.: 24.9’ 7” 9-5/8” 1 2 5 PBTD =16,280’ (MD) / TD =3,901’(TVD) 9-5/8” ‘ES’ Cementer @ ±2,401’ 8 11 9 10 14 3-1/2” 4 13 Min ID 2.750” 8-1/2” Hole 3 7 12 15 6 6-5/8” Shoe @ 16,306’ GENERAL WELL INFO API: 50-029-23631-00-00 Drilled and Completed by Doyon 14 – 5-22-19 CTU FCO w/ N2 – 7/2/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP M-16 CTU #6 50-029-23631-00-00 219-061 6/25/2020 7/2/2020 WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2,000H. RIH W/ DUMMY ISO SLEEVE AND TRIED TO PRESSURE UP IA BUT WERE UNSUCESSFUL. WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2,500H. RUN 3-1/3" OM-1 KOT, 7" EXT, 7" EXT, 1.75" LIB, LOC & S/D IN STA #1 @ 2,683' SLM / 2,707' MD, GET GOOD IMPRESSION OF LATCH. RUN 3-1/2" CHECK SET & S/D ON TOP OF JET PUMP @ 5610' SLM, PIN WORKED BUT NOT SHEARED. PULL 3" JET PUMP (SER #: BP-1099, RATIO 11C, SCREEN, OAL=69") @ 5,610' SLM, RECOVER ALL PKG & NUBBINS. *JUMPER POWER FLUID DOWN TBG TO HELP PUSH DOWN HOLE @ 1bpm*. SET 3" JET PUMP (SER #: BP-1099, RATIO 11C, SCREEN, OAL=69") IN XD SSD @ 5,612' SLM / 5,643' MD, GOOD SET. RUN 3-1/2" CHECK SET & S/D ON TOP OF JET PUMP @ 5,612' SLM, PIN SHEARED. JOB COMPLETE, NOTIFY PAD- OP TO BRING WELL ON UPON DEPARTURE. 6/27/2020 - Saturday WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2,000H. ATTEMPT TO RUN 3-1/2" CAT STANDING VALVE TWICE TO XN-NIPPLE @ 5,751' SLM, UNABLE TO SHEAR GS PIN (brass & 1/2 aluminum), PULL CAT STANDING VALVE FROM WELL. JUMPER POWER FLUID DOWN TBG TO HELP PUSH DOWN HOLE @ 1bpm. 6/30/2020 - Tuesday 6/28/2020 - Sunday WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2,000H. PULL 3" JET PUMP (SER #: BP-1099, RATIO 11C, SCREEN, OAL=69") @ 5,610' SLM, RECOVER ALL PKG & NUBBINS, PUMP NOZZLE & THROAT LOOKS GOOD UPON INSPECTION. 6/29/2020 - Monday 6/26/2020 - Friday WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2,500H. RUN 3 'x 1-7/8" STEM, 3-1/2" 42BO POSITIONING TOOL (keys down to open) & SHIFT XD SSD DOWN @ 5,614' SLM / 5,643' MD, PIN UNTOUCHED IN 42BO SHIFTING TOOL, METAL MARKS ON 3-1/2" 42BO FROM JARRING DOWN. SET 3" JET PUMP (SER #: BP-1099, RATIO 11C, SCREEN, OAL=69") IN XD SSD @ 5,615' SLM / 5,643' MD, GOOD SET. NOTIFY PAD-OP TO BRING WELL ON UPON DEPARTURE. 6/24/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. PUMPED 50bbls POWER FLUID DOWN TUBING @ 1bbl PER MIN TO DISPLACE. PULLED 3" JET PUMP (serial: HC-0003, ratio: 11C) W/ SCREEN FROM XD SLIDING SLEEVE @ 5,626' SLM (5,643 MD), ALL PACKING & PINS RECOVERED. RAN 3'x1-7/8" STEM, 3-1/2" 42BO (keys up), BROGHT ON POWER FLUID DOWN TUBING TO ASSIST RIH, PASSED THROUGH XD SLIDING SLEEVE @ 5,626' SLM (5,643 MD) & HIT UP FOR 15 MIN, PASSED THROUGH, MADE 6 PASSES CLEAN WITH OUT HANGING UP, 42BO PIN NOT SHEARED, SLEEVE IS CLOSED. WELL S/I ON DEPARTURE, DSO NOTIFIED. 6/25/2020 - Thursday MIRU SLB CTU #6 with 16,215' of 2" CT. Perform full BOP test to 300/4,000 psi. Record test on form 10-424. MU Baker BHA with Tempress Tool and SLB 2.27" OD JSN. On well and PT to 300/4,000 psi. RIH dry to lockup depth at 10,575' ctmd with no obstruction encountered. All clean pickups at weight checks. Attempt to circulate fluids from the well using N2 and SLK 1% checking for solids. Unable to surface fluids until we PUH to 4,500'. Recovered slight slugs of fluid only until just circulating N2 around. No apparent solids in recovered crude that appeared diesel cut. POOH. Secure well. RDMO. Well Name Rig API Number Well Permit Number Start Date End Date MP M-16 Slickline 50-029-23631-00-00 219-061 6/24/2020 7/2/2020 7/3/2020 - Friday No operations to report. 7/1/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. SHIFT XD-SS AT 5,623' SLM/ 5,643' MD. CLOSED WITH 3-1/2" 42BO (keys up). ATTEMPT TO PRESSURE IA UP WITH POWER FLUID (unsuccessful). PULL RK-DGLV FROM GLM AT 2,688' SLM/ 2,707' MD (lower packing stack torn up badly). SET RK-DGLV IN GLM AT 2,688' SLM/ 2,707' MD. PRESSURE IA TO 800psi WITH POWER FLUID AND WATCH FOR 15min (good). 7/2/2020 - Thursday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. SHIFT XD-SS WITH 3-1/2" 42BO (keys down) OPEN (pin not sheared). SET 3" JET PUMP (serial# BP-J25, ratio: 10C, OAL=69", screen) IN XD-SS AT 5,628' SLM/ 5,643' MD (recovered all pins & nubbins). No operations to report. No operations to report. 7/4/2020 - Saturday No operations to report. 7/7/2020 - Tuesday 7/5/2020 - Sunday No operations to report. 7/6/2020 - Monday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&RLO7XELQJ8QLW)OXLG)ORZ'LDJUDP&OHDQRXWZ1LWURJHQ )RDP8SGDWHG/(*(1')OXLGV3XPSHG )OXLGV5HWXUQHG9DOYH 2SHQ 9DOYH &ORVHG*DWH9DOYH %DOO9DOYH%XWWHUIO\9DOYH /R7RUT9DOYH&KHFN9DOYH 0DQXDO&KRNH3UHVVXUH*DXJHϱϬϬ></>>dE<ŚŽŬĞ DĂŶŝĨŽůĚWϰϬϬ> hWZ/',dWKƉĞŶsZ>/EK/>WhDWϰϬϬ>hWZ/',dKƉĞŶůŽƐĞĚKƉĞŶKƉĞŶKƉĞŶKƉĞŶKƉĞŶKƉĞŶKƉĞŶW^tŽƌ<>tͬ&KDZKZ&Z/d/KEZhZϱϬ>&ZWZKdddE<^tŽƌ<>tͬ&KDZKZ&Z/d/KEZhZdŽ&ůŽǁůŝŶĞE/dZK'EWhDWΘdE<WK/>hE/dt/d,ϭ͘ϱ͟ƚŽϮ͘Ϭ͟K/>ϰϬϬ>hWZ/',d^tdZtͬ&KDZdZ/W>y DATA SUBMITTAL COMPLIANCE REPORT 9/5/2D19 Permit to Drill 2190610 Well Name/No. MILNE PT UNIT M-16 MD 16306 TVD 3901 Completion Dale 5/21/2019 REQUIRED INFORMATION Mud Log No,� Operator Hilcorp Alaska LLC Completion Status 1 -OIL Samples No DATA INFORMATION List of Logs Obtained: ROP, ABG, DGR, EW R, ADR 2"/5" MID ... ABG, DGR, EW R, ADR 2"/5" TVD Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH ED C 31003 Digital Data 112 16306 ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data ED C 31003 Digital Data AOGCC Pagel of 2 6680 16272 Current Status 1-0IL API No. 50-029-23631-00.00 UIC No Directional Survey Yes (from Master Well Data/Logs) Received Comments 7/19/2019 Electronic Data Set, Filename: MPU M-16 LWD Final.las 7/19/2019 Electronic Data Set, Filename: MPU M-16 ADR Quadrants All Curves.las 7/19/2019 Electronic File: MPU M-16 LWD Final MD.cgm 7/19/2019 Electronic File: MPU M-16 LWD Final TVD.cgm 7/19/2019 Electronic File: MPU M-16 Definitive Survey Report.pdf 7/19/2019 Electronic File: MPU M-16 Surveys.xlsx 7/19/2019 Electronic File: MPU M-16 DSR.txt 7/19/2019 Electronic File: MPU M-16 GIS.txt 7/19/2019 Electronic File: MPU M-16_Plan.pdf 7/19/2019 Electronic File: MPU M -16_V Sec.pdf 7/19/2019 Electronic File: MPU M-16 LWD Final MD.emf 7/19/2019 Electronic File: MPU M-16 LWD Final TVD.emf 7/19/2019 Electronic File: MPU M-16 Gecsteering.dlis 7/19/2019 Electronic File: MPU M-16 Geosteering.ver 7/19/2019 Electronic File: MPU M-16 LWD Final MD.pdf 7/19/2019 Electronic File: MPU M-16 LWD Final TVD.pdf 7/19/2019 Electronic File: MPU M-16 LWD Final MD.tif 7/19/2019 Electronic File: MPU M-16 LWD Final TVD.tif 7/19/2019 Electronic File: EMFView3_1.zip Thursday, September 5, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/5/2019 Permit to Drill 2190610 Well Name/No. MILNE PT UNIT M-16 MD 16306 TVD 3901 Completion Date 5/21/2019 ED C 31003 Digital Data Log 31003 Log Header Scans Well Cores/Samples Information: Name INFORMATION RECEIVED Completion Report? Production Test Information/ NA Geologic Markers/Tops G COMPLIANCE HISTORY Completion Date: 5/21/2019 Release Date: 4/23/2019 Description Comments: Operator Hilcorp Alaska LLC API No. 50-029.23631-00-00 Completion Status 1 -OIL Current Status 1-0I1 UIC No 7/19/2019 Electronic File: Readme.txt 0 0 2190610 MILNE PT UNIT M-16 LOG HEADERS Sample Interval Set Start Stop Sent Received Number Comments Directional / Inclination Data \.% Mud Logs, Image Files, Digital Data Y /(9 Core Chips Y NA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files Core Photographs Y NA Daily Operations Summary Cuttings Samples Y /E) Laboratory Analyses Y NA Date Comments Compliance Reviewed By: I Y \ � Date: /I I AUGCC Page 2 of 2 Thursday, September 5, 2019 DATE: 7/18/2019 219061 Uebra Oudean Hilcorp Alaska, LLC 3 1003 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 DATA TRANSMITTA CD: HALLIBURTON 13 MAY 2019 M-16 ROP DGR ABG EWR ADR MO & TVD Please include current contact information if different from above. RECEIVED JUL 19 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 n Received By: Date: U STATE OF ALASKA I r� IT! 2 ZO,g ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANR h 1a. Well Status: Oil ❑� . Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[_] 1b. Well Class9 20AAC 25.10520AAC 25.110 Development �' Exploratory ❑ GINJ [—]WINJ L] WAG[—] WDSPL El No. of Completions: _ 1 Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Hilcorp Alaska, LLC Abend.: 5/21/2019 219-061 ' 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 May 1, 2019 50-029-23631-00-00 ' 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 4914' FSL, 441' FEL, Sec 14, T13N, R9E, UM, AK ' May 13, 2019 MPU M-16 Top of Productive Interval: 9. Ref Elevations: KB: 59' • 17. Field / Pool(s): Milne Point Field 701' FSL, 1944' FWL, Sec 13, T13N, R9E, UM, AK GL: 24.9' BF: 24.9' Schrader Bluff Oil Pool - Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 505' FSL, 736' FEL, Sec 19, T13N, R10E, UM, AK • 16,280' MD / 3,901' TVD ' -ADL025514, ADLO25515 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 533724 y- 6027765 ' Zone- 4 . 16,306' MD / 3,901' TVD - LONS 16-004 TPI: x- 536131 y- 6023563 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 543992 y- 6018130 Zone- 4 N/A 2,190' MD / 1,853' TVD 5. Directional or Inclination Survey: Yes LJJ (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 SETTING DEPTH TVD AMOUNT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 216# X-52 Surface 114' Surface 114' 42" ±270 ft3 9-5/8" 40# L-80 Surface 6,691' Surface Sig 1 L - 540 sx / T - 400 sx 3,810' 12-1/4" Sig 2L-415 sx/T-415 sx 180.8 7" 26# L-80 Surface 6,562' Surface 3,800' Tieback Tieback Assy. 6-5/8" 20# L-80 6,549' 16,285' 3,798' 3,901' 8-1/2" Cementless PreDrilled Liner 24. Open to production or injection? Yes Q No ❑ 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/rVD) Size and Number; Date Perfd): 3-1/2" 6,581' 5,726' MD / 3,611' TVD 6-5/8" PreDrilled Liner 72 holes per foot run on 5/18/19 PreDrilled Liner COMPLETION 6,696' - 7,106' MD / 3,811' - 3,820' TVD 7,227'- 13,238' MD / 3,820' - 3,897' TVD T 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No 13,676' - 16,244' MD 3,880' - 3,900' TVD S 21 (1 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Solid Liner VERIF ED 7,106' - 7,227' MD / 3,820' - 3,820' TVD 4FAJ _ 13,238' - 13,676' MD / 3,897' - 3,880' TVD 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 5/29/2019 Jet Pump Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 6/5/2019 24 Test Period 1399 305 0 N/A 218 Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 334 3450 24 -Hour Rate —.► 1399 305 0 16 Form 10-407 Revised 5/2017 z CONTINUE ON PAGE 2 RBDMS� JUN 24 2019 141- L orC 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD1TVD, 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 2,190' 1,853' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB 6,696' 3,811' information, including reports, per 20 AAC 25.071. SV5 1,356' 1,310' SVi 2,250' 1,883' Ugnu LA3 4,784' 3,147' SB NA 5,762' 3,623' SB OA 6,651' 3,809' 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: Drill g Manager Contact Email: Cdin er hIIcor .Cold Authorized �� Contact Phone: 777-8389 Signature: pate: 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 tb: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only 1lilmrp Alaska.I.I.0 Dig. KB Elev.: 54/ GL Elev.: 24.4' 2D' 1 � 2 i ssB'Es CerrerM1er@ G� '.� r 2 3 Ur' 7., 3 n I*,, 2 9 35/8" _to • • • • • 6-5/9' 8-1/YShoe @ • 14 Hole 16,306 15 —.. TD 16,306' (MD)/TD=3,901'(TVD) PBTD=16,280' (MD) / TD = 3,901! (TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-16 Last Completed: 5-22-19 PTD: 219-061 Tree Cameron 3 1/8" 5M Wellhead FMC 11" SM TC -1A w/11" x 31/2" 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 bbl s (10 Yards Pilecrete dumped down backside) 12-1/4"lst stage L-540 sx, T-400 Sx 12-1/4" 2nd stage L -4155x/ T-415sx 8-1/2" Cementless Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn DriftlD Top Btm BPF 20"x34" Conductor (insulated) 215.5/A-53/Weld N/A Surface 114' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 6,691' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surtace 6,562' 0.0382 6-5/8" Liner(PreDrilled) 20/L-80/Hydril 563 5.924" 1 6,549' 1 16,285' 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 2.867" I Surf 1 6,581' 1 0.0087 Pw-1 WELL INCLINATION DETAIL KOP @ 507' Max Hole Angle = 63' @ Jet Pump Max Hole Angle = 67` @ XN profile Max Hole Angle = 84' @ Tubing tail Max Hole Angle =95.3° @ 13,624' MD JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 30' Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 2707' 3.5" Patco GLM w/ 1.5" Dummy GLV set 5-22-19 2.867" 3 5632' 3.5" SLB Gauge Mandrel w/ Y." Wire (Discharge Gauge) 2.875" 4 5643 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,688' TVD; 70° (Sleeve open 5-22-19 2.813" 5 5652' 3.5" SLB Gauge Mandrel w/ Y" Wire (Intake Gauge) 2.875" 6 5673' 3.5" X Nipple (2.813" Packing Bore( 2.813" 7 5726' 7" x 3.5" PHL Retrievable Packer, 50k Shear to Release 2.885" 8 5783' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" 2.750" 9 6580' 3.5" WLEG (Btm @ 6,581') 2.867" Lower Completion 10 6,467' BOTSLZXP Liner Top Packer w/BD Slips 7" x 9-5/8" (11.5' Tieback Sleeve) 6.170" 11 6,467' 7" Tieback Assy. (8.25" OD No -Go @ 6,457') 6.090" 12 6,475' 7" Hydril 563 C86 x 6-5/8" Hydril 563 L-80 XO 5.924" 13 6,500' 6-5/8" Pre -Drilled Liner (72 holes per ft) w/ 1 straight -vane centralizer per jt Blank liner from 7,106'-7,227' & 13,238'-13,676' 5.924" 14 16,366' WIV(Wellbore Isolation Valve) 1.000" 15 16,371' Shoe; Btm @ 16,371' GENERAL WELL INFO API: 50-029-23631-00-00 Drilled and Completed by Doyon 14-5-22-19 Revised By: CJD 6/24/19 UHilcorp Energy Company Composite Report Well Name: MP M-16 Field: Milne Point County/State: North Slope Borough, Alaska (LAT/LONG): avation (RKB): 24.9 API #: 50-029-23631-00-00 Spud Date: 5/2/2019 Job Name: 191131 1 D MPU M-16 Drilling Contractor Doyon 14 AFE If AFE $: .. -":bid Ops:Sy ary 4/30/2019 Finish M-14 completion, see M-14 report for details. '"' Notified AOGCC of upcoming diverter test at 06:42 on 30 April 2019 .";Clean and secure well.;Skid rig Floor into the moving position. Sim ops: move rock washer with roads & pads bed truck.;Place matting boards between M-14 and M-16 for rig move. Sim ops: jack up rig and remove shims. "' 2 gallon total glycol leak from expansion boot on generator radiator. 1/2 gallon to the matting board and trace between the rig mats to the pad. Notified Milne Point security and environmental. `"';Move rig off M-14.;Shufffe matting boards from M-14 to M-16.;Move rig onto M-16 and shim Ievel.;Skid rig Floor into moving position.;Orient surface annular and knife valve for diverter line placement and torque bolts. Install riser. Install diverter line. Sim ops: prep mud pits for mud and rig up steam, air and water to the rig Floor. Remove mats from M-14. Spot 5 star, mud man and parts trailem.;Road & pads trucks spot fuel trailer and rock washer. Spot rock washer cuttings tank. 5/1/2019 Finish rig acceptance checklist -rig accepted at 12:00. C/O top drive saver sub, N/U bell nipple, spot MWD and geo shacks. Load 5" drill pipe into the pipe shed and begin to process.;Finish processing 210 joints of 5" drill pipe and 17 joints of 5" HWDP. Load BHA and jars into the pipe shed. Prep mud pits and "' shakers for surface hole. On high line power at 14:40 ***;PIU 30 joints of 5" drill pipe and rack back 10 stands in the derrick.;Perform diverter function test on 5" drill pipe. AOGCC inspector Austin McLeod on location to witness. Knife valve opened in 16 seconds & annular closed in 27 seconds. Accumulators: 3000 PSI system, 1875 PSI after closure, 41 sec. 200 PSI recharge, 157 sec. full recharge, 2108 PSI six bottle N avg.;291' of 16" diverter line installed. 212' from / closest ignition source. 285' from rig substructure.;Continue to pickup remaining ISO joints of 5" drill pipe and rack back 60 stands in the derrick. Total of 70 stands in the derrick to drill surface hole.;P/U 17 joints of 5" HWDP and jars and rack back 6 stands in the derrick.;Slip and cut 93' of drilling line. Service top drive and blocks.;Mobilize BHA components to the rig Floor. M/U used 12-1/4" mill tooth bit, 8" SperryDrill motor set at 1.5°, XO sub and stand of S" HWDP. Pre spud meeting with Doyon, MI and Sperry. M/U XO sub & stand of HWDP. RIH at tag bottom on depth at 114'. Flood lines and pressure test to 3500 PSI - good test.;Drill 12-1/4" surface hole from 114' to 185', 71' drilled, 71'/hour AROP. 375 GPM = 650 PSI, 40 RPM = 1 K TO, 10K WOB. PU 50K / SO 50K / ROT 50K. 8.8 ppg MW, 300+ vis.; Hauled 855 bbls H2O from 6 Mile lake for total = 855 bbls Hauled 0 bols heated H2O from G&I for total = 0 bbls Hauled 0 bbls cutting/liquids to MPU G&I for total= 0 bbls 5/2/2019 Drill 12.25" hole F/ 185' T/ 220'. 350- 400 GPM 610 PSI, 40 RPM, 5K TQ ;Back ream out at 40 rpm F/ 220'T/ 114'. Circ two btm up clean. Blow down TD & L/D Clean out bit. Clean and clear rig goor.;M/U Directional BHA 91 with Kymera bit, Carry Scribe and upload MWD.P/U 3 NMFC & RIH to 193'. Wash down F/ 193' T/ 220'.;Drilling 12.25" hole F/ 220'T/ 377', 157'@ 79 FPH average. 400 GPM, 960 PSi, 40 RPM, 5 K TQ, MW 8.9, Vis 300+.;Drilling 12.25" hole F/ 377' T/ 1160', 783'@ 130 FPH average. 450- 525 GPM 1591 PSI, 40-80 RPM, MW 8.9. Started Directional at 490' Building 4 Deg per 100. Sliding 45' of each stand.; Drilling 12.25" hole F/ 1160' T/ 1887' MD 11699' TVD, 727' @ 121 FPH average. 525 GPM, 1830 PSI, 80 PRM, 5K TO, 18K WOB. 9.2 ppg MW, 145 vis. 10.3 ppg ECD. Max gas 0 units. 105 PU / 90 SO/ 95 ROT.;Drilling 12.25" hole F/ 1887'T/ 2834' MD / 2169' TVD, 947'@ 158 FPH average. 550-600 GPM, 2000-2250 PSI, 80 RPM, 5K TO, 10K WOB. 9.3 ppg MW, 182 vis. 10.6 ppg ECD. Max gas 52 units. 107 PU 188 SO/ 96 ROT. 9.64°DL @ 1925' survey. Ream stand, re -survey with no change, continue drilling.;End of build at 2000', maintain 60° tangent. Base of permafrost at 2190' MD / 1853' TVD. Pumped high vis sweep with nut plug at 2453', 20% increase and back on calculated strokes. ECD climbed to 11.4 ppg while drilling stand to 2739', circulate bottoms up while reamed stand 2x drop ECD to 10.4 ppg.;Last survey at 2781.03' MD /2142.78' TVD, 59.97° inc, 156.32° azm, 7.16' from plan, 1.27' low and 7.44' right.;Hauled 640 bbls H2O from 6 Mile lake for total = 1495 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 1041 bbls cutting/liquids to MPU G&I for total= 1041 bola 0 bbls daily losses, 0 bbls cumulative losses 5/3/2019 Drill 12.25" hole f/ 2834't/ 3821' (2654' TVD), 98T @ 165 FPH average. 600 GPM, 2300 PSI, 80 RPM, 8K TO, 1GK WOB. 9.3 ppg MW, 112 vis, 10.3 ppg ECD. Max gas 23 units. 129K PU 194K SO / 107K ROT.;Drill 12.25" hole f/ 3821' V 4548' (3032' TVD), 727'@ 121 FPH average. 600 GPM, 2380 PSI, 80 RPM, 11 K TO, 5-20K WOB. 9.1 ppg MW, 72 vis, 10.3 ppg ECD. Max gas 23 units. 150K PU 195K SO / 117K ROT. Pumped high vis sweep at 4455', 15% increase back on calculated strokes.;Drill 12.25" hole f/ 4548't/ 5309' (3408' TVD), 761' @ 127 FPH average. 600 GPM, 2440 PSI, 80 RPM, 12K TO 5-20K WOB. 9.2 ppg MW, 91 vis, 10.0 ppg ECD. Max gas 47 units. 167K PU / 100K SO / 125K ROT.;Drill 12.25" hole f/ 5309'11 5575' (3545' TVD), 266'@ 133 FPH average. 585 GPM, 2340 PSI, 80 RPM, 12K TO, 15K WOB. 9.3 ppg MW, 85 vis, 9.80 ppg ECD. Max gas 152 units. 177K PU / 95K SO / 125K ROT.;Observed 152 unit gas spike at 00:40 = lag time from drilling -5290'. Begin 4°1100' build at 5405'. Pumped high vis sweep at 5570'. Ugnu MB at 5254' and MC at 5447'.;Shaker screens blinded off w/ oil and sand f/ Ugnu sands. Slow pumps to 400 GPM. Slow to 300 GPM & clean each shaker individually. Filling rock washer w/ no super suckers on location. Slow to 150 GPM & install 120 mesh screens. Added 4 drums of Screen Kleen to help clean up shakers - 0.35%.;Circulated out sweep: 20% increase and back on calculated strokes. Increase Flow to 375 GPM then 450 GPM.;Drill 12.25" hole f/ 5575' U 5690' (3598' TVD), 115' @ 58 FPH average. 450-600 GPM, 1780-2560 PSI, 80 RPM, 12K TO, 1-35K WOB. 9.2 ppg MW, 74 vis, 9.60 ppg ECD. Max gas 101 units. 182K PU / 97K SO / 126K ROT.; Hauled 1455 bbls H2O from 6 Mile lake for total = 2950 bbls Hauled 0 bbls heated H2O from G&I for total = 0 bbls Hauled 1561 bbls cutting/liquids to MPU G&I for total= 2602 bbls 0 bbls daily losses, 0 bbls cumulative losses. 5/4/2019 Drill 12.25" hole F/ 5690' T/ 6240' 3557' ND 550' 91 FPH average. 600 GPM, 2600 PSI, 80 RPM, 12K TO, 1-25K WOB. 9.4 ppg MW, 74 vis, 10.47 ppg ECD. Max gas 65units. 182K PU / 97K SO / 126K ROT.;Drill 12.25" hole F/ 6240' T/ 6698' (3813' TVD) 458'@ 114 FPH average. TO Called at 6698'. 600 GPM, 2690PSI, 80 RPM, 12K TO, 1-20K WOB. 9.2 ppg MW, 74 vis, 9.60 ppg ECD. Max gas 154 units. 180K PU / 94K SO / 123K ROT.;Last survey @ 6644.72' MD / 3808.96' TVD, 84.31 ° inc, 126.57° azm, 19.99' from plan, 14.92' low and 13.3' right. Top of Schrader Bluff OA -1 at 6651' MD 1381 O'TVD.;Pull one stand & work pipe F/ 6544 T/ 6633'. Circ sweep around at 600 GPM, 80 RPM, Sweep came back on time with Minimal increase in cuttings. Clean hole. RIH back to btm, perform flow check - static and start back reaming out.;Back ream out from 6698' to 4200' at 550 GPM, 1880 PSI, 80 RPM, 15K TQ, 10.6 ppg ECD. 5-10 min per stand slowing down if pressure, TQ, or drag increases. 5420' pulled 15K over and torqued up to 25K, pumps off and RIH to 5437'then back ream clean.;Continue to BROOH f/ 4200' t/ 1316' at 550 GPM, 1890 PSI, 80 RPM, 11 K TO, 10.6 ppg ECD. 5-10 min/stand slowing down if pressure, TO or drag increases. ECD cleaned up to 10.1 ppg at 3800'. Increase pulling speed to 3 min/stand.Began to see ECD climb from 10.0 ppg to 10.6 ppg from 2000', end of build.;Shakers began to unload at 1580', slow backreaming speed 10 min/stand to 1507' then resume 5 min/stand.; Hauled 1439 bbls H2O from 6 Mile lake for total = 4389 bbis Hauled 0 bbis heated H2O from G&I for total = 0 bbis Hauled 1621 bbls cutting/liquids to MPU G&I for total= 4223 bbis 0 bbis dailv losses 0 bbis cumulative losses 5/5/2019 Continue to back ream out of the hole F/ 1316' T/ 746'. 60-80 RPM, 550 GPM, Pull slow last 3 stands and let well clean up. Last a stand of DP Pull with no ROT & orient high side before pulling HWDP on elevators. Get two btm up on last stand with only sand coming back. Never really cleaned up.;POOH on elevators standing back HWDP F/ 746'T/ NMFDC clean. Hole took proper hole fill. UD 3 NMFC, plug in and download MW D.;UD BHA & Drain motor. Break out bit. Bit grade- 1 -1 -CT -G -E -I -ER -TD. Clean and clear rig floor.;R/U to run 9-5/8" Casing with Doyon casing. M/U Volant tool with Cmt swivel to TO & install bail extensions. Install XO on FOSV.*P/U 9-5/8" shoe track to 120'. Baker Loc shoe track and torque to 20,960 ft/lbs. Two 9-5/8"x12-1/4" Expand-o-lizers on shoe joint and 1 each on spacer and float collarjoint. Check floats. Good. Pump through with Volant.;Run 9-5/8" 40# L-80 TXP BTC -SR casing as per tally, filling on the fly with Volant and breaking circ every 10 joints F/ 120' T/ 2384'. Torque to 20,960 ft/lbs w/ Volant. One centralizer per joint to #25 and every other to #60. 20-40'/min running speed. 18.2 bbls Iost.;Circulate bottoms up below the permafrost at 2384'. Stage up pumps from 2 BPM, 110 PSI to 7 BPM, 170 PSI. Reciprocate 40' while circulating. Pumped 197 bbis and only lost 5 bbls.;Run 9-5/8" 40# L-80 TXP BTC -SR casing as per tally, filling on the fly with Volant and breaking circ every 10 joints F/ 2384' T/ 5280'. Torque to 20,960 ft/Ibs w/ Volant. One centralizer every otherjoint to #101, then every joint to 117.;Place Halliburton ESIPC between joints #106 & 107 with centralizers on pup joint above and below ESIPC. Place one centralizer on every otherjoint from #119 to #129. 30-40'/min running speed. 12.2 bbis lost, 35.4 cumulative for casing run.;Circulate a bottoms up at 5280' before the final build section. Stage up pump s from 1 BPM, 200 to 6 BPM, 250 PSI. Reciprocate 40' while circulating. Pumped 302 bbls and lost 21 bbls.:Run 9-5/8" 40# L-80 TXP BTC -SR casing as per tally.fillinao the fly with Volant ea circ avow 10 io nts 5280'T/ 6691'. Washed last joint down w/ 2 BPM, 250 PSI. Place one centralizer on every other joint f/ #131 to #161. 40-607min running speed. 300K PU / 106K SO.;164 joints of 9-5/8" casing, 104 each 9-5/8"x12-1/4" Expand-o-lizers and 10 stop rings ran. 3.6 bbls lost, 60 bbis cumulative.;Hauled 770 bbis H2O from 6 Mile lake for total = 5159 bbis Hauled 0 bbis heated H2O from G&I for total = 0 bbls Hauled 938 bbis cutting/liquids to MPU G&I for total= 5161 bbis 38 bbis daily losses to midnight, 38 bbl cumulative losses. 5/6/2019 Circ btm up at 7 BPM, 250 PSi. Work pipe while ROT at 25K TO & 5 RPM F/ 6634' T/ 6695'. Conduct PJSM on cmt job & Build HV spacer as per HES. 60 BBL.;Shut down. Blow down TD, R/U Circ lines to cmt tool. Line back up to Rig & Cir while waiting on HES to prime up.;Line up to HES. Flood lines with water and test lines to 4000 psi. Good. Mix & pump 55 bbl Clean Spacer. Drop Plug. Ppmn 999 bhl 540 Sx 190 1 can . t Mix R Pump 7S hhl drA1 SX 15 B* Tail cmt. Drop top plua. Chase with 20 bbl H2O. Displace 91 .;Pump 60 bbl spacer out of pit 4. Displace with 137 bbl 9.3 PPG mud & bump plug on calculated strokes. Pressure up to 500 over at 1200 psi, Final lift at 700 psi. Bleed down and check floats. Good. CIP at 13:30.;Stage up pumps to 6 bpm. Saw Pol-e-flake back at 60 bbl. Take all returns to pits until started getting chunky. 150 BBL. Got all spacer back and trace cmt. Started c� getting 2nd spacer back. Dump to cellar. Dumped 100 bbl & took back to the pits. Good 9.3 back. Move pipe 8" pulling 100-250K.;Started getting thick mud back. dump to cellar another 100 bbl. Shut down and prep pits for thick mud returns. Stage up pumps to 6 bpm taking ret to pits and pump HV sweep through curt tool. Circ Two btm up & Pressure dropped from 1900 psi to 350 psi at 8 bpm. Tool opened all the way.;Continue to circ 6-8 BPM. Sweep came ,Q back bringing contaminated mud back with it. Getting clabbered mud back in chunks in returns. Cleaned up after 5 btm up total. Shut down, Break out volant & service. Re engage and circ at 4 bpm while preparing for second stage. Conduct PJSM for second stage.;Perform grid stage cement rob. Pump 5 bbls water, ✓'y 2 BPM, 200 PSI. Mix & pump 60 bbis 10.0 ppg Clean Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 3.5 BPM, 190 PSI. Mix & pump 326 bbis 12.0 ppg Perm L lead cement 1415 sxs Ccd 4,407 yield) 4.2 BPM 320 PSI ICP 600 PSI FCP Began seeing spacer back @ 256 bbls lead pumped & good cement i @ 326 bbis. Mix & pump 56.2 bbls 15.8 ppg Premium G tail cement (270 sxs @ 1.169 yield), 3 BPM, 410 PSI ICP, 460 PSI FCP. Pump 20 bbls water @ 4.8 BPM, 410 PSI. Rig displace w/ 9.4 ppg spud mud. 6 BPM, 390 ICP, 790 PSI FCP, 400 PSI Iift.;Slow to 3 BPM, 530 PSI for the last 10 bbis. Bumped plug @ 1592 stks (1604 stks calculated). Pressure up & shift ESICP closed at 1560 PSI. Continue up to 1870 PSI to ensure closed. Bleed off, no fluid flowing back - confirmed closed. CIP @ 21:45. 180.8 bbis of cement back to surface.:Disconnect & N/D drearier line. Disconnect accumulator lines from knife valve. Flush surface stack 2x with black water. Function annular 4x times with black water. Suck mud out of 9-5/8" stuck to casing cut level. Power down accumulator and disconnect lines to annular.;Hoist diverter stack. Install 9-5/8" casing slips as per wellhead representative with 60K on slips. Cut 9-5/8" casing and UD cut joint (16.49). N/D flow nipple and riser. N/D annular and diverter adapter. Make final cut (0.4'+164=16.80'total cut) Sim -ops: RID casing equipment and Volant.; Install 91 slip lock head, casing spool and tubing spool. Test well head void to 500 PSI for 5 min. and 2475 PSI for 15 minute.; Hauled 550 bbis H2O from 6 Mile lake for total = 5709 bbis Hauled 820 bbis heated H2O from G&I for total = 820 bbls Hauled 1537 bbls cutting/liquids to MPU G&I for total= 6698 bbls 42 bbls daily losses, 80 bbis cumulative losses. 5/7/2019 Install blank flange and 4" Cameron valve on spool. Torque bolts on casing and tubing spools.;N/U and align BOP stack, Install MPD riser, install both mouse holes. Sim -ops: clean mud pits, prep rig floor for testing.;lnstall test plug and 5" test jt, R/U BOP test equipment, flush and drain gas buster, flood stack and lines with water. Perform BOP body test 250 PSI low 13000 PSI high - good. AOGCC notified of test @ 07:48 on 5/6/19. AOGCC rep Adam Earl waived witness for BOP test @ 06:28 on 5/7/19.;Test BOP equipment as per PTD and AOGCC requirement. #1: Annular on 5"" test joint (250 PSI low 12500 PSI high) #2: 4.5"x7" VBR rams on 5"" test joint, valves #12, 13 & 14, 3" Demco, upper IBOP #3: Valves #1, 9 & 11, HCR kill, lower IBOP #4: Valves 95, 8 & 10, manual kill - F/P choke.;#5: Valves #4, 6 & 7, 5" TIW #1 - F/P TIW # #6: Valves #2, 5" TIW #2 #7: HCR choke, 5" Dart valve 98: Manual choke #9: 2.875"x5" VBR lower rams on 5" test joint #10 Blind rams, valve #3 #11 Hydraulic choke "N'#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: 3000 PSI system pressure, 1700 PSI after closure, 41 sec for 200 PSI recharge, 180 sec for full PSI recharge, 2025 PSI six nitrogen bottle average.;R/D BOP test equipment. Blow down lines. Clear rig floor. Mobilize bit, saver sub & wear bushing to the rig floor.;lnspect saver sub - found thread worn. C/O saver sub with new NC -50 saver sub. Install 9-118" I.D. long wear bushing.;M/U 8-1/2" Baker Hughes VM -1 bit, Sperry 7" 1.22" motor, float sub and three NMDC to 119'. TIH w/ HWDP from the derrick to 673'. Single in the hole with 5" drill pipe from the shed to 2353', utilize 2.91" drift.;Fill pipe & wash down from 2353' with 420 GPM, 750 PSI. Tag cement at 2393'. 101 K PU / 80K SO.;Leak from top drive. Lay down single to investigate. Upper IBOP leaking. Begin changing upper IBOP.;Hauled 235 bbis H2O from 6 Mile lake for total = 5944 bbis Hauled 150 bbis heated H2O from G&I for total = 970 bbls Hauled 1051 bbis cutting/liquids to MPU G&I for total= 7749 bbls 0 bbls daily losses, 80 bbis cumulative losses. 5/8/2019 Continue to C/O upper IBOP, ensure proper operation, pressure test to 250 psi low, 3000 psi hi 5 min ea. charted.;M/U TD, Break circulation, drill hard cement Y 2393' to 2400', 450 gpm, 750 psi, 40 rpm, 5k torque, 5k wob, tag cementer tool on depth. drill plug and cementer tool 40 rpm, 3-4k torque, 3-5k WOB, ream 2 limes, attempt to pass thru no rotary or pumps, set down Sk, ream 2 more times.;Pass thru no pump or rotary with no issues. PU 105K, SO 80K, ROT 90K.;Drift and single in with 5" NC50 DP V 2448' U 6387' ( 180 jts ) fill pipe @ 4481'. Wash down f/ 6387' wfth 220 GPM, 510 PSI. See cement stringer at 6510' and 10K tag at 6519'.;Rack back stand & blow down top drive. R/U and perform 9-5/8" casing pressure test . Close upper pipe rams. Pump down drill string and kill line. Hold 2500 PSI for 30 minutes on chart - good test. Pumped 5.3 bbls and bled back 5.3 bbls. R/D test equipment and blow down Iines.;Wash V down to 6529'. Drill shoe track w/ 450 GPM, 1300 PSI, 40 RPM, 15-20K TO, 5-15K WOB. Doll cement f/ 6529't/ 6567', baffle adapter to 6569', float collar V 6609' V 6610' & shoe at 6689' to 6691' (all on depth). Reamed BA , FC & shoe 2x times & slide through clean. Cleanout rathole to 6698'.; Drill 20' of new hole f/ V"6 6698' U 6718' (3815' TVD), 20' drilled, 40 FPH average. 450 GPM, 1300 PSI, 40 RPM, 15-20K TQ, 81K WOB. 225K PU / 75K SO / 112K ROT. Rack back stand to 6672'.;Circulate and condition mud prior to performing FIT. 450 GPM, 1260 PSI, 40 RPM, 16K TO. Reciprocate pipe 90'. Pumped 1.6 bottoms up, 9.4 MW in and out.;Drop Scientific Drilling recorded mode North seeking drop gyro (30.T tool length). Pump down at 210 GPM, 390 PSI, increase to 305 GPM, 730 PSI then 400 GPM, 1110 PSI. Pumped 2x drill pipe volumes. No pressure indication of gyro landing on seat.;Blow down top drive & R/U test equipment. Perform FIT to 12 0 op, EMW. 515 PSI @ 6691' MD / 3813' TVD with 9.4 ppg mud. Pumped 1.1 bilis, bled back 1.0 bbls.;Perform flow check - static. POOH f/ 6672'V 1620'. Wait 2 minutes in slips for gyro survey every connection. Drift check gyro every hour - 6 minutes.;Hauled 60 bbls H2O from 6 Mile lake for total = 6004 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls 1(, Hauled 114 bbls cutting/liquids to MPU G&I for total= 7863 bbls 5/9/2019 TOOH ff 1620' to 724' gyro survey every connection. RIH to 1104', perform survey overlap as per gyro, TOOH to 673' at the HWDP. Correct displacement on TOOH.;Flow check well, static. UD 15 jts excess HWDP. Rack back HWDP jar stand and stand of NMDC to 126'. UD remaining BHA #2. Bit grade= 2/3/A/CD/E/1/WT/BHA.;Load out tools, clear rig floor. Monitor well with trip tank.;PJSM, load tool to rig floor, M/U 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: R/U MPD lines.;RIH w/ drill collars, HWDP and jars from the derrick to 272'. Drift and P/U one joint of 5" DP to 303'. Shallow pulse test MWD 450 GPM, 930 PSI - good test. BD TD.;Ddft, PILI and Single in the hole with 5" drill pipe from 303' to 217T.;Fill pipe. Pressure test Geo-Span lines to 3500 PSI, good test. Break-in Geo-Pilot seals and function test Geo-Pilot good. BD TO. C/O 5" drill pipe elevators due to safety latch not operating correctly.;Continue to single in the hole f/ 2177' U 4463' (132 jts ), fill pipe and blow down top drive. TIH f/ 4463' V 6649', fill pipe and blow down the top dnve.;Slip & cut drilling line (59' cut). Service rig. Sim-ops: pressure test MPD lines to 250 PSI low / 1250 PSI high for 5 min, each.;PJSM with Doyon & Beyond. Remove trip nipple and install MPD RCD. Flood lines and circulate to ensure proper operation of MPD equipment.;PJSM with Doyon, Beyond & M-1. Perform displacement with new 8.8 ppg Flo-Pro NT mud. Pump 30 bbls high vis spacer. Displace with new mud at 305 GPM, 950 PSI. Slow to 225 GPM, 360 PSI with spacer to surface. Perform flow check - close MPD chokes no pressure build up. Obtain slow pump mtes.;Drill 8-1/2" production hole from 6718' to 7030'(3829 TVD), 312' drilled, 89 FPH average. 450 GPM, 1100 PSI, 120 RPM, 15K TO, 5-12K WOB, 196K PU / 65K / 115K ROT. 9.99 ppg ECD, 221 u max gas, 8.85 ppg MW, 40 vis.;Drill with MPD choke wide open. Close choke on connections to monitor pressure - none. Last survey at 6960.26' MD / 3820.01' TVD, 89.70° inc, 123.63° azm, 17.70' from plan, 12.03' low and 13.00' right.;Hauled 230 bbls H2O from 6 Mile lake for total = 6234 bbis Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 228 bbls cutting/liquids to MPU G&I for total= 8091 bbls 0 bbls daily losses, 0 bible cumulative losses. 5/10/2019 Drill 8-112" production hole from 7030' to 769T (3833' TVD), 667' drilled, 111.16 FPH average. 500 GPM, 1490 PSI, 120 RPM, 17K TO, 5-20K WOB, 10.55 ppg ECD, 248u max gas, 9.1 ppg MW, 46 vis. 215K PU / SOK / 115K ROT. Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.;Ddlling in the OA-1 until 7,127' md, hit a 9' DTE fault, aim for 87deg inc, back in the sand at 7,204'. Out of the zone from 7,127' to 7,204' ( 7T). Start undulation dawn to OA-3 at 7559. Pump 30 bbl hi vis at 7500', back on time w/ 20% increase.;Drill 8-1/2" production hole from 7697to 8430' (3850' TVD), 733' drilled, 122.1 FPH average. 500 GPM, 1450 PSI, 120 RPM, 15K TO, 5-20K WOB, 10.48 ppg ECD, 266u max gas, 9.1 ppg MW, 46 vis. 215K PU / NA / 115K ROT. Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.;Drill OA2 from 7717' (3834' tvd) to 7865' (3842' tvd). We will remain into OA 3 until 9,400' Pumped 30 bbl hi vis sweep @ 7980', sweep back on time w/ 50% increase. Note: ream and cleanup 12.5 deg dogleg f/ 8113' to 8123' reducing to 9 deg. Lost slack off weight at 7984'.;Drill 8-1/2" production hole f/ 8430' V 9032' (3852' TVD), 602' drilled, 100.33 FPH average. 510 GPM, 1490 PSI, 120 RPM, 21 K TO, 5-20K WOB. 10.35 ppg ECD, 318u max gas, 9.1 ppg MW, 44 vis. 220K PU / NA / 114K ROT. Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.;Remain in OA 3. Pumped 30 bbl hi vis sweep at 8556' w/ 40% increase and 100 strokes late. Sweep pumped at 9032' was 250 strokes late w/ 50% increase.;Drill 8-1/2" production hole f/ 9032't/ 9623'(3840' TVD), 591' drilled, 98.5 FPH average. 505 GPM, 1580 PSI, 120 RPM, 20K TO, 6-18K WOB. 10.51 ppg ECD, 89u max gas, 8.85 ppg MW, 46 vis. 215K PU / NA / 112K ROT. Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.;Begin building up at 9158'. Pumped 30 bbl hi vis sweep at 9509' with 50% increase & back on calculated strokes. Drilled 16 concretions for a total thickness of 113' (4% of the lateral). OA-2 from 9423' to -9550' (top of OA-2 initial pick).;Last survey @ 9533.80' MD / 3845.31' TVD, 92.98' inc, 126.29° azm, 10.91' from plan, 10.83' high and 1.26' Ieft.;Hauled 560 bbls H2O from 6 Mile lake for total = 6564 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 1289 bbls cutting/liquids to MPU G&I for total= 9380 bbls 0 bbls daily losses, 0 bbls cumulative losses. 5/11/2019 Drill 8-1/2" production hole V 9623' U 10270' (3839' TVD), 647' drilled, 107.8 FPH average. 509 GPM, 1660 PSI, 120 RPM, 22K TQ, 8K WOB. 10.59 ppg ECD, 87u max gas, 9 ppg MW, 48 vis. PU 250k, SO NA, ROT 115k. Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.;Pump 30 bbl hi vis sweep @ 9986, sweep back 150 stks late w/ 20% increase. Drill in the OA-1.;Drill 8-1/2" production hole f/ 10270'V 11000' (3840' TVD), 730' drilled, 121.6 FPH average. 500 GPM, 1670 PSI, 120 RPM, 15K TO, 5-20K WOB. 10.52 ppg ECD, 110u max gas, 8.9 ppg MW, 46 vis. PU 175k, SO 60k, ROT 112 Drill with MPD choke wide open. Monitor SIP during connections= 0 psi.; 10500' add 8 drums of Lo-fork lube, bring lubes in system to 1 % reducing torque f/ 24k to 15k, P/U V 260 to 160k, seeing S/O from none to 60k, 10460' pump 30 bbl hi vis sweep, back on time w/ 10% increase. At 10840' undulate to OA-3 10938' pump 30 bbl hi vis sweep, back on time w/ 40% increase.; Drill 8-1/2" production hole V 11000' V 11842' (3864' TVD), 842' drilled, 140.3 FPH average. 500 GPM, 1810 PSI, 120 RPM, 17K TQ, 5-15K WOB. 10.76 ppg ECD, 110u max gas, 8.8 ppg MW, 45 vis. PU 180k, SO 55k, ROT 110k. Drill with MPD choke wide open. Begin holding 60 PSI at 11126'.; Pumped 30 bbl hi vis sweep at 11507', back on time w/ 30% increase. Drilled OA-2 V 11110' V 11250'. Drilling in OA-3.; Drill 8-1/2" production hole f/ 11842' V 12681' (3870' TVD), 839' drilled, 139.8 FPH average. 505 GPM, 1980 PSI, 120 RPM, 19K TO, 6-12K WOB. 11.07 ppg ECD, 126u max gas, 8.95 ppg MW, 43 vis. PU 195k, SO xx, ROT 108k. Drill w/ MPD choke wide open and holding 60-80 PSI on connections.;Sweep @ 11980' back on time w/ 40% increase and @ 12456' back 50 strokes late w/ 20% increase. Lost down weight at 12075'. Add 100 bbls new mud at 12300'. Drilled in OA-3 to fault #2 at 12347' w/ 10-12' DTS throw and in OA-2 V 12347' V 12516'. Drilling in OA-1.;Last survey @ 12576.38' MD / 3871.77' TVD, 91.06' inc, 127.15° azm. 29.08' from plan, 28.81' high and 3.96' right.;Hauled 760 bbis H2O from 6 Mile lake for total = 7324 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 979 bbls cutting/liquids to MPU G&I for total= 10359 bbls 0 bbis daily losses, 0 bbls cumulative losses 5/12/2019 Drill 8-1/2" production hole f/ 12681' V 13313' (3866' TVD), 632' drilled, 105.3 FPH avg 501 GPM, 2000 PSI, 120 RPM, 23K TQ, 13K WOB. 11.22 ppg ECD, 129u max gas, 9 ppg MW, 45 vis. PU 194k, SO none, ROT 107k. Drill w/ MPD choke wide open, increase SIP f/ 80 psi to 100 psi during conn. @ 13210';Al 13000' add safe carb 500 and 750 bringing background LCM in system to 5 ppb Pump 30 bbl hi vis sweep @ 12930', 250 stks late w/ 25% increase. Drill in the OA-1 to fault #3 @ 13235' build up to 95 deg;Drill 8-1/2" production hole f/ 13313' V 13886' (3873' TVD), 573' drilled, 95.5 FPH avg 500 GPM, 2070 PSI, 120 RPM, 25K TO, 5-15K WOB. 11.68 ppg ECD, 150u max gas, 9.1 ppg MW, 46 vis. PU 205k, SO none, ROT 107k. Drill w/ MPD choke wide open, hold 100 psi SIP @ connections;Conlinue to build up 95 deg until the base of OA-4 at 13528.7' rad, fault 60' DTN throw, steer 89.7 deg. back in the OA-3 sand at 13,688' Md. Out of zone 453'f/ 13235' to 13688. Entered OA-2 at 13834', steering back down to OA-3.;Pump 30 bbl hi vis sweep @ 13423', back 100 stks late with 10% increase. At 13690' dump and dilute with 200 bbls new 8.8 fie pro mud. Al 13789' seeing up to 27k torq, Increase lube f/ 1 to 1.5% adding 6 drums lo- tork.;DrillB-1/2" production hole f/ 13886'V 14455' (3900' TVD) 569' drilled, 94.8 FPH avg. 500 GPM, 2060 PSI, 120 RPM, 23K TQ, 5-15K WOB. 11.26 ppg ECD, 146u max gas, 9.2 ppg MW, 44 vis. PU 210k, SO none, ROT 110k Drill w/ MPD choke wide open, hold 110 psi SIP @ connections.;Pumped 30 bbl hi vis sweep at 13979' back 250 strokes late w/ no increase. Exited OA-2 and entered OA-3 at 14001'.;Drill 8-1/2" production hole f/ 14455' V 15171' (3897' TVD) 726drilled, 121 FPH avg. 510 GPM, 2080 PSI, 120 PRM, 25K TO, 6-12K WOB. 11.34 ppg ECD, 133u max gas, 9.0 ppg MW, 49 vis. PU 203k, SO none, ROT 108k. Begin building up at 14836'. Entered OA-2 at 14991';Drill w/ MPD choke wide open, hold 110 psi SIP @ connections Pumped 30 bbl hi vis sweep @ 14550' back 300 strokes late w/ 30% increase & 15026' back 150 stks late w/ no Inc. Last survey @ 15051.42' MD / 3900.69' TVD, 91.92° inc, 126.55° azm. 16.23' from plan, 13.39' low & 9.18' Ieft;Drilled 46 concretions for a total thickness of 267' (3.2% of the lateral);Hauled 660 bbls H2O from 6 Mile lake for total = 7984 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 979 tools cutting/liquids to MPU G&I for total= 11338 bbls 0 bbls daily losses, 0 bbls cumulative losses. 5/13/2019 Drill 8-1/2" production hole f/ 15171't/ 15710' (3890' TVD) 539 drilled, 89.8 FPH avg. 503 GPM, 2090 PSI, 120 RPM, 24-27K TQ, 5-17K WOB. 11.33 ppg ECD, 138u max gas, 9.1 ppg MW, 48 vis. PU 190k, SO none, ROT 110k. Drill w/ MPD choke wide open, hold 100-105 psi SIP @ connections;30 bbl hi vis sweep pumped at 15501', back 150 stks late with no increase. Continue to building up 91 deg, Entered OA-1 at 15243';Drill 8-1/2" production hole f/ 15710' V 16306' (3899' TVD) 596' drilled, 108.3 FPH avg. 500 GPM, 2150 PSI, 120 RPM, 23K TQ, 5-15K WOB. 11.38 ppg ECD, 170u max gas, 9.1 ppg MW, 45 vis. PU 205k, SO none, ROT 105k. Drill w/ MPD choke wide open, hold 100-105 psi SIP @ connections.;At 16255' dump and dilute with 290 bbls new 8.8 ppg Flo pro mud. At 16285' hit fault, 45' DTN throw, Geo called TO @ 16306. Take final survey @ 16237.5' MD / 3899.07' TVD, 89.39° inc, 128.33' azm. 36.75' below the line, 0.14' right.;60 concretions were drilled in the lateral, for a total thickness of 352' (3.66%). 4 faults were crossed in the Iateral.;Rack 1 stand back to 16258', Pump tandem 50 bbl to vis, 8.7 ppg then 30 bbl hi vis, 10.1 ppg sweep. Circulate hole clean while reciprocating full stand, 550 GPM, 2500 PSI on up stroke and 450 GPM, 1850 PSI on down stroke. Sweep back 350 strokes late w/ 10% increase.; Increase lube to 4% w/ 4 drums LoTorq and 24 drums 776. Rack back stand every bottoms up to 15884'. Torque decreased from 20k to 14k and from no SO to 60K SO. ECD decreased f/ 11.76 to 11.14. Circulated a total of 37570 stks, 4.8 bottoms up.;Service rig. Grease wash pipe and blocks. Check top drive oil. Monitor MPD pressure over 25 min.- bled down from 72 PSI to 42 PSI.;TIH on elevators f/ 15884'V 16306', PU 200k, SO 60k. Fill pipe and get SPRs. Establish 550 GPM and 120 RPM.;BROOH f/ 16306'V 13600'550 GPM, 2470 PSI ICP / 2200 PSI FCP, 120 RPM, 15k TO. 11.14 ECD start / 11.09 ECD end. 4-5 min/stand pulling speed. Correct pipe displacement. 50 PSI line pressure while circulating and 40-50 PSI trapped on connections.; Hauled 601 bbls H2O from 6 Mile lake for total = 8585 bible Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 1088 bible cutting/liquids to MPU G&I for total= 12426 bbls 0 bbls daily losses, 0 bbls cumulative losses. 5/14/2019 BROOH f/ 13600'V 11097'550 GPM, 2450 PSI ICP / 2020 PSI FCP, 120 RPM, 10k TO. 11.14 ECD start / ECD currently 10.71 4-5 min/stand pulling speed. Loss rate 2 bph BROOH MPD holding 50 PSI line pressure while circulating and 50-70 PSI trapped on connections.;BROOH f/ 11097' V 6651'550 GPM, 2020 PSI ICP / 1720 PSI FCP, 120 RPM, 5k TO. 10.71 ECD start / ECD currently 10.53 4-5 min/stand pulling speed. Loss rate at -1 bph MPD holding 100 PSI line pressure while circulating and 130 PSI trapped on connections.; Pump 30 bbl Hi-Vis sweep around while Rot & Recip string. 550 GPM - 1700 psi, 60 RPM - 5k Tq. Continue circulating for total 2x bottoms up. No increasing in cutting with sweep to surface. 31 bbls lost while BROOH.;Perform MPD pressure test. Shut in choke for 15min, Initial shut in pressure of 125 psi decrease to 115 psi. Bleed off 3/4 bbls. Pressure @ 16 psi increasing V 43 psi. Bleed down to 16 psi and pressure increase V 30 psi. Bleed down to 16 psi and pressure increase V 20 psi.;Crew change, PJSM. Weight up active pit and circulate 9.1 ppg mud around. 500 GPM - 1400 psi, 120 RPM - 4k Tq. Rot & Recip string.;Monitor well for flow. Less than 1/4 bbls returned over 20 min becoming static. Continue to monitor well -static- Remove RCD Bearing and install trip nipple, check for Ieaks.;Hang blocks, cut and slip 79' drilling line. Service dwks, roughneck and TopDrive. Start to see a static loss rate @ 1 bbl/hr.;POOH on elevators V 6651' V 6175 , laying down singles to shed. Loss rate @ 1 bbithr.;Hauled 630 bbls H2O from 6 Mile lake for total = 9215 bbls Hauled 0 tools heated H2O from G&I for total = 970 bbls Hauled 691 bbls cutting/liquids to MPU G&I for total= 131176 bbls 31 bbls dailv losses,31 bbls cumulative losses 5/15/2019 POOH on elevators f/ 6175' to HWDP @ 272' UD 5" DP to pipe shed. Loss rate @ 1 bbl/hr, 14 bbl losses f/ shoe to HWDP.;Monitor well. UD HWDP, Jars & Flex Collars. Plug in and Download MWD data. UD DM Collar, UD and inspect remaining BHA #3, Break out- UD 8 1/2" PDC Bit, grade = 2/1/CT/N/X/I/WT/TD, ILS under cut 2" on top f/ BROOK Submit 24 hr BOP test notification to AOGCC.;Clear and Clean rig floor. Prep for UD drill pipe from Derrick. SimOps: R/D MPD lines. C/O TD filter housing, cleaning pits 4, 5. Monitor well with trip tank, static loss rate 1 bph.;PJSM, UD 37 stands of 5" drill pipe from derrick using mouse hole, 70 stands left in derrick. Monitor well with trip tank, static loss rate continues at 1 bph.;PJSM; Mob 3-1/2" handling equipment to rig floor and R/U to M/U stands of 3-1/2" inner string. Monitor well with trip tank, Static loss rate @ 1-1.5 bbls/hr.;M/U 63 stands of 3-1/2", 9.3#, L- 80, EUE tubing and rack in Derrick. Monitor well with trip tank, Static loss rate @ 1.5 bbls/hr.;Hauled 135 bbls H2O from 6 Mile lake for total = 9350 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 240 bbls cutting/liquids to MPU G&I for total= 13357 bbls 42 bbis daily losses, 73 bbls cumulative losses. 511612019 Continue to M/U 42 stands of 3-1/2", 9.3#, L-80, EUE tubing and rack in Derrick, 105 stands total. Monitor well with trip tank, Static loss rate @ 1.5 bbis/hr.;Clear rig floor, Remove 9 1/8" wear bushing, R/U and flush BOP stack with jet tool. BD TD.;Crew change, R/U test equipment, Install test plug, Flood lines, choke manifold and stack with fresh water. Purge the air from the system & perform body test. Good Test. Monitor annulus while testing, 1.5 bph static loss rate. AOGCC rep M. Herrera waived witness to BOP test @ 05:48.;Test BOP equipment as per AOGCC & PTD requirements. All tests performed to 250 PSI low 13000 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 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 2-718"x5"" VBR on 5" test joint. Accumulator test: 3000 PSI system, 1600 PSI after closure, 200 PSI in 36 sec., full in 198 sec., 6 nitrogen bottle avg 2000 PSI. 7: Annular on 3-112" test joint, HCR choke 8: Lower 2-7/8"x5"" VBR on 3-1/2" test joint.;9: Upper 4-1/2'x7"" VBR on 7" test, Manual choke 10: Blind rams & choke valve 3, 3-112" TIW 11: Hydraulic choke A 12: Manual choke B;Pull test plug and UD test joint. Blow down choke & kill lines. Install 9 1/8" ID wear bushing.;Rigged up casing running equipment and M/U safety joint for 6-5/8" PDL run.;Hold PJSM with rig and casing crew. P/U shoe joint, P/U and RIH w/ 6-5/8", 209, L-80, Hydril 563, Pre-Drilled liner U 6304'. Centralizer every joint. M/U Tq = 7100 ft/lbs. Losses @ 1.25 BPH, Total of 7.5 blots loss while running in hole w! liner. Total losses last 24 hr = 29 bbls;Hauled 60 bbls H2O from 6 Mile lake for total = 9410 bbls Hauled 0 bbis heated H2O from G&I for total = 970 bbis Hauled 109 bbis cutting/liquids to MPU G&I for total= 13466 bbis 22 bbis daily losses, 95 bbis cumulative losses. 5/17/2019 Cont P/U and RIH w/ 6-5/8"", 20#, L-80, Hydril 563, PDL it 6304' t/ 9709'. PIU 145k, SIO 82k. ( 220 its PDL, 17 its solid liner ) Cent every joint. total of 235, M/U Tq = 7100 ft/lbs. Note: before exiting 9 5/8 shoe 6691'= PIU 152k, S/0 = 90k. Losses @ 1.1 bph over calc disp. 11 bbls total.;Change handling equipment to 3-1/2". Change safety joint XO's to 3-1/2" w/ triple connect. Rig up 4-112" double stack power tongs and false table.; PJSM with rig, BOT and casing crew. M/U 2 3/8" slick stick assy, RIH with 3-1/2", 9.3#, L-80 E U E tubing from Derrick to 5112' torque to 3100 ft/lbs.;C/O to 5" elevators, M/U triple connect, P/U to ensure liner free, P/U to 184k- broke free. P/U 175k, S/O 108k, UD triple connect. R/U 3 112" elevators. Monitor well, Loss rate continues at 1 BPH.;Continue RIH with 3-11", 9.3#, L-80 EUE tubing from Derrick f/ 5112' U 9698'. 3100 ft/lbs Tq. P/U = 85K, SIO = 64K. No-Go out w/ 5k wt. UD 2 its for space out.;M/U safery it & triple connect. RID false table and break over 6-518" PDL. P/U string free @ 205k. Work string f/ 97091' 1:19689'. 185k Up wt, 108k down. Reset PDL in compression, R/U false table and UD safety joint. M/U 2x Pup its, 10.15' & 8.16'. RID triple connect.;M/U Baker SLZXP Packer, fill liner tie-back sleeve with Xanplex, RIH w/3 its 5" HWDP t/ 9840. Set 3-1/2" inner string 6.7' off no-go. Drift HWDP w/ 2.44".;Kelly up and break circulation. Pumped 20 bbis. Stage up U 2.2 BPM -410 psi. PIU = 190k, SIO = 108k. Sting would not rotate freely @ 10k Tq, Rotation achieve only while moving string down. B/D TopDrive.;Continue running in hole with the 6-5/8" pre-drilled liner on 5" HWDP singles from shed, U 13766'. Fill pipe of the fly and top off every 5 Stands. Losses at -1 BPH. Total 24hr losses = 29.5.;Hauted 50 bbis H2O from 6 Mile lake for total = 9460 bbis Hauled 0 bbis heated H2O from G&I for total = 970 bbis Hauled 0 bbis cutting/liquids to MPU G&I for total= 13466 bbis Mud Losses: 29.5 bbis daily losses, 124.5 bbls cumulative losses. 5/18/2019 Continue running in hole with the 6-5/8" pre-drilled liner on 5" HWDP singles from shed, f/ 13766' to 15885'. ( 199 its push pipe ) Fill pipe of the fly and top off every 5 Stands. Loss rate continues 1 bph TIH w/ liner on HW, 14 bbls.;RIH w/ 3 stds 5" DP to 16169', M/U std 4 and TD. Break circulation, wash down 1 bpm, 430 psi, PU single and wash to 16292' just below liner setting depth. (Verify DP count ) Set TD torque @ 10k. PU 305K, SO 120K.;Circulate and condition, stage pump slow f/ i bpm 430 psi to 1370 psi, reciprocate pipe 50' f/ 16292' to 16240' able to rotate 1-3 rpm working pipe only. CBU, FCP 5.1 bpm, 1650 psi, PU/SO 295K/125K with 9.1 mud, 51 vis @ 4% lube after BU. PJSM for displacing to brine. 9 bbl losses circulating.;Continue to reciprocate 50', rot 1- 3 rpm while working pipe , 5 bpm 1300 psi Pump 30 bbl hi vis spacer, 50 bbl SW, 30 bbl SAPP pill 1, 50 bbis SW, 30 bbl SAPP pill 2, 50 bbis SW, 30 bbl SAPP pill 3, 30 bbl hi vis spacer followed w/ 280 bbis SW.;Take all mud, SAAP trains and seawater to rock washer. Displace w 1 OH volume 9.05 brine then / 1.5 OH volumes 9.05 ppg 3% lubricated brine, w/good 9+ lubricated brine at returns, shut down pump. P/U = 305k, SIO = 125k.;Drop setting ball - 1.25" OD. Chase with 30 bbl hi-vis spacer. Pump down @ 2 BPM, 540 psi. Ball seat at 125 bbis. Set SLZXP as per baker rep. Pressure up to 2750 psi. Hold for 5 min. Slack off 50k, to 75K as per Baker Rep.;Pressure up to 3750 psi with rig pumps and line up test pump. Pressure up to 4200 psi and felt release. Bleed down, P/U & verify free.;Close annular and test LT & back side to 1680 psi for 10 min. Good. TOL = 6549.35' BOL = 16285'. Bleed down and UD top single.;P/U & break circ, displacing the IA to 9.05 ppg brine. Pump remaining 105 bb viscosified brine followed with clean 9.05 ppg brine. 499 bbis total pumped. Pump @ 5. 7 BPM as pit volumes allowed. Shut down and monitor well. - Static - Rack back 4 stands 5" Drill Pipe & Blow down TopDrive. P/U - 255k;POOH UD 5" HWDP to pipe shed f/ 15885't/ 10830'. Monitor well on Trip Tank. Even displacement until 14000' where started seeing 1.6 BPH Iosses.;Hauled 50 bbis H2O from 6 Mile lake for total = 9510 bbis Hauled 0 bbis heated H2O from G&I for total = 970 bbis Hauled 2873 bbis cutting/liquids to MPU G&I for total= 16339 bbis Mud Losses: 14 bbis daily losses, 138.5 bbis cumulative losses. 5/19/2019 POOH UD 5" HWDP to pipe shed f/ 10830'V 9746'@ the LRT. Monitor well on Trip Tank. 1.6 BPH UD HW, 11 bbls.;Ready FOSV for 3 1/2", Inspect and UD LRT, PUPS and XOs, R/U 3 1/2" handling equipment.;POOH UD 3 1/2 eue inner string f/ 9660' to 8040', wet pipe, pump dry job, continue UD tbg to 7291', Draworks making noise, shut down and WU FOSV. 2 bph loss rate TOOH.;PJSM, LOTO draworks, Investigate draworks, high drum chain lost cotter key on connecting link, damaging a section of chain, remove guards and damaged chain, clean sump, inspect sprockets, install V new section of chain. reinstall guards. test run desks, good. Monitor well, 1 bph static loss rate;Continue to UD 3 1/2" tbg to 6492', 210 its, TOOH racking 70 stds tbg in derrick for completion. 1.5 bph loss rate.;See completions report for remainder of daily activity.; Hauled 75 bbis H2O from 6 Mile lake for total = 9585 bbls Hauled 0 bbis heated H2O from G&I for total = 970 bbis Hauled 314 bbis cutting/liquids to MPU G&I for total= 16653 bbis Cumulative Mud Losses: 138.5 bbis Daily & Cumulative Brine Loses = 30.5 bbis Hilcorp Energy Company Composite Report Well Name: MP M-16 Field: Milne Point County/State: North Slope Borough, Alaska (LAT/LONG): avation (RKB): API #: 50-029-23631-00-00 Spud Date: 5/2/2019 Job Name: 1911311C MPU M-16 Completion Contractor AFE #: AFE $: A e Nt(y Late Ups Summary , 5/19/2019 POOh laying down HWDP & 3-1/2" tubing. Rack back 51 stands 3-112" tubing in Derrick. See drilling report for details.POOH racking 19 stds tbg in derrick for completion. Total 70 std racked back. Inspect and UD slick stick assy. Loss rate continue at 1.5 BPH,Drain Stack, Pull wear bushing, Dummy run 7" hanger. UD hanger and landing jt. Install wear bushing.,Make up 3-1/2" wash pipe with no-go to stand of 5" drill pipe and RIH out of Derrick. Tag up with 10k, No -Go depth of 6550.32'. P/U = 138k, S/O = 110k. 6.1 bbls actual over calculated displacement on trip in hole.,Hi-Line power went down @ 20:35, On Rig Cat power @ 20:45.,Circulate 2x bottoms up @ 600 GPM - 460 psi. Pump 30 bbls hi -vis sweep chased with 490 bbls 9.05 ppg Brine. Pumped until clean brine observed at surface. 3-10 BPM , 130-350 psi. Rotate and reciprocate string above liner top once clean brine around the back side. Total of 520 bbls pumped. No losses recorded during clean up cycle and displacement.,Monitor well, slight losses. Rack back one stand drill pipe and blow down Topdrive.,Cut and Slip 99' drilling line. Service Dwks, Roughneck & TopDrive. Losses @ 1 BPH.,Pull out of hole laying down 5" drill pipe to shed f/ 6481' U 5857'. Losses @ 1 BPH., Hauled 75 bbls H2O from 6 Mile lake for total = 9585 bbls Hauled 0 bbis heated H2O from G&I for total = 970 blots Hauled 314 bbls cutting/liquids to MPU G&I for total= 16653 bbls Cumulative Mud Losses: 138.5 bbls Dailv & Cumulative Brine Loses = 30.5 bbls 5/20/2019 Pull out of hole laying down 5" drill pipe to shed f/ 5857' t/ surface, UD stinger and nogo. Losses continue @ 1 BPH.,Clear rig Floor, pull wear bushing. R/U 7" handling equipment and power tongs, ready FOSV on XO. PJSM with Doyon casing, BOT rep and rig crew. Monitor well w/ trip tank.,P/U Baker Bullet seals tie back assembly to 16. Run 7" 26# L-80 TXP BTC -SR liner f/ 15' U 6563.33'. PIU = 147k, 8/0 = I I5k. Torque to 14750 fUlbs with Doyon casing double stack tongs. Tagged No -Go 10k (4' Low) 1 BPH loss rate.,Shut annular & Pressure test backside to 250 . Verify seals landed Good. Bleed down and open up annular. TOL= 6553.75'., UD joint #162. WU hanger and landing joint. R/U circ equipment. WU to string and land out. Close annular. Pressure up on injection line to 250. PIU on string until ports open and verify pressure dump. Good.,Line up and reverse circ 116 bbl corrosion inhibitor then chase with 76 bbl diesel. Land w/ 75k Hanger. 5 BPM - 650 psi., Bleed down to cellar and verify seals engaged. Good. Back side dead. Open annular & drain stack. RID landing joint. Change handling equipment to 5". M/U Pack off running tool on jt of 5" HWDP. RIH & set pack off. RILD. Wellhead rep verify. Test Void to 500/5000 psi, 5 min./10 min - good.,Test 7" X 9-5/8" annulus to 1100 psi for 30 charted min. Bled down 30 psi. Good. Bleed of pressure test & RID 5" equipment. SIMOPS: R/U 3.5" handling equipment.,Continue rigging up 3-1/2" completion equipment. Change out air boot on trip nipple riser.,Hauled295 bbls H2O from 6 Mile lake for total = 9880 blots Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 1020 bbls cutting/liquids to MPU G&I for total= 17673 bola Daily Brine Loses = 35 bbls Cumulative Brine Loses = 65.5 bbls of I Mud Loss s: 138.5 blols 5/21/2019 R/U to run 3.5 completion. R/U shives & tie back tugger lines. M/U Well control XO & 3.5 IF TIW.,M/U 3-1/2" pup joint w/ wireline entry guide, 25 joints of 3- 1/2" 9.3# L-80 EUE tubing, HES XN nipple easy, 1 joint 3-1/2"" tubing, HES 3-1/2"xT' retrievable packer, 1 joint of 3-1/2" tubing, HES X nipple assy and SLB sliding sleeve and gauges to 954'. Torque to 3100 (tubs with Doyon casing double stack tongs. Loss Rate @ 1/2 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/ 954' U 5650' as per tally. Torque to 3100 ft/lbs with Doyon casing double stack tongs. Install Cannon clamps at every connection.,Cannon clamp caught air slips while lowering through rotary table. Inspect TEC wire and observe damage. Decision made to splice wire. After splice, pressure test lines V 5000 psi for 10 mins each. 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/ 5650 U 6547' as per tally. Torque to 3100 ft/lbs with Doyon casing double stack tongs. Install Cannon clamps at every connection. Total 184 Cannon clamps, 4 half clamps & 2 centralizer clamps. Loss Rate — 112 BPH.,C/O elevators & PIU 5" drill pipe landing joint. M/U XO subs & Cameron 11 "0-112" tubing hanger. Perform TEC wire penetrations through hanger. Blow down Iines.,Land 3-1/2" completion on hanger. 80K PU, 68K SO, 28K on hanger. Run in lock down screws.,Drop ball (1.31") & rod. R/U circulating head, hoses & chart recorder. Pressure up to 3700 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 2675 PSI due to compression. Bleed tubing off, shear valve in GLM @ 2707'.,UD landing it. Install BPV and test U 500 psi. Start cleaning rig floor while prep to nipple down BOP stack.,Remove MPD trip nipple & kill line. Nipple down BOP stack and rack back to travelling stump.,Clean and prep hanger and TEC wire. Install dart in BPV. Terminate TEC wire through adapter flange.,Nipple up tree and test void to 500/5000 psi. Install gauge housing. Schlumberger representative tested electrical connections and operation of downhole gauges - good. Final pressure gauge readings. Intake: 1697.13 PSI, 72.21', Discharge: 1692.13 PSI, 71.88°.,Rig up and pressure test tree to 250 PSI low 15000 PSI high for 5 min. each - good tests.,Pull dart from BPV. Rig up to pump diesel freeze protect down tubing.,PJSM, Circulate diesel freeze protect down the tubing, taking returns to the cellar from IA at 2 BPM, 450 ICP.,Hauled 50 bbls H2O from 6 Mile lake for total = 9930 bbls Hauled 0 bbls heated H2O from G&I for total = 970 bbls Hauled 601 bbls cutting/liquids to MPU G&I for total= 18274 bible Daily Brine Loses = 7 bbls Cumulative Brine Loses = 72.5 bbls Total Mud Losses: 138.5 bola 5/22/2019 Finish M-16 completion. Pumped total 117 bbls diesel freeze protect. Flush pumps & rig down lines. Install gauges on Wellhead. Prep rig floor for move, blow down buildings, remove remaining brine from pits. Clean and secure well. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-16 500292363100 Sperry Drilling Definitive Survey Report 16 May, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-16 Project: Milne Point TVD Reference: MPU M-16 Actual RKB @ 59.08usft - Site: M Pt Moose Pad MD Reference: MPU M-16 Actual RKB @ 59.08usft Well: MPU M-16 North Reference: True Wellbore: MPU M-16 Survey Calculation Method: Minimum Curvature ' Design: MPU M-16 Database: NORTH US+CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor well MPU M-16 Well Position +NIS 0.00 usft Northing: 6,027,765.37 usfl . Latitude: 70' 29'12.7849 N +E/ -W 0.00 usft Easting: 533,724.10 usfl • Longitude: 149'43'27.7026 W Position Uncertainty 0.00 usft Wellhead Elevation: usfl Ground Level: 24.90 usft Wellbore MPU M-16 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1) (1) [PT) BGGM2018 3/15/2019 16.73 80.97 57,432.61136150 Design MPU M-16 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 34.18 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usfl) (usft) 0 34.18 0.00 0.00 124.99 Survey Program Date 5/16/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 228.97 6,644.72 MPU M-16 MWD+IFR2+MS+Sag (1) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis+ sa 04/25/2019 6,739.22 16,237.50 MPU M-16 MWD+IFR2+MS+Sag (2) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 05/06/2019 Survey Map Map Vertical MO Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (I (usft) (usft) (usft) (usft) (ft) (ft) (./100') (ft) Survey Tool Name 34.18 0.00 0.00 34.18 -24.90 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 UNDEFINED 228.97 1.89 236.03 228.93 169.85 -1.79 -2.66 6,027,763.56 533,721.44 0.97 -1.15 2_MWD+IFR2+MS+Sag(1) 323.13 0.50 241.29 323.07 263.99 -2.86 4.31 6,027,762.49 533,719.80 1.48 -1.89 2_MWD+IFR2+MS+Sag(1) 414.30 0.35 35.12 414.24 355.16 -2.82 4.50 6,027,762.53 533,719.61 0.91 -2.07 2_MWD+IFR2+MS+Sag(1) 507.31 1.22 133.87 507.24 448.16 -3.28 -3.62 6,027,762.08 533,720.49 1.42 -1.09 2_MWD+IFR2+MS+Sag(1) 597.08 5.61 150.72 596.83 537.75 -7.77 -0.79 6,027,757.60 533,723.35 4.96 3.81 2_MWD+IFR2+MS+Sag(1) 690.65 9.33 152.38 689.59 630.51 -18.48 4.97 6 533,729.15 3.98 M,027,746.91 14.67 2_WD+IFR2+MS+Sag(1) 783.85 12.67 153.93 781.07 721.99 -34.36 12.96 6,027,731.07 533,737.22 3.60 30.33 2_MWD+IFR2+MS+Sag(1) 879.13 15.94 156.52 873.38 814.30 -55.75 22.77 6,027,709.73 533,747.12 3.50 50.63 2_MWD+IFR2+MS+Sag(1) 975.78 19.43 155.56 965.45 906.37 -82.57 34.71 6,027,682.97 533,759.19 3.62 75.79 2_MWD+IFR2+MS+Sag(1) 1,069.96 20.89 155.28 1,053.86 994.78 -112.09 48.22 6,027,653.52 533,772.82 1.55 103.78 2_MWD+IFR2+MS+Sag(1) 1,166.62 24.23 155.90 1,143.11 1,084.03 -145.85 63.53 6,027,619.82 533,788.28 3.46 135.68 2_MWD+IFR2+MS+Sag(1) 1,261.81 28.61 156.33 1,228.37 1,169.29 -184.51 80.63 6,027,581.25 533,805.56 4.50 171.86 2 MWD+IFR2+MS+Sag(1) 57162019 5.29:25PM Page 2 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-16 Wellbore: MPU M-16 Design: MPU M-16 survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-16 MPU M-16 Actual RKB @ 59.08usft MPU M-16 Actual RKB @ 59.08usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1 (usft) (usft) (usft) (usft) (ft) (ft) (-/100•) (ft) Survey Tool Name 1,356.58 30.72 156.09 1,310.76 1,251.68 -227.36 99.53 6,027,538.49 533,824.65 2.34 211.91 2_MWD+IFR2+MS+Sag(1) 1,451.89 35.22 154.70 1,390.70 1,331.62 -274.49 121.15 6,027,491.46 533,846.48 4.79 256.65 2_MWD+IFR2+MS+Sag(1) 1,546.04 40.93 155.11 1,464.79 1,405.71 -327.05 145.75 6,027,439.02 533,871.32 6.07 306.95 2_MWD+IFR2+MS+Sag(1) 1,639.30 43.57 155.31 1,533.81 1,474.73 -383.97 172.04 6,027,382.22 533,897.86 2.83 361.13 2_MWD+IFR2+MS+Sag(1) 1,735.95 46.63 154.72 1,602.03 1,542.95 -446.02 200.96 6,027,320.31 533,927.06 3.20 420.40 2_MWD+IFR2+MS+Sag(1) 1,831.01 50.03 152.83 1,665.22 1,606.14 -509.69 232.36 6,027,256.79 533,958.75 3.87 482.63 2_MWD+IFR2+MS+Sag (1) 1,925.52 59.14 152.36 1,719.93 1,660.85 -577.99 267.79 6,027,188.66 533,994.48 9.65 550.82 2 MWD+IFR2+MS+Sag(1) 2,020.25 59.94 154.38 1,767.96 1,708.88 -650.98 304.38 6,027,115.85 534,031.40 2.02 622.66 2_MWD+IFR2+MS+Sag(1) 2,115.83 60.35 156.57 1,815.54 1,756.46 -726.39 338.78 6,027,040.60 534,066.14 2.03 694.08 2_MWD+IFR2+MS+Sag(1) 2,210.52 58.94 157.13 1,863.39 1,804.31 -801.51 370.91 6,026,965.63 534,098.60 1.57 763.48 2_MWD+IFR2+MS+Sag(1) 2,305.01 60.19 157.29 1,911.26 1,852.18 -876.62 402.47 6,026,890.67 534,130.50 1.33 832.40 2_MWD+IFR2+MS+Sag(1) 2,399.19 61.82 155.48 1,956.91 1,897.83 -952.09 435.47 6,026,815.36 534,163.84 2.41 902.72 2_MWD+IFR2+MS+Sag(1) 2,495.66 60.51 156.43 2,003.44 1,944.36 -1,029.26 469.91 6,026,738.36 534,198.62 1.61 975.18 2_MWD+IFR2+MS+Sag(1) 2,590.65 61.63 155.55 2,049.39 1,990.31 -1,105.20 503.74 6,026,662.58 534,232.79 1.43 1,046.44 2_MWD+IFR2+MS+Sag(1) 2,686.42 60.44 155.74 2,095.76 2,036.68 -1,181.53 538.29 6,026,586.41 534,267.69 1.25 1,118.52 2_MWD+IFR2+MS+Sag(1) 2,781.03 59.97 156.32 2,142.78 2,083.70 -1,256.55 571.65 6,026,511.55 534,301.38 0.73 1,188.87 2 MWD+IFR2+MS+Sag(1) 2,876.32 60.87 155.75 2,189.81 2,130.73 -1,332.28 605.31 6,026,435.98 534,335.38 1.08 1,259.87 2_MWD+IFR2+MS+Sag(1) 2,971.12 58.05 155.88 2,237.98 2,178.90 -1,406.75 638.76 6,026,361.67 534,369.17 2.98 1,329.98 2 MWD+IFR2+MS+Sag(1) 3,066.10 60.42 155.24 2,286.56 2,227.48 -1,481.04 672.53 6,026,287.54 534,403.27 2.56 1,400.25 2_MWD+IFR2+MS+Sag(1) 3,161.06 59.06 156.19 2,334.41 2,275.33 -1,555.80 706.26 6,026,212.94 534,437.34 1.67 1,470.76 2_MWD+IFR2+MS+Sag(1)M 3,255.96 60.72 155.40 2,382.02 2,322.94 -1,630.67 739.92 6,026,138.23 534,471.34 1.89 1,541.27 2_WD+IFR2+MS+Sag (1) 3,351.65 60.19 156.04 2,429.21 2,370.13 -1,706.55 774.16 6,026,062.51 534,505.91 0.80 1,612.82 2_MWD+IFR2+MS+Sag(1) 3,446.75 61.76 153.84 2,475.35 2,416.27 -1,781.87 809.38 6,025,987.37 534,541.48 2.61 1,684.87 2_MWD+IFR2+MS+Sag(1) 3,541.33 62.24 153.61 2,519.75 2,460.67 -1,856.75 846.35 6,025,912.66 534,578.78 0.55 1,758.10 2_MWD+IFR2+MS+Sag(1) 3,635.50 62.93 154.46 2,563.11 2,504.03 -1,931.91 882.95 6,025,837.68 534,615.71 1.09 1,831.18 2_MWD+IFR2+MS+Sag(1) 3,731.87 61.19 153.21 2,608.27 2,549.19 -2,008.32 920.48 6,025,761.45 534,653.59 2.14 1,905.74 2_MWD+IFR2+MS+Sag(1)M 3,827.51 59.99 152.14 2,655.23 2,596.15 -2,082.33 958.72 6,025,687.61 534,692.16 1.59 1,979.51 2_WD+IFR2+MS+Sag(1) 3,922.63 57.74 151.56 2,704.41 2,645.33 -2,154.12 997.13 6,025,616.01 534,730.88 2.42 2,052.14 2_MWD+IFR2+MS+Sag(1) 4,016.40 55.68 153.28 2,755.88 2,696.80 -2,223.58 1,033.42 6,025,546.72 534,767.49 2.68 2,121.71 2_MWD+IFR2+MS+Sag(1) 4,113.45 56.82 155.41 2,809.80 2,750.72 -2,296.31 1,068.35 6,025,474.15 534,802.74 2.17 2,192.03 2_MWD+IFR2+MS+Sag(1)M 4,208.83 58.04 157.10 2,861.15 2,802.07 -2,369.89 1,100.70 6,025,400.73 534,835.43 1.97 2,260.73 2_WD+IFR2+MS+Sag(1) 4,303.65 58.12 157.26 2,911.28 2,852.20 -2,444.07 1,131.92 6,025,326.70 534,866.98 0.17 2,328.84 2_MWD+IFR2+MS+Sag(1) 4,398.67 59.85 156.83 2,960.24 2,901.16 -2,519.05 1,163.68 6,025,251.87 534,899.07 1.86 2,397.86 2_MWD+IFR2+MS+Sag(1) 4,493.53 59.50 157.74 3,008.14 2,949.06 -2,594.58 1,195.30 6,025,176.49 534,931.03 0.91 2,467.07 2_MWD+IFR2+MS+Sag(1) 4,587.61 62.27 155.80 3,053.91 2,994.83 -2,670.09 1,227.73 6,025,101.14 534,963.80 3.45 2,536.94 2 MWD+IFR2+MS+Sag(1) 4,684.46 61.63 155.82 3,099.46 3,040.38 -2,748.06 1,262.75 6,025,023.34 534,999.18 0.66 2,610.34 2_MWD+IFR2+MS+Sag(1) 4,779.64 61.18 154.76 3,145.01 3,085.93 -2,823.98 1,297.69 6,024,947.59 535,034.45 1.09 2,682.49 2_MWD+IFR2+MS+Sag(1) 4,874.40 61.46 154.43 3,190.49 3,131.41 -2,899.07 1,333.35 6,024,872.66 535,070.45 0.43 2,754.77 2_MWD+IFR2+MS+Sag(1)M 4,969.60 61.05 154.85 3,236.27 3,177.19 -2,974.49 1,369.10 6,024,797.41 535,106.54 0.58 2,827.31 2_WD+IFR2+MS+Sag(1) 5,063.60 60.25 154.01 3,282.34 3,223.26 -3,048.40 1,404.46 6,024,723.67 535,142.23 1.15 2,898.67 2_MWD+IFR2+MS+Sag(1) 5/162019 5:29:25PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-16 MPU M-16 MPU M-16 Local Co-ordinate Reference: Well MPU M-16 TVD Reference: MPU M-16 Actual RKB @ 59.08usft MD Reference: MPU M-16 Actual RKB @ 59.08usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (') (1) (usft) (usft) (usft) (usft) (ft) (ft) (.1100') (ft) Survey Tool Name 5,160.04 58.41 153.74 3,331.54 3,272.46 -3,122.88 1,440.98 6,024,649.37 535,179.09 1.92 2,971.29 2_MWD+IFR2+MS+Sa9(1) 5,255.45 58.86 155.56 3,381.20 3,322.12 -3,196.50 1,475.86 6,024,575.91 535,214.29 1.70 3,042.08 2_MWD+IFR2+MS+Sag(1) 5,351.14 58.28 156.15 3,431.10 3,372.02 -3,271.00 1,509.26 6,024,501.57 535,248.03 0.80 3,112.17 2_MWD+IFR2+MS+Sag(1) 5,445.97 59.13 156.96 3,480.36 3,421.28 -3,345.34 1,541.50 6,024,427.38 535,280.60 1.16 3,181.21 2_MWD+IFR2+MS+Sag(1) 5,540.83 60.71 155.36 3,527.90 3,468.82 -3,420.41 1,574.68 6,024,352.47 535,314.12 2.21 3,251.44 2_MWD+IFR2+MS+Sag(1) 5,636.35 63.78 151.81 3,572.39 3,513.31 -3,496.08 1,612.30 6,024,276.98 535,352.08 4.60 3,325.65 2_MWD+IFR2+MS+Sag(1) 5,731.66 67.22 148.05 3,611.92 3,552.84 -3,571.08 1,655.78 6,024,202.18 535,395.89 5.09 3,404.28 2_MWD+IFR2+MS+Sag(1) 5,825.31 70.35 143.55 3,645.82 3,586.74 -3,643.24 1,704.86 6,024,130.26 535,445.29 5.59 3,485.86 2_MWD+IFR2+MS+Sag(1) 5,921.31 71.83 139.81 3,676.94 3,617.86 -3,714.46 1,761.17 6,024,059.30 535,501.92 3.99 3,572.84 2_MWD+IFR2+MS+Sag(1) 6,015.51 73.80 136.05 3,704.78 3,645.70 -3,781.24 1,821.46 6,023,992.80 535,562.51 4.35 3,660.53 2_MWD+IFR2+MS+Sag(1) 6,111.25 76.29 131.02 3,729.50 3,670.42 -3,844.91 1,888.50 6,023,929.44 535,629.83 5.70 3,751.96 2_MWD+IFR2+MS+Sag(1) 6,206.86 78.37 126.43 3,750.48 3,691.40 -3,903.23 1,961.26 6,023,871.46 535,702.85 5.16 3,845.01 2_MWD+IFR2+MS+Sag(1) 6,301.61 78.69 125.05 3,769.32 3,710.24 -3,957.47 2,036.63 6,023,817.57 535,778.45 1.47 3,937.86 2_MWD+IFR2+MS+Sag(1) 6,396.17 84.32 126.71 3,783.29 3,724.21 1,012.27 2,112.37 6,023,763.12 535,854.43 6.20 4,031.33 2_MWD+IFR2+MS+Sag(1) 6,490.60 84.65 125.59 3,792.36 3,733.28 1,067.71 2,188.26 6,023,708.02 535,930.57 1.23 4,125.30 2_MWD+IFR2+MS+Sag(1) 6,588.11 83.13 125.93 3,802.74 3,743.66 1,124.37 2,266.94 6,023,651.73 536,009.49 1.60 4,222.25 2_MWD+IFR2+MS+Sag(1) 6,644.72 84.31 126.57 3,808.93 3,749.85 1,157.64 2,312.32 6,023,618.67 536,055.02 2.37 4,278.50 2_MWD+IFR2+MS+Sag(1) 6,739.22 87.05 125.07 3,816.05 3,756.97 1,212.78 2,388.72 6,023,563.88 536,131.66 3.30 4,372.71 2_MWD+IFR2+MS+Sag(2) 6,770.87 88.53 125.17 3,817.27 3,758.19 -4,230.98 2,414.59 6,023,545.80 536,157.61 4.69 4,404.34 2_MWD+IFR2+MS+Sag(2) 6,865.86 88.96 124.36 3,819.35 3,760.27 1,285.13 2,492.60 6,023,492.01 536,235.86 0.97 4,499.30 2_MWD+IFR2+MS+Sag(2) 6,960.26 89.70 123.63 3,820.46 3,761.38 1,337.90 2,570.86 6,023,439.60 536,314.35 1.10 4,593.68 2_MWD+IFR2+MS+Sag(2) 7,055.19 90.69 123.32 3,820.13 3,761.05 1,390.26 2,650.04 6,023,387.60 536,393.76 1.09 4,688.58 2_MWD+IFR2+MS+Sag(2) 7,149.46 90.32 123.03 3,819.30 3,760.22 1,441.84 2,728.94 6,023,336.38 536,472.88 0.50 4,782.79 2_MWD+IFR2+MS+Sag(2) 7,245.96 87.91 122.64 3,820.79 3,761.71 1,494.16 2,810.01 6,023,284.44 536,554.18 2.53 4,879.21 2_MWD+IFR2+MS+Sag(2) 7,341.44 87.98 122.39 3,824.22 3,765.14 1,545.45 2,890.47 6,023,233.52 536,634.87 0.27 4,974.54 2_MWD+IFR2+MS+Sag(2)M 7,435.53 89.02 124.13 3,826.68 3,767.60 1,597.03 2,969.12 6,023,182.30 536,713.74 2.15 5,068.55 2_WD+IFR2+MS+Sag (2) 7,532.27 89.70 126.28 3,827.76 3,768.68 1,652.80 3,048.15 6,023,126.90 536,793.02 2.33 5,165.27 2_MWD+IFR2+MS+Sag(2) 7,627.40 87.66 126.31 3,829.95 3,770.87 1,709.09 3,124.80 6,023,070.96 536,869.91 2.14 5,260.35 2_MWD+IFR2+MS+Sag (2) 7,722.90 86.49 126.04 3,834.82 3,775.74 1,765.38 3,201.79 6,023,015.02 536,947.15 1.26 5,355.70 2_MWD+IFR2+MS+Sag(2) 7,818.85 87.29 126.25 3,840.03 3,780.95 1,821.89 3,279.16 6,022,958.87 537,024.76 0.86 5,451.49 2_MWD+IFR2+MS+Sag(2) 7,914.19 87.48 125.30 3,844.38 3,785.30 1,877.57 3,356.43 6,022,903.55 537,102.28 1.02 5,546.72 2_MWD+IFR2+MS+Sag (2) 8,009.74 89.40 126.29 3,846.98 3,787.90 1,933.43 3,433.89 6,022,848.04 537,179.99 2.26 5,642.22 2_MWD+IFR2+MS+Sag(2) 8,105.24 90.14 126.56 3,847.36 3,788.28 1,990.14 3,510.74 6,022,791.69 537,257.08 0.82 5,737.69 2_MWD+IFR2+MS+Sag(2) 8,200.83 88.96 125.46 3,848.12 3,789.04 -5,046.33 3,588.05 6,022,735.85 537,334.64 1.69 5,833.26 2 MWD+IFR2+MS+Sag(2) 8,296.04 89.33 125.37 3,849.54 3,790.46 -5,101.50 3,665.64 6,022,681.04 537,412.47 0.40 5,928.45 2_MWD+IFR2+MS+8ag(2) 8,393.24 90.01 123.95 3,850.10 3,791.02 -5,156.78 3,745.59 6,022,626.14 537,492.66 1.62 6,025.65 2_MWD+IFR2+MS+Sag(2) 8,486.30 89.76 123.82 3,850.28 3,791.20 -5,208.66 3,822.84 6,022,574.61 537,570.14 0.30 6,118.69 2_MWD+IFR2+MS+Sag(2) 8,581.53 89.14 124.02 3,851.20 3,792.12 -5,261.80 3,901.86 6,022,521.84 537,649.39 0.68 6,213.90 2_MWD+IFR2+MS+Sag(2) 8,677.36 90.32 124.53 3,851.65 3,792.57 -5,315.77 3,981.05 6,022,468.23 537,728.82 1.34 6,309.72 2_MWD+IFR2+MS+Sag(2) 8,772.35 89.39 124.28 3,851.89 3,792.81 -5,369.44 4,059.42 6,022,414.92 537,807.42 1.01 6,404.70 2 MWD+IFR2+MS+Sag(2) Y162019 5:29:25PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-16 Project: Milne Point TVD Reference: MPU M-16 Actual RKB @ 59.08usft Site: M Pt Moose Pad MD Reference: MPU M-16 Actual RKB @ 59.08usft Well: MPU M-16 North Reference: True Wellbore: MPU M-16 Survey Calculation Method: Minimum Curvature Design: MPU M-16 Database: NORTH US+CANADA Survey - Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,867.38 89.52 123.72 3,852.79 3,793.71 -5,422.58 4,138.20 6,022,362.15 537,886.43 0.60 6,499.71 2_MWD+IFR2+MS+Sag (2) 8,962.30 89.08 123.61 3,853.95 3,794.87 -5,475.19 4,217.19 6,022,309.90 537,965.66 0.48 6,594.60 2_MWD+IFR2+MS+Sag(2) 9,057.26 89.21 123.49 3,855.37 3,796.29 -5,527.66 4,296.32 6,022,257.79 538,045.02 0.19 6,689.52 2_MWD+IFR2+MS+Sag (2)M 9,152.46 88.65 123.39 3,857.15 3,798.07 -5,580.12 4,375.75 6,022,205.70 538,124.68 0.60 6,784.67 2_WD+IFR2+MS+Sag(2) 9,247.50 90.44 124.65 3,857.90 3,798.82 -5,633.28 4,454.52 6,022,152.90 538,203.67 2.30 6,879.69 2_MWD+IFR2+MS+Sag(2) 9,343.12 91.55 125.81 3,856.24 3,797.16 -5,688.43 4,532.61 6,022,098.11 538,282.01 1.68 6,975.29 2_MWD+IFR2+MS+Sag (2) 9,439.89 93.41 127.01 3,852.05 3,792.97 -5,745.81 4,610.41 6,022,041.09 538,360.06 2.29 7,071.93 2_MWD+IFR2+MS+Sag(2) 9,533.80 92.98 126.29 3,846.82 3,787.74 -5,801.78 4,685.64 6,021,985.46 538,435.53 0.89 7,165.66 2_MWD+IFR2+MS+Sag(2) 9,628.90 91.67 126.19 3,842.96 3,783.88 -5,857.96 4,762.28 6,021,929.64 538,512.42 1.38 7,260.65 2_MWD+IFR2+MS+Sag (2) 9,723.85 90.62 126.21 3,841.07 3,781.99 -5,914.02 4,838.88 6,021,873.93 538,589.27 1.11 7,355.56 2_MWD+IFR2+MS+Sag (2) 9,819.87 89.89 126.70 3,840.64 3,781.56 -5,971.08 4,916.11 6,021,817.24 538,666.75 0.92 7,451.55 2_MWD+IFR2+MS+Sag(2) 9,915.13 90.07 124.77 3,840.67 3,781.59 -6,026.71 4,993.43 6,021,761.96 538,744.31 2.03 7,546.80 2_MWD+IFR2+MS+Sag(2) 10,010.45 89.88 125.47 3,840.71 3,781.63 -6,081.54 5,071.40 6,021,707.48 538,822.52 0.76 7,642.11 2_MWD+IFR2+MS+Sag(2) 10,105.39 89.95 127.85 3,840.85 3,781.77 -6,138.23 5,147.55 6,021,651.15 538,898.92 2.51 7,737.01 2_MWD+IFR2+MS+Sag(2) 10,200.60 90.32 128.73 3,840.63 3,781.55 -6,197.22 5,222.28 6,021,592.50 538,973.91 1.00 7,832.06 2_MWD+IFR2+MS+Sag(2) 10,295.86 90.51 127.82 3,839.94 3,780.86 -6,256.23 5,297.06 6,021,533.84 539,048.95 0.98 7,927.16 2 MWD+IFR2+MS+Sag (2) 10,391.05 90.26 126.53 3,839.30 3,780.22 -6,313.74 5,372.90 6,021,476.68 539,125.05 1.38 8,022.27 2_MWD+IFR2+MS+Sag(2) 10,486.06 90.01 125.40 3,839.08 3,780.00 £,369.54 5,449.80 6,021,421.23 539,202.19 1.22 8,117.27 2_MWD+IFR2+MS+Sag(2) 10,581.26 89.76 124.92 3,839.27 3,780.19 -6,424.36 5,527.63 6,021,366.77 539,280.26 0.57 8,212.47 2_MWD+IFR2+MS+Sag (2) 10,676.71 . 89.88 123.32 3,839.57 3,780.49 -6,477.90 5,606.65 6,021,313.60 539,359.51 1.68 8,307.90 2_MWD+IFR2+MS+Sag (2) 10,772.11 89.64 121.00 3,839.97 3,780.89 -6,528.68 5,687.40 6,021,263.19 539,440.49 2.44 8,403.18 2_MWD+IFR2+MS+Sag(2) 10,866.97 89.46 119.34 3,840.71 3,781.63 -6,576.35 5,769.41 6,021,215.90 539,522.70 1.76 8,497.70 2_MWD+IFR2+MS+Sag (2) 10,961.37 87.29 120.13 3,843.39 3,784.31 -6,623.15 5,851.34 6,021,169.48 539,604.83 2.45 8,591.66 2_MWD+IFR2+MS+Sag(2) 11,056.10 87.48 120.45 3,847.71 3,788.63 -6,670.88 5,933.05 6,021,122.12 539,686.75 0.39 8,685.97 2_MWD+IFR2+MS+Sag(2) 11,151.24 87.42 123.25 3,851.94 3,792.86 -6,721.03 6,013.78 6,021,072.34 539,767.70 2.94 8,780.86 2_MWD+IFR2+MS+Sag(2) 11,243.89 87.42 125.51 3,856.11 3,797.03 -6,773.29 6,090.16 6,021,020.43 539,844.31 2.44 8,873.41 2_MWD+IFR2+MS+Sag(2) 11,340.64 87.97 126.69 3,860.01 3,800.93 -6,830.24 6,168.27 6,020,963.84 539,922.67 1.34 8,970.06 2_MWD+IFR2+MS+Sag(2) 11,435.88 89.15 126.15 3,862.40 3,803.32 -6,886.77 6,244.88 6,020,907.67 539,999.53 1.36 9,065.24 2_MWD+IFR2+MS+Sag (2) 11,531.08 88.83 125.32 3,864.08 3,805.00 -6,942.36 6,322.15 6,020,852.43 540,077.03 0.93 9,160.41 2_MWD+IFR2+MS+Sag(2) 11,625.81 89.39 125.21 3,865.55 3,806.47 -6,997.05 6,399.48 6,020,798.10 540,154.61 0.60 9,255.13 2_MWD+IFR2+MS+Sag(2) 11,720.51 89.82 125.75 3,866.20 3,807.12 -7,052.01 6,476.60 6,020,743.49 540,231.97 0.73 9,349.82 2_MWD+IFR2+MS+Sag(2) 11,815.90 89.76 126.22 3,866.55 3,807.47 -7,108.06 6,553.78 6,020,687.80 540,309.40 0.50 9,445.20 2_MWD+IFR2+MS+Sag(2) 11,910.55 89.52 126.38 3,867.15 3,808.07 -7,164.09 6,630.06 6,020,632.12 540,385.92 0.30 9,539.82 2 MWD+IFR2+MS+Sag(2) 12,005.61 89.02 125.76 3,868.36 3,809.28 -7,220.06 6,706.89 6,020,576.51 540,463.00 0.84 9,634.86 2_MWD+IFR2+MS+Sag(2) 12,101.26 89.15 124.72 3,869.88 3,810.80 -7,275.24 6,785.00 6,020,521.69 540,541.35 1.10 9,730.49 2_MWD+iFR2+MS+Sag(2) 12,196.42 87.85 124.13 3,872.38 3,813.30 -7,329.02 6,863.47 6,020,468.27 540,620.05 1.50 9,825.61 2_MWD+IFR2+MS+Sag(2) 12,291.40 87.79 123.87 3,875.99 3,816.91 -7,382.09 6,942.15 6,020,415.56 540,698.97 0.28 9,920.51 2_MWD+IFR2+MS+Sag(2) 12,386.26 89.52 124.88 3,878.22 3,819.14 -7,435.63 7,020.42 6,020,362.38 540,777.47 2.11 10,015.33 2_MWD+IFR2+MS+Sag(2) 12,481.42 92.67 127.44 3,876.40 3,817.32 -7,491.76 7,097.22 6,020,306.61 540,854.52 4.27 10,110.44 2_MWD+IFR2+MS+Sag(2) 12,576.38 91.06 127.15 3,873.31 3,814.23 -7,549.26 7,172.72 6,020,249.45 540,930.27 1.72 10,205.27 2_MWD+IFR2+MS+Sag(2) 5(1672019 5.29:25PM Page 5 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-16 Wellbore: MPU M-16 Design: MPU M-16 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-16 MPU M-16 Actual RKB @ 59.08usft MPU M-16 Actual RKB @ 59.08usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EbW Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/1001) (ft) Survey Tool Name 12,671.28 89.58 124.52 3,872.78 3,813.70 -7,604.81 7,249.65 6,020,194.26 541,007.44 3.18 10,300.14 2_MWD+IFR2+MS+Sag(2) 12,766.54 89.02 122.90 3,873.94 3,814.86 -7,657.68 7,328.88 6,020,141.76 541,086.90 1.80 10,395.37 2_MWD+IFR2+MS+Sag(2) 12,862.38 87.30 121.44 3,877.02 3,817.94 -7,708.68 7,409.96 6,020,091.13 541,168.20 2.35 10,491.04 2_MWD+IFR2+MS+Sag(2) 12,956.85 86.12 121.20 3,882.44 3,823.36 -7,757.70 7,490.53 6,020,042.48 541,248.99 1.27 10,585.16 2 MWD+IFR2+MS+Sag(2) 13,052.11 87.17 124.53 3,888.02 3,828.94 -7,809.30 7,570.39 6,019,991.25 541,329.08 3.66 10,680.17 2_MWD+IFR2+MS+Sag(2) 13,147.63 87.54 131.73 3,892.43 3,833.35 -7,868.18 7,645.40 6,019,932.72 541,404.34 7.54 10,775.39 2_MWD+IFR2+MS+Sag(2) 13,243.06 86.62 129.95 3,897.29 3,838.21 -7,930.50 7,717.50 6,019,870.73 541,476.71 2.10 10,870,19 2_MWD+IFR2+MS+Sag (2) 13,337.80 89.40 128.23 3,900.58 3,841.50 -7,990.19 7,790.98 6,019,811.37 541,550.46 3.45 10,964.62 2_MWD+IFR2+MS+Sag (2) 13,433.20 92.61 127.49 3,898.91 3,839.83 -8,048.72 7,866.27 6,019,753.19 541,626.01 3.45 11,059.87 2 MWD+IFR2+MS+Sag (2) 13,528.70 94.78 125.43 3,892.75 3,833.67 -8,105.35 7,942.91 6,019,696.91 541,702.90 3.13 11,155.13 2_MWD+IFR2+MS+Sag(2) 13,624.21 95.33 122.68 3,884.34 3,825.26 -8,158.63 8,021.73 6,019,644.00 541,781.94 2.93 11,250.25 2_MWD+IFR2+MS+Sag (2) 13,718.62 92.98 122.01 3,877.50 3,818.42 -8,209.00 8,101.27 6,019,594.00 541,861.71 2.59 11,344.30 2_MWD+IFR2+MS+Sag (2) 13,814.42 89.95 121.34 3,875A5 3,815.97 -8,259.28 8,182.77 6,019,544.09 541,943.42 3.24 11,439.90 2 MWD+IFR2+MS+Sag (2) 13,909.92 87.85 120.78 3,876.88 3,817.80 -8,308.54 8,264.55 6,019,495.21 542,025.43 2.28 11,535.15 2_MWD+IFR2+MS+Sag (2) 14,003.49 86.12 122.88 3,881.80 3,822.72 -8,357.82 8,343.94 6,019,446.30 542,105.02 2.91 11,628.44 2_MWD+IFR2+MS+Sag (2)M 14,100.14 86.92 125.17 3,887.67 3,828.59 -8,411.79 8,423.88 6,019,392.69 542,185.21 2.51 11,724.89 2_WD+IFR2+MS+Sag(2) 14,195.03 88.03 127.05 3,891.85 3,832.77 -8,467.66 8,500.47 6,019,337.18 542,262.03 2.30 11,819.66 2_MWD+IFR2+MS+Sag(2) 14,290.02 87.36 126.59 3,895.67 3,836.59 -8,524.54 8,576.44 6,019,280.65 542,338.26 0.86 11,914.53 2_MWD+IFR2+MS+Sag(2) 14,385.27 88.66 124.67 3,898.98 3,839.90 -8,579.99 8,653.81 6,019,225.55 542,415.87 2.43 12,009.71 2_MWD+IFR2+MS+Sag(2) 14,480.33 88.41 123.81 3,901.41 3,842.33 -8,633.46 8,732.37 6,019,172.45 542,494.66 0.94 12,104.73 2 MWD+IFR2+MS+Sag(2) 14,576.28 88.90 124.24 3,903.66 3,844.58 -8,687.13 8,811.87 6,019,119.14 542,574.40 0.68 12,200.64 2_MWD+IFR2+MS+Sag(2) 14,671.16 89.46 123.59 3,905.02 3,845.94 -8,740.07 8,890.60 6,019,066.57 542,653.36 0.90 12,295.49 2_MWD+IFR2+MS+Sag(2) 14,766.42 89.46 123.59 3,905.92 3,846.84 -8,792.77 8,969.95 6,019,014.23 542,732.94 0.00 12,390.72 2_MWD+IFR2+MS+Sag (2)M 14,861.55 89.40 123.63 3,906.86 3,847.78 -8,845.42 9,049.17 6,018,961.94 542,812.39 0.08 12,485.81 2_WD+IFR2+MS+Sag (2) 14,956.20 92.18 125.62 3,905.56 3,846.48 -8,899.19 9,127.04 6,018,908.53 542,890.50 3.61 12,580.44 2_MWD+IFR2+MS+Sag (2) 15,051.42 91.92 126.55 3,902.15 3,843.07 -8,955.24 9,203.94 6,018,852.84 542,967.64 1.01 12,675.58 2_MWD+IFR2+MS+Sag(2) 15,146.37 91.74 125.98 3,899.12 3,840.04 -9,011.37 9,280.46 6,018,797.06 543,044.41 0.63 12,770.46 2_MWD+IFR2+MS+Sag(2) 15,240.74 91.43 126.24 3,896.51 3,837.43 -9,066.97 9,356.67 6,018,741.82 543,120.86 0.43 12,864.77 2_MWD+IFR2+MS+Sag (2) 15,336.25 90.56 125.98 3,894.85 3,835.77 -9,123.24 9,433.82 6,018,685.89 543,198.26 0.95 12,960.25 2_MWD+IFR2+MS+Sag(2) 15,431.74 90.51 125.98 3,893.96 3,834.88 -9,179.34 9,511.09 6,018,630.15 543,275.77 0.05 13,055.72 2_MWD+IFR2+MS+Sag(2) 15,527.67 90.01 124.06 3,893.52 3,834.44 -9,234.39 9,589.65 6,018,575.47 543,354.57 2.07 13,151.65 2_MWD+IFR2+MS+Sag(2) 15,622.58 91.12 123.20 3,892.59 3,833.51 -9,286.95 9,668.66 6,018,523.27 543,433.82 1.48 13,246.52 2_MWD+IFR2+MS+Sag(2) 15,717.45 89.89 122.58 3,891.75 3,832.67 -9,338.46 9,748.32 6,018,472.12 543,513.70 1.45 13,341.32 2_MWD+IFR2+MS+Sag (2) 15,812.76 89.15 123.26 3,892.55 3,833.47 -9,390.26 9,828.33 6,018,420.70 543,593.93 1.05 13,436.57 2_MWD+IFR2+MS+Sag (2) 15,908.04 89.39 125.80 3,893.76 3,834.68 -9,444.26 9,906.81 6,018,367.06 543,672.65 2.68 13,531.83 2_MWD+IFR2+MS+Sag (2) 16,003.20 88.90 126.42 3,895.18 3,836.10 -9,500.33 9,983.68 6,018,311.34 543,749.76 0.83 13,626.96 2_MWD+IFR2+MS+Sag (2) 16,098.36 88.41 125.76 3,897.42 3,838.34 -9,556.37 10,060.55 6,018,255.66 543,826.89 0.86 13,722.07 2_MWD+IFR2+MS+Sag (2) 16,193.43 88.72 126.82 3,899.80 3,840.72 -9,612.62 10,137.16 6,018,199.76 543,903.74 1.16 13,817.09 2_MWD+IFR2+MS+Sag(2)M 16,237.50 89.39 128.33 3,900.53 3,841.45 -9,639.49 10,172.08 6,018,173.05 543,938.78 3.75 13,861.10 2_WD+IFR2+MS+Sag(2) 16,306.00 • 89.39 128.33 3,901.25 - 3,842.17 • -9,681.97 10,225.81 6,018,130.82 543,992.70 0.00 13,929.48 PROJECTEDto TD 5/16!1019 5:29:25PM Page 6 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-16 Wellbore: MPU M-16 Design: MPU M-16 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M-16 ND Reference: MPU M-16 Actual RKB @ 59.08usft MD Reference: MPU M-16 Actual RKB @ 59.08usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Checked By: Chelsea Wright. _._ Approved By: Mitch Laird ^^— Date: 05-16-2019 51162019 5:29:25PM Page 7 COMPASS 5000.15 Build 91 Hilcorp Energy Company CASING & CEMENTING REPORT Lease 8 Well No. MP M-16 Dale Run 5 -May -19 County North Slope Borough State Alaska Supv. S. Sunderland / C. Demoski CASING RECORD sadace TO 6,698.00 Shoe Depth: 6,691.00 PBTD: No .Its Deliv red taa Nn u. P. - usg Wt. on Hook: 100,000 Type Float Collar Innovex No. Hm to Run: 16.5 Csg Wt. On Slips: 60,000 Type of Shoe: Innovex Casing Cr": Dayon Rotate Csg X Yes No Recip Csg X Yes _ No 40 Ft Min. 94 PPG Fluid Description: Spud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: CEMENTING REPORT Liner top Packer?: Yes No Floats Held X Yes No Shoe @ 6691 FC @ 61609.22 Casing (Or Liner) Detail 671 Preflush(Spacer) Setting Depths As. Component Size Wt, Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 PBTC-5 Innovex 1.60 6,691.00 6,689.40 2 Casing 95/8 40.0 L-80 PBTC-S Tenaris 78.88 6,689.40 6,610.52 1 Float Collar 103/4 50.0 75 PBTC-S Innovex 1.30 6,610.52 6,609.22 1 Casing 95/8 40.0 L-80 PBTC-S Tenaris 39.78 6,609.22 6,569.44 1 Baffle Adapter 103/4 50.0 6.3 XPBTC-5 HES 1.47 6,569.44 6,567.97 102 Casing 95/8 40.0 L-80 PBTC-5 Tenaris 4,140.31 6,567.97 2,427.66 1 Pup Joint 95/8 40.0 L-80 NPBTC-S Tenaris 14.08 2,427.66 2,413.58 1 ES Cementer 103/4 Closure OK Y XP BTC -S HES 11.90 2,413.58 2,401.68 1 Pu Joint 95/8 40.0 L-80 P8TC-5 Tenaris 13.72 2,401.68 2,387.96 57 Casing 95/8 40.0 L-80 Density (ppg) 10.7 Tenaris 2,333.61 2,387.96 54.35 1 Casing Cut Joint 95/8 40.0 L-80 KIP PBTC-S Tenaris 24.71 54.35 29.64 usg Wt. on Hook: 100,000 Type Float Collar Innovex No. Hm to Run: 16.5 Csg Wt. On Slips: 60,000 Type of Shoe: Innovex Casing Cr": Dayon Rotate Csg X Yes No Recip Csg X Yes _ No 40 Ft Min. 94 PPG Fluid Description: Spud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: CEMENTING REPORT Liner top Packer?: Yes No Floats Held X Yes No Post lob Calculations: Shoe @ 6691 FC @ 61609.22 Calculated Cam Vol @ 0% excess: Top of Liner 671 Preflush(Spacer) Calculated cement left in wellbore: 498.4 OH volume Calculated 367 OH volume actual: 467.62 Actual % Washout: Type: Clean Spacer Density (ppg) 10 Volume pumped (BBLs) 55 Lead Slurry Type: Premium G Sacks: 540 Yield: 2.36 Density (ppg) 12 Volume pumped (BBLs) 222 Mixing / Pumping Rate (bpm): 5.6 Tail Slurry W Type: Premium G Sacks: 400 Yield: 1.16 F Density (ppg) 15.8 Volume pumped (BBLs) 75 Mixing / Pumping Rate (bpm): 5 F Post Flush (Spacer) rc Type: Density (ppg) Rate (bpm): Volume: u Displacement: Type: Spud Mud Density(pW) 9.4 Rate (bpm): 6.3 Volume (actual /calclated): 497.85/497.85 FCP (psi): 720 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1200 Casing Rotated? X Yes _No Reciprocated? X Yes -No % Returns during jab 100 . Cement returns to surface? Yes X No Spacer retums? Yes X No Vol to Surf' 0 - Cement In Place At: 1330 Date: 5/6/2019 Estimated TQC: 2,401 Method Used To Detennine TOC: Cementer Stage Collar@ 2401.68 Type ESIPC Closure OK Y Preflush (Spacer) Type: Clean Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: Permafrost Sacks: 415 Yield: 4.41 Density (ppg) 10.7 Volume Pumped l BBLs) 326 Mixing/ Pumping Rate (bpm)'. 4.2 Tail Slurry Type: Premium G Sacks: 415 Yield: 1.17 n Density(ppg) 15.8 Volume pumped (BBLs) 56.2 Mixing/ Pumping Rate (bpm): 3 z Post Flush (Spacer) w Type: Density(ppg) Rale(bpm): Volume: m Displacement Type: Spud Mud Density (ppg) 94 Rate (bpm): 6 Volume (actual /calculated): 160.79/162 FCP(psi): 530 Pump used for disp: Rig Bump Plug? X Yes _No Bump press 1560 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 ' Cement returns to surface? X Yes -No Spacer returns? Ves X No Vol to Surf. 180.8 Cement In Place At: 21:45 Date: 5/6/2019 Estimated TOC' 38 Method Used To Determine TOC: Returns to surface Post lob Calculations: Calculated Cam Vol @ 0% excess: 397.78 Total Volume cmt Pumped: 671 Cml returned to surface: 180.8 Calculated cement left in wellbore: 498.4 OH volume Calculated 367 OH volume actual: 467.62 Actual % Washout: 2742 www.weliez.net Well Ez Information Management LLC ver 048181br 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 v .aogcc.olaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-16 Hilcorp Alaska, LLC Permit to Drill Number: 219-061 Surface Location: 4914' FSL, 441' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 448' FSL, 655' FEL, SEC. 19, 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. Seamount, Jr. Commissioner / DATED this Z3 day of April, 2019. STATE OF ALASKA AL .�A OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 211 AA(. 25 005 RECEIVED APR 12 2019 1a. Type of Work: 11b. Proposed Well Class: Exploratory - Gas Ll Service- WAG ❑ Service - Disp ❑ 1c. Sp/ d for: Drill 2' Lateral ElStratigraphic Test E]Development - Oil 0' Service- Winj El Single Zone ❑v • Coalb dZdrates ❑ 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-16 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 1' �L fJ TVD: 3,862' 1 Milne Point Field Schrader Bluff Oil Pool - 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4914' FSL, 441' FEL, Sec 14, T13N, R9E, UM, AK ADL025514' ADLO25515 3ET P""10 8. DNR Approval Number: 13. Approximate Spud Date: Top of Productive Horizon: 766' FSL, 1875' FWL, Sec 13, TI 3N, R9E, UM, AK LONS 16-004 5/3/2019 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 448' FSL, 655' FEL, Sec 19, T13N, R10E, UM, AK 5104 4,888'to nearest unit boundary 4b. Location of Well (Stale Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.6 ' 15. Distance to Nearest Well Open Surface: x-533724. y- 6027765 - Zane -4 • GL / BF Elevation above MSL (ft): 24.9 to Same Pool: 360' to MPU J -24A 16. Deviated wells: Kickoff depth: 460 feet ' 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 93 degrees ' Downhole: 1676 • Surface: 1295 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" 215# X-42 Weld 113' Surface Surface 113' 113' ±270 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 6,617' Surface Surface 6,617' . 3,811' Stg 1 L -1269.5 ft3 / T - 458 ft3 Stg 2 L - 1937 ft3 / T - 314 ft3 Tieback 7" 26# L-80 TXP SR 6,467' Surface Surface 6,467' 3,794' Tieback Assy. 8-1/2" 6-5/8" 20# L-80 Hyd 563 10,264' 6,467' 3,794 1 3,862' Cementless PreDrilled Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re- n rations)'As 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 F- 20. 20. Attachments: Property Plat O BOP Sketch Diverter Sketch e Drilling ProgramT. Depth Plot Seabed Report e Drillinimeg Flvuid Program B Shallow Hazard Analysis 20 AAC 25.050 requirements e 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 W hllcor .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: L1 6 Date: 1 ) Z • I 1 Commission Use Only Permit to Drill /�1�/ / `�7 API Numbed>: �� Permit Approval '/l/ %� I See cover letter for other Number. iF / 50- U�-%-Z'�'-�-C- Date: (r,/ requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other:�(! 3 ��_ ,� /— n Samples req'd: Yes ❑ NOE. Mud log req'd: Yes E] No Pf H,S measures: Yes ❑ No [✓� Directional svy req'd: Yes u No kS L h � T` -S 2— 560P Spacing exception req'd: Yes ❑ No E Inclination -only svy req'd: Yes ❑ No Post initial injection MIT req'd: Yes ❑ No❑ APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: 23 Form 10-401 Revised 512017 This permit Is valid }tl�r�,,} d e f approval per 20 AAC 25.005(8) gnachments in ou licate I V 1 IV�1� ��p�j H Hilcorp F.ncMy company 4.11.2019 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU M-16 Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Dear Commissioner, 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 16. Drilling operations are intended to commence approximately May 1st, 2019, pending rig schedule. MPU M-16 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M- 16 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.zut� TKe 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 -('j drilling program for MPU M-16, 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, r� oe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-16 Drilling Program Version l 4/11/19 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 NIU 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Pre -Drilled Liner...................................................................................32 17.0 Run 7" Tieback..............................................................................................................................37 18.0 Run Jet Pump Completion...........................................................................................................40 19.0 RDMO............................................................................................................................................40 20.0 Doyon 14 Diverter Schematic.......................................................................................................41 21.0 Doyon 14 BOP Schematic.............................................................................................................42 22.0 Wellhead Schematic......................................................................................................................43 23.0 Days Vs Depth................................................................................................................................44 24.0 Formation Tops & Information...................................................................................................45 25.0 Anticipated Drilling Hazards.......................................................................................................46 26.0 Doyon 14 Layout............................................................................................................................49 27.0 FIT Procedure................................................................................................................................50 28.0 Doyon 14 Choke Manifold Schematic..........................................................................................51 29.0 Casing Design.................................................................................................................................52 30.0 8-1/2" Hole Section MASP............................................................................................................53 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................54 32.0 Surface Plat (As Built) (NAD 27).................................................................................................55 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................56 34.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................57 n Hilcorp 1.0 Well Summary Milne Point Unit M-16 SB Producer Drilling Procedure Well MPU M-16 ' Pad Milne Point "M" Pad Planned Completion Type Jet Pump on 3-1/2" Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 16,370'•MD / 3,861' TVD PBTD, MD / TVD 16,360' MD / 3,861' TVD Surface Location Governmental 4914' FSL, 441' FEL, Sec 14, TI 3N, R9E, UM, AK Surface Location (NAD 27) X= 533,724.1, Y= 6,027,765.37 ' Top of Productive Horizon (Governmental) 766' FSL, 1875' FWL, Sec 13, TON, R9E, UM, AK TPH Location AD 27 X= 536,062 Y= 6,023,629 BHL (Governmental) 448' FSL, 655' FEL, Sec 19, TON, R10E, UM, AK BHL (NAD 27) X= 544,073.9, Y=6,018,074 AFE Number 1911311 AFE Drilling Days 23 days AFE Completion Das 5 days AFE Drilling Amount $4,841,560 AFE Completion Amount $2,048,719 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1295 psig Maximum Anticipated Pressure Downhole/Reservoir S« t r cs al 1676 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.1 ft = 58.8 ft GL Elevation above MSL: 25.1 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 H Hilcorp Eongy Compeuy 2.0 Milne Point Unit M-16 SB Producer Drilling Procedure Management of Change Information H Hilcorp Alaska, LLC Hitaotp Fnn Company Changes to Approved Permit to Drill Date: 411112019 Subject: Changes to Approved Permit to Drill for MPU M-16 File #: MPU M-16 Drilling and Completion Program Any modifications to MPU M-16 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC. Approval: Prepared: Page 3 Drilling Manager Drilling Engineer Date Date H Hilcorp Fn�ryy tbmpny 3.0 Tubular Program: Milne Point Unit M-16 SB Producer Drilling Procedure 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 n Hilcorp 5.0 Internal Reporting Requirements Milne Point Unit M-16 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 pmazzolinighilcorp.com, mm} ers(7a hilcorp, jengelghilcorp.com and cdinger(a hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mm, ers@hilcorp,com jengel@a hilcorp.com and cdinizer@bilcoip.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@bilcorp.com iengel@hilco!p.com and cdin er 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 iengel@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 kflemine@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 1 caiones@hilcoro.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdineer@hilcorp.com Page 5 n Hilcorp Eve�4 2 6.0 Planned Wellbore Schematic PROPOSED SCHEMATIC Ilil...q. 1l.nlu. LIl Org IBEIw.: -%F/GL EIe<:245 TREE & WELLHEAD m=S6XI (MLt/TD= 3)M2TM VM=16,3W (FA/TD-3.Re'lt4Di Page 6 Milne Point Unit M-16 SB Producer Drilling Procedure Milne Point Unit Well: MPU Moose Pad M-16 Last Completed: Proposed PTD: TBD Use I Camemn3its- SM Wellhead fMC1634'3Mx11"5MMDIGbDM W/11"x31/2"WETOp and Bottom VAN 3" CP W 5Wprofile-Zea 316" Nff ndn a lines OPEN HOLE / CEMENT DETAIL 42" SOS f10YaNsaq;M dump.s dot�n badlsitlei 12-1/4'W stege 1269.5 R331.]6g 456k315.8a 12-3/4"2nd ela" 193]k310.TPenn4316 k315.Ae� 6-Slr fWDnarin&1/r We Size Type Y_4/Grade/Conn Drift ID Top BAp RPF 20'7X" Cendu=r rnsuleed) 73.6/A-53/Weld NIA Surface Sao' NIA 45/3" Surface 40/L-jw 58 &6A" Surface 6,617' OAT58 T' Tieback 261L-�/w!xt 6.351" surface 6,467 0.0382 6-5/3" Llner(pr dllad) 20/L-80/)* NR1 5."C 6,467' 16,321' 0.0354 TUBING DETAIL 3.1/2" Tubing 951L-JWE-MOD 236]" I Surf 16,66/ O.COe] �@l L WELL INCLINATION DETAIL KGPM45N Mex lbk Angle=T80.plet Pump Rem Maz Ible Angle=TBD. @xN profile Max Fame Angle=. LOTubing Wil uppe on Maz Itde Angle=T5D.6i T5D MD JEWELRY DETAII JW, TOP MD Rem DIASID uppe on 1 Tu Hanger 3- WE DTopfirm 2862 2 T8D 35'61M W,r 1.5"GGLVw/BfilYde 2J16r 3 T60 3.5External Preswre Gauge Mar&ei(OiSharge Gauge! 2.613" 4 M 35 Jet pumpCarity, Renu3e circle] Pump(Annulus wLt%) 2613" 5 T D 3. Gatge Ma re W Wire Inca Gaug. 2613 6 T6Dx .5 PHLRB w& Pa 2613 ] TSD 3.5'xN Nipple, IAn ID= 27W NOGo, 2.813" Packing 6arc 2750' 6 T6D 3-5 WIEG ll"L i Ixrear Gan n 4 6,46 Asry. 6.25 OD 6. 3 ID 6,x67' em Sao(P liner Top Packerw/BD 4psrx&5/8"11351ieback5leeve) 6.2(p" 11 6,4]5 ,rNn, Ldox65B n625 L-6 M 5.924 32 65iu ne-0am uner 5524. 13 16,3fi1 4- naimxensw 14 16,366 WV Valva LTC Me (IT Hall on Se84Cioiad) - K Hilcorp E YC -Way 7.0 Drilling / Completion Summary Milne Point Unit M-16 5B Producer Drilling Procedure MPU M-16 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M-16 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" bole 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 May 1 st, 2019, pending rig schedule. Surface casing will be run to 6,617 MD / 3,810' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP 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 0 Hilcorp Milne Point Unit M-16 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-16. Ensure to provide AOGCC 24 Ins notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid, flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. Page 8 0 Hilcorp Summary of BOP Equipment & Notifications Milne Point Unit M-16 SB Producer Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" 21-1/4" 2M Diverter w/ 16' Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/4000 o Blind ram in bum 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 250/4000 • 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: iim.rel4a@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartz@alaska. ov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.eov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.i-ixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Iiispectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/Ogc/fortns/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 Milne Point Unit M-16 SB Producer Drilling Procedure R/U and Preparatory Work M-16 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. Ensure PTD and drilling program are posted in the rig office and on the rig floor. Install landing ring. Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. Level pad and ensure enough room for layout of rig footprint and RAJ. Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. i 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 (<800F). 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 Milne Point unit Ah-16 SB Producer Hilcorp Drilling Procedure F.o 10.0 N/U 21-1/4" 2M Diverter System 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/tJ 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 11 10.5 Rig & Diverter Orientation: • May change on location M-10 0 M-11 0 M-13 fr} M-12 0 M-14+ M-18 M-15 M-16 i 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-16 SB Producer Hilcorp Drilling Procedure 10.5 Rig & Diverter Orientation: • May change on location M-10 0 M-11 0 M-13 fr} M-12 0 M-14+ M-18 M-15 M-16 i 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 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-16 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# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. - Page 13 N Hilcorp Milne Point Unit M-16 SB Producer Drilling Procedure J Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD ✓ • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW 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: Page 14 • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells MW can be cut once —500' below hydrate zone ,% • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section System JzI5'ensity Dviscosity I Plastic Viscosity Yield Point API FL Milne Point unit Tem Surface 118.8-9.8_4 M-16 SB Producer 1 20-40 Hilco Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section System JzI5'ensity Dviscosity I Plastic Viscosity Yield Point API FL pH Tem Surface 118.8-9.8_4 75-175 1 20-40 25-45 1 <10 1 8.5— .5— 0.08 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-1 Gel 50 Ib 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 al dm 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 15 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring Milne Point Unit Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring M-16 SB Producer HES Baffle Adaptor Hilcorp Drilling Procedure 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. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle 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 n Hilcorp 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. / Closing Sleeve No. Shear Pins t v Opening Sleeve J C3 No. Sheaf Pins lJ ES Cementer Depth g. S79L Baffle Adapter (if used) ID Depth $r Bypass or Shut-off Baffle ID Depth Float Collar Depth e Float Shoe Depth 1I Hole TD "Reference Casing Sales Manual Section 5 Page 17 "A Overall Length B Min. ID After Drdbut O Max. Tool OD D open, Sea11D PS✓1 E Casing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug O QO OD Shut-off Plug lf�I) OD Bypass Plug (it used) 5V# �- 1 I r�� OD Milne Point Unit M-16 SB Producer Drilling Procedure Bikam ES lBunning Ord., Fill Cemerrter Shut OO plug Baffle Adapter i By-pass Aug By Pass Batik Fluat Collar Float Shoe Milne Point Unit M-16 SB Producer Hilcorp Drilling Procedure e avcw..s 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 Upon) • 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 -I1 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" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 GEOMETRY 4891 in. Threads perm: 5 Connection 00 Option REGULAR Nominal OD Ncminai ID 9.625 in. 8,835 is Pdominal Weight Alpe Thickneae da lbsn 0.395 in. Milne Point Unit B.679 jr. 38.971bs,tt Tension Efrcii Compression Eff iency E.aemal Pnessue Capacity 100.0°n 100% 3090.000 psi - mYesd Strength compression strength 916.000 x)DD0 Its 916.000 x1000 lbs M-16 SB Producer 5750.000 psi 38 Y100 ft Hilcor1 Hm®Damp r Drilling Procedure Mminum 18860 ft-ks Optimum 20960 1144. Maximum TXP® BTC OPERATION LIMIT TORQUES --1111.1110812018 Outside Diameter 9.625 in. Min. Wall ThicknessGratle 87.544 L80 low T Type f Yield Torcus Wall Thickness 0395 id Connini OD 01 REGULAR COUPLING PIPE BODY Grade L80TYPe 1' Duk API standard Body. Red 1st Band: Red 1st Rand -Brawn 2nd Band: 2rd Bard: - Snored Type Casing 3rd SamOl- 3rdSidd- 4th Sand: - GEOMETRY 4891 in. Threads perm: 5 Connection 00 Option REGULAR Nominal OD Ncminai ID 9.625 in. 8,835 is Pdominal Weight Alpe Thickneae da lbsn 0.395 in. Di Plain End bYeight B.679 jr. 38.971bs,tt OO Tdiai AN PERFORMANCE 91 Ye susing;h 916 x10005s Weddii id 5750 P. SMYS 80000 psi eo8spse 3090 Pi GEOMETRY I cemnection OD 10.625 in. CA4hi Len¢h 10-825'. Connection ID 8.823 ir. Make-up Loss 4891 in. Threads perm: 5 Connection 00 Option REGULAR PERFORMANCE Tension Efrcii Compression Eff iency E.aemal Pnessue Capacity 100.0°n 100% 3090.000 psi - mYesd Strength compression strength 916.000 x)DD0 Its 916.000 x1000 lbs Internal Pressure Capacej In tilos. Mimi Sending 5750.000 psi 38 Y100 ft MAKE-UP TORQUES Mminum 18860 ft-ks Optimum 20960 1144. Maximum 23080 Nits OPERATION LIMIT TORQUES OW-WITorque 35600 ft -6s Yield Torcus 434001 Notes This connection is full' interchangeable with: TXP® BTC - 9-625 in. - 36 f 43.5 f 47153.5158.4 Ibi [11 Internal Pressure Capacity related to structural resistance only. Intemal pressure leak resistance as per section 40.3 AFI 5C31130 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 Tenans technical sales representative. Page 19 H Hilcorp r.'w >m�> Milne Point Unit M-16 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 PIU 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(]) 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 ff Hilcorp aTZTI 13.0 Cement 9-5/8" Surface Casing C/ C7 Milne Point Unit M-16 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. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible b� -}y �assplug) — HEC rep to witness. Mix and pump cement per below calculations for the 17' sttage,—co`nhrm ctual 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 11' Stage Total Cement Volume: Page 21 Section Calculation Vol (bbl) Vol (ft3) OH x 9-5/8" ffl2-1/4" (5,617'- 2500') x .0558 bpf x 1.3 = 226.1 1269.5 Casing Total Lead 226.1 1269.5 12-1/4" OH x 9-5/8" (6,617-5,617')x.0558bpfx1.3= 72.5 407 Casing ~ 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 1 81.6 458 Page 21 N Hilcorp Milne Point Unit M-16 SB Producer Drilling Procedure Cement Slurry Design (1St Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. • 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: /at4� 6,497' x .0758 bpf = 492.47 bbls 40 bbls of weighted spacer to be leftehin tage tool, confirm spacer is compatible with cement behind stage tool c c,+f,s 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 TI System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13ga1/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: /at4� 6,497' x .0758 bpf = 492.47 bbls 40 bbls of weighted spacer to be leftehin tage tool, confirm spacer is compatible with cement behind stage tool c c,+f,s 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 Milne Point Unit M-16 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 -11 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 R HilcorpCvw Second Stage Surface Cement Job: Milne Point Unit M-16 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 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 cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cemen continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM T" System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 a 12-1/4" OH x 9-5 8" Casin (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5 8" Casin (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 .l Sb 5.4 a'7 0 Lead Slurry Tail Slurry System Permafrost L SwiftCEM T" 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 .l Sb 5.4 a'7 0 R Hilcorp E� C—pwy Milne Point Unit M-16 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated Spacer is seen at surface, then switch to tail. ori 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: --ty 2500' x.0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casinjz tally & casing and cement report to jengel@a hilcorp com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC Page 25 Milne Point Unit M-16 SB Producer Hilcor Drilling Procedure 14.0 BOP N/U and Test 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 Lk- bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. N" • 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 14.3 valve i'kk-q4 A Run 5" BOP test plug l7 + rAPD 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD • 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 FloPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 Milne Point Unit M-16 SB Producer Hilcorp Drilling Procedure 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) 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/U and test casing to 2500 psi / 30 min. Ensure to record volume /pressure (every '/< bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. �i 15.6 CBU and condition mud for FIT. i1 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 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 0 Hilcorp Milne Point Unit M-16 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 retunl permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Properties: ,u/ j Interval Density PV I YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 1 15-25 - ALAP 1 15-30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 Ib sx 6 CONQOR404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCI 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 ib sx 10 SAFE-CARB 20 (verify) 50 Ib sx 10 Soda Ash 50 Ib sx 0.5 Page 28 n Hilcorp �M 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-16 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 section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader 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, -11, -12. MPD will be utilized to monitor pressure build up on connections. -\,`� i o•2 EAr 4J • Close Approaches: I i'S 3 �� Pr1 y;� i0 lq • J-24: 15400 MD. J-24 is an abandoned SB OA well, any collision risk is minimal due to abandoned lateral. J -24A is an aRive SB NB injector. There is minimal risk with J -24A. 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. • Attemnt to lowside in a fast drilline interval where the wellbore is headed uD. Page 29 ff Hilcorp Fne� Company Milne Point Unit M-16 SB Producer Drilling Procedure Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 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 Page 31 Milne Point unit M-16 SB Producer HHCO2 �T— Drilling Procedure Page 31 H Hilcorp E,� U=Pmy 16.0 Run 6-5/8" Production Pre -Drilled Liner Milne Point Unit M-16 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. Pickup 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# Hydri1563 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 dril 563 Torque OD Minimum Optimum Maximum Yield Tor ue 6-5/8 5,900 ft -lbs 7,100 ft -lbs 10,300 ft -lbs 36,000 ft -lbs Page 32 Wedge 5630 1 ,. 11rCn.", !.. Oalsode DumNtt 8.875 n. Nin. "h11 BTS% Canne[IiM 9i5OLtiVf R£311LAR Milne Point Unit Thidcxss M-16 SB Producer sow, Hilco Drilling Procedure Wedge 5630 1 ,. 11rCn.", !.. Oalsode DumNtt 8.875 n. Nin. "h11 BTS% Canne[IiM 9i5OLtiVf R£311LAR GEOMETRY Thidcxss I.1 Grade LBO sow, RIDmvuI 00 fi.625 !f. Nominal YYefgM 2OZO N11 Typo 1 S9ur Wall Thianass 0.288 �. Cominclion qD REGULAR Hain Ebd 14p13M 1951a,4 O6Tal..a AFT gplinn Tim" tas cOWUNG %PEBL ft Bcri_Rsd 1 Daad Rud Gmdc LSD Typo 1- GAR AN Standard ts1 B �: Brown 2rd Dw d. Er , Yz d 81."M 499 a tCfl ibt 3fdoma! saw Ki 2M E... Brown tads fl fl,: L1a+imum TYpa Caaing Id Dsld. • 3rd Be' die a3rd. PIPE BODY DATA. 'min TprsNC GRr in 3]4 Canne[IiM 9i5OLtiVf R£311LAR GEOMETRY RIDmvuI 00 fi.625 !f. Nominal YYefgM 2OZO N11 Gin S9ur Nominaln 6.049+, W0 TNAk,.p 8.288'., Hain Ebd 14p13M 1951a,4 O6Tal..a AFT apsmum Tim" tas 34aAmlm 1000A,mc ft 0W.1M Tmryu PERFORMANCE Y.11 Tnr;nc 360401a.ms BUCK -ON-- Er , Yz d 81."M 499 a tCfl ibt 3fdoma! saw Ki Sh s Ha26 pa C W'. 3 $T0 CONPAECTIF 1N DATA GEOMETRY_ fannonvsr�00 T.390;n wuRIFN 14Ram 42i.n LEEnccliW lO 9.940.r -- &9a1cuC L. 'min TprsNC GRr in 3]4 Canne[IiM 9i5OLtiVf R£311LAR PERFORMANCE Tersmn Ertl#ncY CamFrzszix9 Eft ktny EnlLLrnal Peos:vre Gpa:Yr 947% 100.6 3470.08E p> 3dnl YAd 61n'vfry C.uple�Taco Load 434263 M1 Ips Ips 310400 bs isnmv Prtssum CERary &tar. Al�apk E"n; SaS0409 AL SY371C11 MAKE-UP TORQUES uaimum SM 2, fns apsmum Tim" tas 34aAmlm 1000A,mc OPERATION LIMIT TORQUES 0W.1M Tmryu Sia "Abs Y.11 Tnr;nc 360401a.ms BUCK -ON-- —� MMmum tads fl fl,: L1a+imum 1130ott-M Notes This connection is fully interchengeabde with: Wedge 563.& - 6.625 in. - 24120132 Ibsr t Connections oath Dapeles.sO Technology are fugy compatible with the same connection in its Standard version Page 33 .J H Hilcorp Milne Point Unit M-16 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 ft/min — this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 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 34 n Hilcorp F «.comvmy Milne Point Unit M-16 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 KCI NaQ. , 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 35 H ilcorp Milne Point Unit M-16 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 36 17.0 Run 7" Tieback Milne Point Unit M-16 SB Producer Drilling Procedure 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 37 TXP® BTC Unimum 13280H4bs Opbman 14750 ft -lbs kAsirmrrn r Milne Point Unit OPERATION LJMri TORQUES M-16 SB Producer Hileo Drilling Procedure TXP® BTC Unimum 13280H4bs Opbman 14750 ft -lbs kAsirmrrn r 16230 k4be OPERATION LJMri TORQUES 12106!2018 Outside Diameter 7,000 in. Min. Wall 87.5% ..... Cannecean OO 7.6_..._..... 56 m Thickness 10.200 in {') Grade LBO Iowa Make -up Lass 4.570 in Threads per rn 5 Type 1 REGULAR PERFORMANCE Wall Thickness 0.362 in. Connection OD REGULAR Torsion Efr.iety 100.0% JniM Yield strength 806-00000,00 Option 7240AW psi COUPLING PIPE BODY Its Comaression €ficiency Body: Red 1st Bard: Red 604.004xlX0 Grade LBO Type 9 Drift API standard Fst Band: Brown 2nd Band,. 2nd Band. - Brawn Type Casing 3rd Band 3rd Band: - 4th Band: - VICE ECSCI., DAJl ,. I GEOMETRY Namnal OD 7.000 in. Nowal Wrmitt 26 Ibs,1t Qift 6.151 n. Normal 6176th. Wall TtvGnses 0.362 in. Pim Esd M4ghl 2569 "IF. OD Tolerance AN PERFORMANCE Body YwId strength 604 x10001bs IntemVYleld 7240psi s66Ys 80000 psi Collapse 5410 psi CONNECTION DATA Unimum 13280H4bs Opbman 14750 ft -lbs kAsirmrrn r 16230 k4be OPERATION LJMri TORQUES J GEOMETRY -^ ..... Cannecean OO 7.6_..._..... 56 m Coupling Lmmh 10.200 in Ccnneceon ID 6.264 m - Make -up Lass 4.570 in Threads per rn 5 Connector OD option REGULAR PERFORMANCE .^A---�--.- Torsion Efr.iety 100.0% JniM Yield strength 806-00000,00 imaccal Pres-sma Capacity 111 7240AW psi Its Comaression €ficiency 100 % Compression strength 604.004xlX0 Ms.. AlcwaMe Bending 52';100 ft Ibs External Pressure iapwity 5410.000 psi MAKE-UP TORQUES �i Unimum 13280H4bs Opbman 14750 ft -lbs kAsirmrrn r 16230 k4be OPERATION LJMri TORQUES Opeabirg Imine 20001 Yield Torque 23400 ft -lbs Notes This connection is fully interchangeable with: TXR&^ BTC - 7 in. - 23129 f 32/35/38 lbs/ft 11] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 I ISO 1 D400 - 2007. Page 38 17.6 MX 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 1 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 Confirm 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. 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 39 Milne Point unit M-16 SB Producer Hilco Drilling Procedure 17.6 MX 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 1 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 Confirm 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. 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 39 18.0 Run Jet Pump Completion 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 up to 3,500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. t� ,�/ 18.11 Pressure up annulus topsi to test casing/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 NIU 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 40 Milne Point unit M-16 SB Producer HilcolTy E., Company Drilling Procedure 18.0 Run Jet Pump Completion 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 up to 3,500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. t� ,�/ 18.11 Pressure up annulus topsi to test casing/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 NIU 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 40 20.0 Doyon 14 Diverter Schematic 21 V4.Wf6wr- 21 �ur 2M— �irgiter'T' 21AW 21 Sp Wrsm 16-3A' W, 21 AW 261 DSI Page 41 Milne Point Unit M-16 SB Producer Drilling Procedure -16' F,11 Cv~g Kwfo vane � 16' rr m itr Lt. 21.0 Doyon 14 BOP Schematic Kill line-----� Page 42 2-7/8" x 5" VBR Blind Rams W AR—A.a Loe al Gate V*ve 2-7/8" x 5" VBR Milne Point unit M-16 SB Producer Hilco �� om Drilling Procedure 21.0 Doyon 14 BOP Schematic Kill line-----� Page 42 2-7/8" x 5" VBR Blind Rams W AR—A.a Loe al Gate V*ve 2-7/8" x 5" VBR H Hilcorp 22.0 Wellhead Schematic Page 43 Milne Point Unit M-16 SB Producer Drilling Procedure oum. l r..l e.=: C�urou=tir I I I Milne Point unit M-16 SB Producer HHilcorp Drilling Procedure �o > 23.0 Days Vs Depth 0 2000 4000 6000 i Y Q 6000 L N Q) 10000 5 12000 14000 16600 Page 44 MPU M-16 SB OA Producer Days vs Depth 0 5 10 15 20 25 30 Days H Hilico ..mrrpery I'v 24.0 Formation Tops & Information Milne Point Unit M-16 SB Producer Drilling Procedure MPU M-16 Formations (wp03) MD (ft) TVDss (ft) ND (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2298 -1760 1819 800.36 8.46 LA3 4735 -3052 3111 1368.84 8.46 Schrader Bluff NA 5731 -3570 3628 1596.32 8.46 Schrader Bluff OA 6575 -3751 3810 1676.4 8.46 L -Pad (,rata Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) ENERALIZED GEOLOGICAL _ _ F R A T SS GEOLOGICAL TVD FM LITH DESCRPTION COMMENTS Aa "'L NOTE: Sm indfvidlui Wall Program for ip q- Gudk specific casing design, depths, sizes. •11lW 50c weights• grades and mrvlectiona. Unc«solidned cmrt. m nrdbm tare am small Pavel �'• wire min«summa. 7,000' IF SIGNIFICANT AMOUNTS OF GRAVEL n" ARE ENCOUNTERED WHEN DRILLING THE SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE +ys0• Base permafrost EFFECTIVE HOLE CLEANING. 2,000' nbbeds of Sam. clays am dllsmms Mth Occasional Now of cml. watch p.slbla sidetracking wNle wasNnprmaming L33 8 L•t5. sa,nrr tivintok -4il*ea No hydrates encountered on L -Pad wells drilled to date. _ "anther" lm«beds of Sam. clays am alltift rs with occasional shwa of coal Traces of ppir at W 3100 n. / 3.000• nmrval al.;. 3aaonean bo saekyaaanpntaatl. 4•ec%G<@.-t Clay nMrbedebe«Aee3000and as0ufe A(-[�:a��"�a� C L 72, A 3asi- k..nm Y LIGNU:sedesofcmns.nlrl,o .wsandswhlcham NlecDl leads age of:(hem lop. bow.)...... a fimaam, dllyehale eager dse.bp.d lyd.rvmlrg alltks as Y. UGNU Wages. lost, the Lam M(logger). ti,,...d Schrader BlNt pmsiWa 1,drmsrbms umued lona b sW et,rrnr of Milm a.✓eloprrrnl. Nerenmar.als 1-Aal acrrmllllel.m am wet. •3139' wane I A9.c1 •.090 Schrader Bluff Sands: 4,000'r.Aet.p. Comimrd byomesad pve mole Sam... bove �� Schrader Bluff: Possible lost Cirtutalion r.Fl momw and am wire eccasim.f coal. zone while drillingbra strings and running 9 9 9 •an0' oaaad. Clay rich Clay dch ahie cloy St 000 n a500n wronm dSc paiNO lrydrmarpom limited casing. end deep setting surface IoM OXY) WSWr .f&M1. d. toswmmi.0,rSmdawlopm..n Lai am L -AS aro casing for Kuparuk long strings. Also, the r Kuper mats!isamar Score p° wet, .tapir. areaw Schrader Bluff sands area tenial Schrader L -pad i. aw rlry l s am wal. a differential stuck pipe interval if left un -cased Bluff C sura. o@Ig point In ansa bow. for Kuparuk long strings. Sands:Schrader I BINE O6 Sam for lm0or mach welb. Page 45 U Hilcorp E,em Campmy 25.0 Anticipated Drilling Hazards Milne Point Unit M-16 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: d 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 46 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 47 Milne Point Unit M-16 SB Producer o Hilco Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 47 H Hilcorp 8-1/2" Hole Section: Milne Point Unit M-16 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 H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure has been seen on M -Pad. Utilize MPD to mitigate any abnormal pressure seen. G-- • r Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Page 48 26.0 Dovon 14 V111L O m.arr I- M Page 49 �al N Milne Point unit M-16 SB Producer HiI,zT eo.Br comv�r Drilling Procedure 26.0 Dovon 14 V111L O m.arr I- M Page 49 �al N Milne Point unit M-16 SB Producer Hilcorp Drilling Procedure �T 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. PIU 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 50 Milne Point unit M-16 SB Producer Hilcorp Drilling Procedure Ems C27 28.0 Dovon 14 Choke Manifold Schematic Asti=�Z 3 o®®m < u u v d r' O /'� an = n M _ fi n y T N N N n rA y 0, N O p_ Z� G- IJ / T Z 'a V ''� 0 J A V V p< O H N q s W ; aN > < �aD � X� 3 v n _elm O Cl � Gln y s � o � v Y I n ` n u m V � � OW N CD O � � W r o S o� i A .p � v } H Ln (r D cn 0 0 � j w o n`. m Page 51 n Milne Point unit Calculation/Specification 1 2 3 4 M-16 SB Producer 9-518" Hilcorp X� r Drilling Procedure 29.0 Casing Design 11 Calculation & Casing Design Factors Hilcorp DATE: 4/11/2019 WELL: MPU M-16 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1295 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1295 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 52 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 6-5/8" Top (MD) 0 6,617 Top (TVD) 0 3,810 Bottom (MD) 6,617 16,370 Bottom (TVD) 3,810 3,861 Length 6,617 9,753 Weight (ppf) 40 1 20 Grade L-80 L80 Connection TXP H563 Weight w/o Bouyancy Factor (Ibs) 264,680 195,060 Tension at Top of Section (Ibs) 264,680 195,060 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.46V 2.35 Collapse Pressure at bottom (Psi) 1,882 1,907 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.64 V 1.82 MASP (psi) 1,295 1,295 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 4.44 - 4.70 Page 52 30.0 8-1/2" Hole Section MASP Ti� Maximum Anticipated Surface Pressure Calculation xit 1 8-1/2" Hole Section MPU M-16 Milne Point Unit MD TVD Planned Top: 6617 • 3810 Planned TD: 16370 3861 Anticipated Formations and Pressures: Formation TVD TVDss _ Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,810 3, 1676 Oil 846 0.440 Offset Well Mud Densities , /,;6. 4 Well MW range Top (TVD) Bottom (TVD) Date L-50 8.8 - 9.1 Surface Milne Point Unit 2015 M-16 SB Producer Hilcotp Drilling Procedure Eney CumpnY 2015 30.0 8-1/2" Hole Section MASP Ti� Maximum Anticipated Surface Pressure Calculation xit 1 8-1/2" Hole Section MPU M-16 Milne Point Unit MD TVD Planned Top: 6617 • 3810 Planned TD: 16370 3861 Anticipated Formations and Pressures: Formation TVD TVDss _ Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,810 3, 1676 Oil 846 0.440 Offset Well Mud Densities , /,;6. 4 Well MW range Top (TVD) Bottom (TVD) Date L-50 8.8 - 9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. , 3. Calculations assume full evacuation of well bore togas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,810 (ft) x 0.78(psi/ft)= 2971.8 2971(psi) - [0.1(psi/ft)*3810(ft)]= F2591 psi MASP f rorn pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 6', 3810 (ft) x 0.44(psi/ft)= 1676 psi 1676.4(psi) - 0.1(psi/ft)*3810(ft) 1295 psi � Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 53 Milne Point Unit M-16 SB Producer Hilcorp Drilling Procedure E� Compay 31.0 Spider Plot (NAD 27) (Governmental Sections) S 23 P1,10 r 0 ..._----- ADCOZS515--i 1 N I 1 ADL025519 Sea.26 Sec. 25 � KUPARUK RIVER UNIT J , _ ADL388235 Legend • MPU M-16SHL Other Surface rbkz (SNy ' •a'+ ADL x MPU M-16 TPH 011ie, BaO. Wl (BKO v c - - - 011ier WO Palls ADL355023 rdPU M-16 BHL 1:63kJ � — CoeOm IUSGS QOE and Ga:U�Daundary \� —J Pad F.o Pml ` �..�.I '..cure: I e. � , n 1 � 114 r . , •. � S:i 141 m 19 �vv SvtihL' Ir 1 Pi57f 1 r wLes Jf' L' I Hw 1 7� I � ��`♦ j A1PUM-16 1071 PH I, MILNE P;O1NT Uf(IITA�! 1 " 1 I `! 1 �. ♦,, •_ I' 11 SIA � I `{!: I 1 r Iw I w`\'UD73N010E w • t I I + I ' "" S 23 P1,10 r 0 ..._----- ADCOZS515--i 1 N I 1 ADL025519 Sea.26 Sec. 25 � KUPARUK RIVER UNIT J , _ riJ Milne Point Unit MPU M-16 Well 0 1,250 2.500 w1303 Feet Page 54 Legend • MPU M-16SHL Other Surface rbkz (SNy ' •a'+ ADL x MPU M-16 TPH 011ie, BaO. Wl (BKO v c - - - 011ier WO Palls -;- rdPU M-16 BHL 1:63kJ � — CoeOm IUSGS QOE and Ga:U�Daundary \� —J Pad F.o Pml ` �..�.I '..cure: riJ Milne Point Unit MPU M-16 Well 0 1,250 2.500 w1303 Feet Page 54 Milne Point Unit M-16 SB Producer Hilcorp Drilling Procedure En, Comryoy 32.0 Surface Plat (As Built) (NAD 27) Page 55 I{ PROJECT z -r - - - - -- 1�1 7M YP, 14 t SEG 12 I -RC. Ii A A... Y -1O L-...- ■ I W-11 m I I M-13 I 6 Y-11 R I I M^14 23 19 M-18 I E MT6 c M-75 D M-16 14CINITY MAP NM OF A I ... .pdr Ti,o1I, . BffTw I Y GRAPHIC SCALEI MOOSE PAD''•.,, 10200 9 (N iEET ) SURVEYOR'S C RTIF)CATE LEGEND: NOTES: 1 1¢REpv ftX,Irr TUT 1W AS-R'dRt uf101KiON 1. AU WA rAM P:,YIE CW6 M NS N r.. ZONE l � 'Y PEP6IETQD A!O L1YT19]! TO W.LTCE iVF.W,O N 2 mm PMTmS APE NAIW. MC STA14 011= MIO TUT TRIS A$ -RIVET RPPPE6ENTS A WRWY t EYSTNC ERIWCTOR 1 8496 01 NRXANTY. AM 1RPCAL CdtiN'1. 4 uAp[ 6Y x[ M UWM Yv 6YE4T 1 _Al P 61x4 RL &RWN9W ANO MAT ALL GYENSCNS AW OMER [F,TAll6 /Ol N YPJ YO22 AHP6AE PN 5"Yr PAN.4t 5 6.%§MYS CWPECT AS 6' MPIUARY 16, 2619. 5 "Tt IX "KI, Ip/PRARY 2% ZV(R 4 fiIF6£ m FCD 90M� RLY9-91 PU 1,• 14 LOCATED WITHIN PROTRACTED SEC. 14, T. 13 N., R. 9 E, UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETC SECTION PAD CELLAR NO. COORD N RTES COORDINATE OSITIONCOYSI POSITIONMOD) OFFSETS ELEVATION BOX EL. Y- 6.027,765.70 N- 1,168.04 70'29'12-776" 70.4868822' 4,913' FSL' 25.0' 24.T M-73 X= 533,99384 E= 1,995.03 t4943'19.766" 149,7221572' 171FEL Y- 6,027,765.67 8- 1,16802 70'29'12.780" 70.4868833' 4,91,3: 'SL 25.0' 24.7' M-14 X. 533,903.60 E- 1,904.96 149'43'22415" 149.7226931' 261FEL Y= 6.027,765.69 N= 1,16&04 70'29'12,784" 70.4888845' 4,914' FSL 25.1' 24.7' M-15 X- 533,613.87 E- 1,815.05 149'43'25.061" 149.723fi281' 351' FEL Y. 6,027,765.37 N- 1.167.73 70.29'12.785" 70.4868847' , 4,914' FSL 25.1' 24.9' M-16 X- 533,724.10 E= 1,725.26 149'43'27.703" 149.7243619' • 441' FEL Y= 6,027,889.58 N- 1,291,95 7019'14,001' 1 70.4872226' 5.037' FSL 25.0' 24.9' M-18 X- 533,043.66 E. 1,844.84 149'43'24.188` 149.7233800' 321' FEL _ Hftcorp Alaska bell Ja IB W r.xRX MPU MOOSE PAD AS -BUILT CONDUCTORS WELLS 13,14,1 5,16,16 v Pn YYYaMY m u I• " my Page 55 H Hilcox Enngy Cmnpv�r Milne Point Unit M-16 SB Producer Drilling Procedure 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD mw, ppB 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 lull Fm 1500 2000 o 2500 9074m 3500 4000 4500 Page 56 Fj l 'J r -MPU L-46 (2015) ,q -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) H Hilcorp Milne Point Unit M-16 SB Producer Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD to 5.0(10 Pipe Body Wall Thickness m 0.362 Pipe Body Grade S-135 Dr91 Pipe Length Range2 Connection GPDS50 Tod Joint CO 6.625 Tod Joint ID m 3250 Pin Tong 9 Box Tong la, 12 BO % Inspection Class Nominal Nominal Weight Designation 19.50 Drill Pipe Approximate Length 1')131-5 SntaothEdge Height w13132 Rased Tool Joint SMYS (W-1 120.000 Upset Type IEU Max Upset OD (DTE) nal 5.125 Friction Factor 11.0 1.24 Nu T. 4 eW ce m.Y hdl nvCanrq. Drill Pipe Performance DrilLRpe Length Rangel at Nominal Inansaeeibl 23.28 0.36 0.0085 0.72 r,ati ..oP�.ly r� D.Drpo ....,.D 0.0172 ,,\`�J!( rnre+i,nruur 36r1Q0 Tension only 0 560800 Drill Size ua13.125 -i-ie32.100 146T400 aaT; on nerd aar.a mils az ueewK Hole:lMl pbe azzemtb v>We: arx Best esbmmes asa avY'�YGi:e m ppe my' mu meearce, mlemai ams:e malne, a.�0 vuxr txf:ws. Connection Performance GPDS50 ( 6.625 mr OD X 3.250 kn1 ID ) 120,000 bat P9kiC0 CbY6Vp r.,u' al sea,iser Tenxlv,a WlmNM Tmmb ;ma.me� ma tnasl il.250,ODD Maximum Makeup Torque 43,100 Tensile Lawled 1,046,900 Minimum -uMakep Torque 36.100 1202500 IIC4.Thefulmum maketp kppWssLiYW pC i491bp en(11 Wisp}. Htte le mulnCe[vnnecltnepaeaOvnal lensreaMlTkf1'I.3i.1p 11LWSIsnouHM IW Tool Joint Dimensions Balanced OD 6.435 wvnum Toa d�noo fir kali 5.930 P,emMn CNss in nn„aaua Toa ton(»v 15.93 M[ CavilerWre 11n TpJoint Ton;imal Strength IRS) 71.80(1 Todol Joint Tensile Strength kMl 1250.000 Elevator Shoulder Information Elevator OD 332 Raised 6.612 kM SmoothEdge Height Nominal Tool Joint Worn to Bevel Wom to Min TJ OD for 3132 Paised OD Diameter API Premium Clam Box OD 11^ 6.812 fi.625 6.063 5.930 Elevator aci 0-11,658,000 1,4402110 1823,600 1685.600 m5.219 rrme skrmc.moxuihmamaeeumed el-.ar.earc.no.�ar ranc..amcan�l.�.: arlla.lo�:i. Assum¢d Elevator Bae Dia tiler 4a Aml eee ODeb ucmaon' wt anRuaoa atbap o-.o„o. Pipe Body Slip Crushing Capacity POO 804ConPpuration ( 5 Wr OD 0.362(-) Wan S-135) Nominal I 80%Inspection Ctass API Premium Class t�[Slip Crushing Ca c' (0.498,300 1396,5DO 396.500 IY/ one:sw ormrs au oma 1. t. s and main mm'wry tee. Dnir Assumed Sti L¢ h to 165 ralnx:aoa�>wn a.ls»nr m:seer-0na.�rmrs,.nae mdwara�.aiannr.leai.. Transverse Load Factor (KI 4.2 ^"+-stPwvwamxWnum.me nt•anoe aarxnr. mr:mmer,elm .weocWnaa.3 ay�enl Pre oomd�.annm, as miotwxrs. caem wm nx std nurrtxr tic rs aaxaw Pipe Bodv Performance Page 57 Pipe Body Configuration ( 5 m) OD 0.362 col Wall S-135) nL'a c Nmru eu,v csru 1 at 3ROW per AP. Nominal 80% Inspection Class API Premim Class Pipe Tensile Strength 1- 712,101) 560,800 560,800 Pipe Torsional Strenp 74,100 58,100 58.100 TJ/Pipe Torsional Ratio 0.97 1.24 124 80% Pipe Torsional Strength 1n.mzr 59300 46,500 46,500 Burst (m 17,105 15.638 15638 collapse 15.672 10.029 10.029 Pipe OD to 5.000 4.855 Wall Thickness nai 0.362 02911 0290 Nonvnal Pipe ID thr 4276 4276 4.276 Cross Sectional Area of Pipe body -1, 5,275 4.154 4.154 Cross Sectional Area of OD rn•zl 19.635 18.514 18.514 Cross Sectional Area of ID ,", 14.360 14.360 14.360 Section Modulus 111.3) 5.708 4.476 4.476 Potar Section Modulus ,in-, 11.415 8,953 8.953 nL'a c Nmru eu,v csru 1 at 3ROW per AP. 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 Milne Point Unit 5' XH & 4-12' IF Upset Type IEU M-16 SB Producer 19.50 lbs Hilcorp E�,w c��y 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 19.50 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 3-1116" 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' 0290' Cross Sectional Area 5275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712,000 lbs 560.800 lbs Slip Crushing / Slip Type (SDXL) 572.100 lbs 453.500 lbs 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 aaVft 1 0.726 US gallift Displacement Wl Tool Joint 0.353 US gaVft 1 0.322 US al/ft 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. 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O O O 0 0 0 0 0 0 M r O r M N O M M M (Uyysn 0051) 91daa IeoivaA anjl �_ w0 m M X O M 3 163710 16000 M 0 n 5500 0 150002:1 G � a 14500 U M a 14000 3 co a 135000 30o0 3 125002 a 12000 a U 11500 0 3 0 Q00 � 7 10500 I- N � a 100000 6 3 9500 �o 7 000 o_ � a 500 U CI 000 3 7500 CL � a 7000 m O 3 N � X a M rn a L L o M 0 0 N O N 0 0 0 Stan Dir ToMffl' :460' MD, 460'1VD -�- Stan Dir S°/100': BW'MD, 798217VD \250 End Dir : 1774.41 1577.12' TVD s, " -15 .1P Project: Milne Point TVD TVDSS MD size Name Site: M Pt Moose Pad 3810.55 3751.95 6617.24 9-5/9 95/9"x121/4^ Well: Plan: MPU M-16 3861.80 3803.20 16370.94 6-5/9 6 5/8" x 8 1/2" HALLIBURTON Sea, Drilllne Wellbore. MPU M-16 Plan: MPU M-16 wp03 WELL DETAILS: Plan: WUM-16 4.90 +N/ -S +FJ -W NonhinK FastinK latinude Iimsimdc Uhl 0.00 6027765.37 533724.10 70° 29' 12.7849 N 149° 43' 27.7026 W REFERENCE INFORMATION Co-ordinate (WE) Reference: Well Plan: MPU M-16, True Nonh Vertical (TVD) Reference: MPU M-16 Planned PIKE @ M.60us t Mannered Depth Refinance: MPU M-16 Planned RKB Ca 58 Wmit CalcWation Memed: Minimum Cuneum �D00 Stan Dir 5°/]M': 5566.68' MD, 3537.277VD -3000 -Y'Sp " - End Dir : 6317.24' MD, 3779.19' TVD Stan Dir 4°/109: 6617.24' MD. 3810.557VD 5o End Dir : 6756.79MD,3RI8.35'TVD -3750- ' StanDir3.06°/100': 7721]4'NID, 3825.87VD 9 5/8" x 12 Il4" - - - - End Dir :7903.41' MD, 3836.0l'ND p MPU M- 10 WP03 Heel tinStan Dir 3.00100': 7942.93'MD. 3840.14'TVD -4500 _ "'-End Dir :6122.]1' MD. 3850.33' TVD " z MPU M-16 WP03 CPI' D, 3DM660.8'ND j -5250 End Dir :9417.63' MD, 3859.2TND C Start Dir 3"/100': 9728.12' MD, 31 F o I - EM Dir :9823.04' MD, 3845.02' ND - -6000 MPU M -I6 wP03 CP2 , Stan Dir 3"/100': 10923.04' MD, 3854.627VD End Dir : 11041.56' MD, 3859.33' ND - - �- Stan on 3"/100': 11225.42'MD, 3872.33TVD -6750 MPU M-16 "03 CP3 - - End Dir : 11323.94' MD, 3876.76 TVD Stan Dir 3"/100' : 12523.94' MD, 3899.8 -TVD -7500 -_"_"_ End Dir : 12616.57' MD, 3999.33' TVD MPU M. WT03 CP4 Stan Du 3°/100': 1346184' MD, 3676,33TVD - ' End Dv : 13471 04' MD. 3875.56 TVD -8250 Start Dir Y/100': 15021.47M. 3886.78TVD - MPU M- 16 Wp03 CP5 End DiT : 15132.13' MD, 38847' ND Stan Dir 3"/100' : 15443.13' MD, 3869.867VD End Dir : 15520.94' MD. 3867.73' ND -9000- MPU M- 16"63 CP6I Total Depth : 16370.94'M. 3861.8' ND -� -9750 MPU M-16 Wp03 Ice let-- 'NPU M-Ifi wp03 6 5/8" x 8 1/2" 0 750 1500 i i 2250 3000 3750 4500 5250 6000 6750 7500 9250 9000 9750 10500 11250 12000 12750 13500 West( -)/East(+) (1500 usft/in) HALLIBURT01-4 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-16 Wellbore: MPU M-16 Design: MPU M-16 wp03 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-16 TVD Reference: MPU M-16 Planned RKB @ 58.60usft , MD Reference: MPU M-16 Planned RKB @ 58.60usft North Reference: True . Survey Calculation Method: Minimum Curvature - Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) • System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Plan: MPU M-16 Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore Magnetics Design Audit Notes: Version: Vertical Section: MPU M-16 Model Name BGGM2018 MPU M-16 wp03 Sample Date 3/15,/2019 6,027,877.65usft Latitude: 533,363.92usft Longitude: 13-3116" Grid Convergence: 6,027,765.37 usfl Latitude: 533,724.10 usfl Longitude: usfl Ground Level: Declination (°I 16.73 Phase: PLAN Depth From (TVD) +N1 -S (usft) (usft) 33 70 0.00 70° 29' 13.9052 N 149° 43' 38.2855 W 0.26 ° 70° 29' 12.7849 N 149° 43'27.7026 W 24.90usft Dip Angle Field Strength (°) (nT) 80.97 57,432.61136150 Tie On Depth: 33.70 +E/ -W Direction (usft) (°) 0.00 124.99 3/212019 2:00:48PM Page 2 COMPASS 5000.15 Build 91 Plan Sections Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-16 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-16 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-16 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-16 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-16 Depth Inclination Azimuth Design: MPU M-16 wp03 System +N/ -S 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) (°/100u8ft) (°/100usft) (°I100usft) (°) 33.70 0.00 0.00 33.70 -2490 0.00 0.00 0.00 0.00 0.00 0.00 460.00 0.00 0.00 460.00 401.40 0.00 0.00 0.00 0.00 0.00 0.00 800.00 10.20 160.00 798.21 739.61 -28.36 10.32 3.00 3.00 0.00 160.00 1,774.48 58.88 154.76 1,577.12 1,518.52 -516.49 231.19 5.00 5.00 -0.54 -5.97 5,566.68 58.88 154.76 3,537.27 3,478.67 -3,452.80 1,615.61 0.00 0.00 0.00 0.00 6,317.24 84.00 124.99 3,779.19 3,720.59 -3,976.25 2,074.92 5.00 3.35 -3.97 -54.15 6,617.24 84.00 124.99 3,810.55 3,751.95 -4,147.34 2,319.35 0.00 0.00 0.00 0.00 6,756.19 89.56 124.99 3,818.35 3,759.75 -4,226.87 2,432.96 4.00 4.00 0.00 0.05 7,721.74 89.56 124.99 3,825.80 3,767.20 -4,780.59 3,223.92 0.00 0.00 0.00 0.00 7,903.41 84.00 125.03 3,836.01 3,777.41 -4,884,61 3,372.42 3.06 -3.06 0.02 179.69 7,942.93 84.00 125.03 3,840.14 3,781.54 -4,907.17 3,404.61 0.00 0.00 0.00 0.00 8,122.71 89.50 124.99 3,850.33 3.791.73 -5,010.10 3,551.56 3.06 3.06 -0.02 -0.37 9,322.71 89.50 124.99 3,860.80 3,802.20 -5,698.19 4,534.63 0.00 0.00 0.00 0.00 9,417.63 92.35 125.01 3,859.27 3,800.67 -5,752.62 4,612.37 3.00 3.00 0.02 0.36 9,728.12 92.35 125.01 3,846.55 3,787.95 -5,930.60 4,866.47 0.00 0.00 0.00 0.00 9,823.04 89.50 124.99 3,845.02 3,786.42 -5,985.03 4,944.21 3.00 -3.00 -0.02 -179.64 10,923.04 89.50 124.99 3,854.62 3,796.02 -6,615.78 5,845.35 0.00 0.00 0.00 0.00 11,041.56 85.94 125.02 3,859.33 3,800.73 -6,683.71 5,942.34 3.00 -3.00 0.02 179.60 11,225.42 85.94 125.02 3,872.33 3,813.73 -6,788.93 6,092.54 0.00 0.00 0.00 0.00 11,323.94 88.90 124.99 3,876.76 3,818.16 -6,845.38 6,173.15 3.00 3.00 -0.03 -0.49 12,523.94 88.90 124.99 3,899.80 3,841.20 -7,533.38 7,156.07 0.00 0.00 0.00 0.00 12,616.57 91.68 125.00 3,899.33 3,840.73 -7,586.49 7,231.95 3.00 3.00 0.01 0.11 13,401.64 91.68 125.00 3,876.33 3,817.73 -8,036.55 7,874.80 0.00 0.00 0.00 0.00 13,424.28 91.00 124.99 3,875.80 3,81720 -8,049.53 7,893.34 3.00 -3.00 -0.02 -179.54 13,471.44 89.59 124.99 3,875.56 3,816.96 -8,076.57 7,931.97 3.00 -3.00 0.01 179.80 15,021.47 89.59 124.99 3,886.78 3,828.18 -8,965.50 9,201.73 0.00 0.00 0.00 0.00 15,024.32 89.50 124.99 3,886.80 3,828.20 -8,967.13 9,204.07 3.00 -2.99 -0.17 -176.68 15,132.13 92.73 125.01 3,884.70 3,826.10 -9,028.94 9,292.35 3.00 3.00 0.01 0.27 15,443.13 92.73 125.01 3,869.86 3,811.26 -9,207.15 9,546.80 0.00 0.00 0.00 0.00 15,520.94 90.40 124.99 3,867.73 3,809.13 -9,251.76 9,610.52 3.00 -3.00 -0.02 -179.62 16,370.94 , 90.40 124.99 3,861.80 3,803.20 -9,739.16 10,306.86 0.00 0.00 0.00 0.00 31212019 2:00:48PM Page 3 COMPASS 5000.15 Build 91 Halliburton HALLIBURT01A Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-16 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-16 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-16 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-16 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-16 Design: MPU M-16 wp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -24.90 33.70 0.00 0.00 33.70 -24.90 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 100.00 0.00 0.00 100.00 41.40 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 200.00 0.00 0.00 200.00 141.40 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 300.00 0.00 0.00 300.00 241.40 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 400.00 0.00 0.00 400.00 341.40 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 460.00 0.00 0.00 460.00 401.40 0.00 0.00 6,027,765.37 533,724.10 0.00 0.00 Start Dir 301100' : 460' MD, 460'TVD 500.00 1.20 160.00 500.00 441.40 -0.39 0.14 6,027,764.98 533,724.25 3.00 0.34 600.00 420 160.00 599.87 541.27 -4.82 1.75 6,027,760.56 533,725.88 3.00 4.20 700.00 7.20 160.00 699.37 640.77 -14.15 5.15 6,027,751.24 533,729.31 3.00 12.33 800.00 10.20 160.00 798.21 739.61 -28.36 10.32 6,027,737.06 533,734.55 3.00 24.72 Start Dir 50/100': 800' MD, 798.21'TVD 900.00 15.18 158.01 895.73 837.13 -48.84 18.26 6,027,716.62 533,742.58 5.00 42.96 1,000.00 20.17 157.00 990.98 932.38 -76.87 29.91 6,027,688.64 533,754.35 5.00 68.58 1,100.00 25.17 156.37 1,083.23 1,024.63 -112.24 45.18 6,027,653.34 533,769.78 5.00 101.38 1,200.00 30.16 155.94 1,171.77 1,113.17 -154.69 63.96 6,027,610.99 533,788.75 5.00 141.10 1,300.00 35.16 155.62 1,255.93 1,197.33 -203.88 86.10 6,027,561.90 533,811.12 5.00 187.45 1,400.00 40.16 155.37 1,335.07 1,276.47 -259.46 111.44 6,027,506.45 533,836.70 5.00 240.08 1,500.00 45.16 155.17 1,408.59 1,349.99 -320.98 139.78 6,027,445.06 533,865.32 5.00 298.58 1,600.00 50.15 155.00 1,475.93 1,417.33 -387.99 170.91 6,027,378.20 533,896.75 5.00 362.51 1,700.00 55.15 154.85 1,536.57 1,477.97 -459.97 204.59 6,027,306.38 533,930.76 5.00 431.38 1,774.48 58.88 154.76 1,577.12 1,518.52 -516.49 231.18 6,027,249.98 533,957.60 5.00 485.57 End Dir : 1774.48' MD, 1577.12' TVD 1,800.00 58.88 154.76 1,590.31 1,531.71 -536.25 240.50 6,027,230.27 533,967.01 0.00 504.54 1,900.00 58.88 154.76 1,641.99 1,583.39 -613.68 277.01 6,027,153.01 534,003.86 0.00 578.85 2,000.00 58.88 154.76 1,693.68 1,635.08 -691.11 313.52 6,027,075.76 534,040.71 0.00 653.15 2,100.00 58.88 154.76 1,745.37 1,686.77 -768.54 350.02 6,026,998.50 534,077.57 0.00 727.46 2,200.00 58.88 154.76 1,797.06 1,738.46 -845.97 386.53 6,026,921.24 534,114.42 0.00 801.77 2,300.00 58.88 154.76 1,848.75 1,790.15 -923.40 423.04 6,026,843.99 534,151.28 0.00 876.08 2,400.00 58.88 154.76 1,900.44 1,841.84 -1,000.83 459.54 6,026,766.73 534,188.13 0.00 950.39 2,500.00 56.88 154.76 1,952.13 1,893.53 -1,078.26 496.05 6,026,689.47 534,224.99 0.00 1,024.70 2,600.00 58.88 154.76 2,003.82 1,945.22 -1,155.69 532.56 6,026,612.22 534,261.84 0.00 1,099.01 2,700.00 58.88 154.76 2,055.51 1,996.91 -1,233.12 569.07 6,026,534.96 534,298.70 0.00 1,173.32 2,800.00 58.88 154.76 2,107.20 2,048.60 -1,310.55 605.57 6,026,457.70 534,335.55 0.00 1,247.63 2,900.00 58.88 154.76 2,158.89 2,100.29 -1,387.98 642.08 6,026,380.45 534,372.40 0.00 1,321.94 3,000.00 58.88 154.76 2,210.58 2,151.98 -1,465.41 678.59 6,026,303.19 534,409.26 0.00 1,396.25 3,100.00 58.88 154.76 2,262.27 2,203.67 -1,542.84 715.09 6,026,225.94 534,446.11 0.00 1,470.56 3,200.00 58.88 154.76 2,313.95 2,255.35 -1,620.27 751.60 6,026,148.68 534,482.97 0.00 1,544.87 3,300.00 58.88 154.76 2,365.64 2,307.04 -1,697.71 788.11 6,026,071.42 534,519.82 0.00 1,619.18 3,400.00 58.88 154.76 2,417.33 2,358.73 -1,775.14 824.62 6,025,994.17 534,556.68 0.00 1,693.49 3,500.00 58.88 154.76 2,469.02 2,410.42 -1,852.57 861.12 6,025,916.91 534,593.53 0.00 1,767.80 3,600.00 58.88 154.76 2,520.71 2,462.11 -1,930.00 897.63 6,025,839.65 534,630.38 0.00 1,842.11 3,700.00 58.88 154.76 2,572.40 2,513.80 -2,007.43 934.14 6,025,762.40 534,667.24 0.00 1,916.42 3,800.00 58.88 154.76 2,624.09 2,565.49 -2,084.86 970.65 6,025,685.14 534,704.09 0.00 1,990.73 3,900.00 58.88 154.76 2,675.78 2,617.18 -2,162.29 1,007.15 6,025,607.89 534,740.95 0.00 2,065.04 321/2019 2:00:48PM 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-16 Wellbore: MPU M-16 Design: MPU M-16 wp03 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-16 TVD Reference: MPU M-16 Planned RKB @ 58.60usft MD Reference: MPU M-16 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical 4,460.84 +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (°) (°) (usft) usft (usft) 4,000.00 58.88 154.76 2,727.47 2,668.87 -2,239.72 4,100.00 58.88 154.76 2,779.16 2,720.56 -2,317.15 4,200.00 58.88 154.76 2,830.85 2,772.25 -2,394.58 4,300.00 58.88 154.76 2,882.54 2,823.94 -2,472.01 4,400.00 58.88 154.76 2,934.23 2,875.63 -2,549.44 4,500.00 58.88 154.76 2,985.91 2,927.31 -2,626.87 4,600.00 58.88 154.76 3,037.60 2,979.00 -2,704.30 4,700.00 58.88 154.76 3,089.29 3,030.69 -2,781.73 4,800.00 58.88 154.76 3,140.98 3,082.38 -2,859.16 4,900.00 58.88 154.76 3,192.67 3,134.07 -2,936.59 5,000.00 58.88 154.76 3,244.36 3,185.76 -3,014.02 5,100.00 58.88 154.76 3,296.05 3,237.45 -3,091.45 5,200.00 58.88 154.76 3,347.74 3,289.14 -3,168.88 5,300.00 58.88 154.76 3,399.43 3,340.83 -3,246.31 5,400.00 58.88 154.76 3,451.12 3,392.52 -3,323.74 5,500.00 58.88 154.76 3,502.81 3,444.21 -3,401.17 5,566.68 58.88 154.76 3,537.27 3,478.67 -3,452.80 Start Dir 50/100': 5566.68' MD, 3537.27'TVD 535,580.88 5,600.00 59.86 153.20 3,554.25 3,495.65 -3,478.56 5,700.00 62.92 148.69 3,602.15 3,543.55 -3,555.24 5,800.00 66.12 144.43 3,645.18 3,586.58 -3,630.52 5,900.00 69.43 140.38 3,683.01 3,624.41 -3,703.81 6,000.00 72.83 136.50 3,715.37 3,656.77 -3,774.57 6,100.00 76.30 132.77 3,741.99 3,683.39 -3,842.25 6,200.00 79.82 129.14 3,762.69 3,704.09 -3,906.34 6,300.00 83.38 125.60 3,777.30 3,718.70 -3,966.35 6,317.24 84.00 124.99 3,779.19 3,720.59 -3,976.25 End Dir : 6317.24' MD, 3779.19' TVD 6,400.00 84.00 124.99 3,787.84 3,729.24 -4,023.45 6,500.00 84.00 124.99 3,798.30 3,739.70 -4,080.48 6,600.00 84.00 124.99 3,808.75 3,750.15 -4,137.51 6,617.24 84.00 124.99 3,810.55 3,751.95 -4,147.34 Start Dir 4°1100' : 6617.24' MD, 3810.55'TVD - 9 518" x 12 114" 6,700.00 87.31 124.99 3,816.82 3,758.22 -4,194.65 6,756.19 89.56 124.99 3,818.35 3,759.75 -4,226.86 End Dir : 6756.19' MD, 3818.35' TVD 6,800.00 89.56 124.99 3,818.69 3,760.09 -4,251.99 6,900.00 89.56 124.99 3,819.46 3,760.86 -4,309.34 7,000.00 89.56 124.99 3,820.23 3,761.63 -4,366.68 7,100.00 89.56 124.99 3,821.01 3,762,41 -4,424.03 7,200.00 89.56 124.99 3,821.78 3,763.18 -4,481.38 7,300.00 89.56 124.99 3,822.55 3,763.95 -4,538.73 7,400.00 89.56 124.99 3,823.32 3,764.72 4,596.08 7,500.00 89.56 124.99 3,824.09 3,765.49 -4,653.43 7,600.00 89.56 124.99 3,824.86 3,766.26 -4,710.77 2,468.84 Map Map 0.00 4,460.84 +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,668.87 4,660.83 1,043.66 6,025,530.63 534,777.80 0.00 2,139.35 1,080.17 6,025,453.37 534,814.66 0.00 2,213.66 1,116.67 6,025,376.12 534,851.51 0.00 2,287.97 1,153.18 6,025,298.86 534,888.36 0.00 2,362.28 1,189.69 6,025,221.60 534,925.22 0.00 2,436.59 1,226.20 6,025,144.35 534,962.07 0.00 2,510.90 1,262.70 6,025,067.09 534,998.93 0.00 2,585.21 1,299.21 6,024,989.83 535,035.78 0.00 2,659.52 1,335.72 6,024,912.58 535,072.64 0.00 2,733.83 1,372.22 6,024,835.32 535,109.49 0.00 2,808.14 1,408.73 6,024,758.07 535,146.34 0.00 2,882.45 1,445.24 6,024,680.81 535,183.20 0.00 2,956.76 1,481.75 6,024,603.55 535,220.05 0.00 3,031.07 1,518.25 6,024,526.30 535,256.91 0.00 3,105.38 1,554.76 6,024,449.04 535,293.76 0.00 3,179.69 1,591.27 6,024,371.78 535,330.62 0.00 3,253.99 1,615.61 6,024,320.27 535,355.19 0.00 3,303.54 1,628.19 6,024,294.57 535,367.89 5.00 3,328.62 1,670.85 6,024,218.09 535,410.89 5.00 3,407.54 1,720.61 6,024,143.05 535,460.99 5.00 3,491.47 1,777.09 6,024,070.02 535,517.79 5.00 3,579.78 1,839.87 6,023,999.56 535,580.88 5.00 3,671.78 1,908.45 6,023,932.19 535,649.76 5.00 3,766.78 1,982.33 6,023,868.45 535,723.92 5.00 3,864.05 2,060.93 6,023,808.80 535,802.79 5.00 3,962.86 2,074.92 6,023,798.96 535,816.82 5.00 3,980.00 2,142.35 6,023,752.07 535,884.46 0.00 4,062.30 2,223.83 6,023,695.42 535,966.18 0.00 4,161.76 2,305.30 6,023,638.77 536,047.91 0.00 4,261.21 2,319.35 6,023,629.00 536,062.00 0.00 4,278.35 2,386.94 6,023,582.00 536,129.80 4.00 4,360.86 2,432.96 6,023,550.00 536,175.96 4.00 4,417.03 2,468.84 6,023,525.04 536,211.95 0.00 4,460.84 2,550.76 6,023,468.07 536,294.12 0.00 4,560.84 2,632.68 6,023,411.10 536,376.29 0.00 4,660.83 2,714.60 6,023,354.13 536,458.46 0.00 4,760.83 2,796.52 6,023,297.16 536,540.63 0.00 4,860.83 2,878.43 6,023,240.19 536,622.80 0.00 4,960.82 2,960.35 6,023,183.22 536,704.97 0.00 5,060.82 3,042.27 6,023,126.25 536,787.14 0.00 5,160.82 3,124.19 6,023,069.28 536,869.31 0.00 5,260.81 3/212019 2:00.'48PM 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-16 Wellbore: MPU M-16 Design: MPU M-16 wp03 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) Usti 7,700.00 89.56 124.99 3,825.63 3,767.03 7,721.74 89.56 124.99 3,825.80 3,767.20 Start Dir 3.06°1100' : 7721.74' MD, 3825.8TVD 7,800.00 87.16 125.01 3,828.04 3,769.44 7,903.41 84.00 125.03 3,836.01 3,777.41 End Dir : 7903.41' MD, 3836.01' ND 3.06 7,942.93 84.00 125.03 3,840.14 3,781.54 Start Dir 3.060/100' : 7942.93' MD, 3840.14'TVD 8,000.00 85.74 125.01 3,845.24 3,786.64 8,100.00 88.81 124.99 3,849.99 3,791.39 8,122.71 89.50 124.99 3,850.33 3,791.73 End Dir : 8122.71' MD, 3850.33' TVD 5,782.59 8,200.00 89.50 124.99 3,851.00 3,792.40 8,300.00 89.50 124.99 3,851.88 3,793.28 8,400.00 89.50 124.99 3,852.75 3,794.15 8,500.00 89.50 124.99 3,853.62 3,795.02 8,600.00 89.50 124.99 3,854.49 3,795.89 8,700.00 89.50 124.99 3,855.37 3,796.77 8,800.00 89.50 124.99 3,856.24 3,797.64 8,900.00 89.50 124.99 3,857.11 3,798.51 9,000.00 89.50 124.99 3,857.98 3,799.38 9,100.00 89.50 124.99 3,858.86 3,800.26 9,200.00 89.50 124.99 3,859.73 3,801.13 9,300.00 89.50 124.99 3,860.60 3,802.00 9,322.71 89.50 124.99 3,860.80 3,802.20 Start Dir 301100' : 9322.71' MD, 3860.87VD 4,516.03 9,400.00 91.82 125.00 3,859.91 3,801.31 9,417.63 92.35 125.01 3,859.27 3,800.67 End Dir : 9417.63' MD, 3859.27' TVD 6,022,044.33 9,500.00 92.35 125.01 3,855.90 3,797.30 9,600.00 92.35 125.01 3,851.80 3,793.20 9,700.00 92.35 125.01 3,847.70 3,789.10 9,728.12 92.35 125.01 3,846.55 3,787.95 Start Dir 3-1100': 9728.12' MD, 3846.55'TVD 9,800.00 90.19 124.99 3,844.96 3,786.36 9,823.04 89.50 124.99 3,845.02 3,786.42 End Dir : 9823.04' MD, 3845.02' TVD 4,925.33 9,900.00 89.50 124.99 3,845.69 3,787.09 10,000.00 89.50 124.99 3,846.57 3,787.97 10,100.00 89.50 124.99 3,847.44 3,788.84 10,200.00 89.50 124.99 3,848.31 3,789.71 10,300.00 89.50 124.99 3,849.18 3,790.58 10,400.00 89.50 124.99 3,850.06 3,791.46 10,500.00 89.50 124.99 3,850.93 3,792.33 10,600.00 89.50 124.99 3,851.80 3,793.20 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-16 MPU M-16 Planned RKB @ 58.60usft MPU M-16 Planned RKB @ 58.60usft True Minimum Curvature 321/2019 2:00:48PM Page 6 COMPASS 5000.15 Build 91 Map Map +NI -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,767.03 -4,768.12 3,206.11 6,023,012.30 536,951.48 0.00 5,360.81 -4,780.59 3,223.92 6,022,999.92 536,969.34 0.00 5,382.55 -4,825.46 3,287.99 6,022,955.35 537,033.61 3.06 5,460.77 -4,884.61 3,372.42 6,022,896.58 537,118.30 3.06 5,563.86 -4,907.17 3,404.61 6,022,874.17 537,150.58 0.00 5,603.17 -4,939.79 3,451.16 6,022,841.77 537,197.28 3.06 5,660.01 4,997.08 3,532.96 6,022,784.86 537,279.34 3.06 5,759.88 -5,010.10 3,551.57 6,022,771.92 537,298.00 3.06 5,782.59 -5,054.42 3,614.88 6,022,727.89 537,361.51 0.00 5,859.87 -5,111.76 3,696.81 6,022,670.93 537,443.68 0.00 5,959.87 -5,169.10 3,778.73 6,022,613.97 537,525.85 0.00 6,059.87 -5,226.44 3,860.65 6,022,557.00 537,608.03 0.00 6,159.86 -5,283.78 3,942.57 6,022,500.04 537,690.20 0.00 6,259.86 -5,341.12 4,024.49 6,022,443.07 537,772.37 0.00 6,359.86 -5,398.47 4,106.42 6,022,386.11 537,854.55 0.00 6,459.85 -5,455.81 4,188.34 6,022,329.15 537,936.72 0.00 6,559.85 -5,513.15 4,270.26 6,022,272.18 538,018.89 0.00 6,659.84 -5,570.49 4,352.18 6,022,215.22 538,101.07 0.00 6,759.84 -5,627.83 4,434.11 6,022,158.26 538,183.24 0.00 6,859.84 -5,685.17 4,516.03 6,022,101.29 538,265.41 0.00 6,959.83 -5,698.19 4,534.63 6,022,088.36 538,284.07 0.00 6,982.54 -5,742.52 4,597.94 6,022,044.33 538,347.57 3.00 7,059.82 -5,752.62 4,612.37 6,022,034.29 538,362.05 3.00 7,077.44 -5,799.84 4,679.78 6,021,987.38 538,429.67 0.00 7,159.74 -5,857.16 4,761.62 6,021,930.44 538,511.75 0.00 7,259.66 -5,914.48 4,843.46 6,021,873.49 538,593.84 0.00 7,359.57 -5,930.60 4,866.47 6,021,857.48 538,616.93 0.00 7,387.67 -5,971.82 4,925.33 6,021,816.54 538,675.97 3.00 7,459.53 -5,985.03 4,944.20 6,021,803.41 538,694.90 3.00 7,482.57 -6,029.16 5,007.25 6,021,759.57 538,758.14 0.00 7,559.52 -6,086.50 5,089.17 6,021,702.61 538,840.32 0.00 7,659.52 -6,143.84 5,171.10 6,021,645.64 538,922.49 0.00 7,759.52 -6,201.18 5,253.02 6,021,588.68 539,004.66 0.00 7,859.51 -6,258.52 5,334.94 6,021,531.72 539,086.84 0.00 7,959.51 -6,315.87 5,416.86 6,021,474.75 539,169.01 0.00 8,059.50 -6,373.21 5,498.78 6,021,417.79 539,251.18 0.00 8,159.50 -6,430.55 5,580.71 6,021,360.83 539,333.36 0.00 8,259.50 321/2019 2:00:48PM Page 6 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-16 Wellbore: MPU M-16 Design: MPU M-16 wp03 Planned Survey Measured MPU M-16 Planned RKB @ 58.60usft MD Reference: Vertical North Reference: Depth Inclination Azimuth Depth TVDss (usft) (0) (0) (usft) usft 10,700.00 89.50 124.99 3,852.67 3,794.07 10,800.00 89.50 124.99 3,853.55 3,794.95 10,900.00 89.50 124.99 3,854.42 3,795.82 10,923.04 89.50 124.99 3,854.62 3,796.02 Start Dir 301100' : 10923.04' MD, 3854.62TVD 11,000.00 87.19 125.01 3,856.84 3,798.24 11,041.56 85.94 125.02 3,859.33 3,800.73 End Dir : 11041.56' MD, 3859.33' TVD 539,696.10 11,100.00 85.94 125.02 3,863.46 3,804.86 11,200.00 85.94 125.02 3,870.53 3,811.93 11,225.42 85.94 125.02 3,872.33 3,813.73 Start Dir 301100' : 11225.42' MD, 3872.33'TVD 11,300.00 88.18 125.00 3,876.15 3,817.55 11,323.94 88.90 124.99 3,876.76 3,818.16 End Dir : 11323.94' MD, 3876.76' TVD 8,982.74 11,400.00 88.90 124.99 3,878.22 3,819.62 11,500.00 88.90 124.99 3,880.14 3,821.54 11,600.00 88.90 124.99 3,882.06 3,823.46 11,700.00 88.90 124.99 3,883.98 3,825.38 11,800.00 88.90 124.99 3,885.90 3,827.30 11,900.00 88.90 124.99 3,887.82 3,829.22 12,000.00 88.90 124.99 3,889.74 3,831.14 12,100.00 88.90 124.99 3,891.66 3,833.06 123200.00 88.90 124.99 3,893.58 3,834.98 12,300.00 88.90 124.99 3,895.50 3,836.90 12,400.00 88.90 124.99 3,897.42 3,838.82 12,500.00 88.90 124.99 3,899.34 3,840.74 12,523.94 88.90 124.99 3,899.80 3,841.20 Start Dir 301100': 12523.94' MD, 3899.8'TVD 123600.00 91.18 124.99 3,899.75 3,841.15 12,616.57 91.68 125.00 3,899.33 3,840.73 End Dir : 12616.57' MD, 3899.33' TVD 6,020,221.93 12,700.00 91.68 125.00 3,896.89 3,838.29 12,800.00 91.68 125.00 3,893.96 3,835.36 12,900.00 91.68 125.00 3,891.03 3,832.43 13,000.00 91.68 125.00 3,888.10 3,829.50 133100.00 91.68 125.00 3,885.17 3,826.57 13,200.00 91.68 125.00 3,882.24 3,823.64 13,300.00 91.68 125.00 3,879.31 3,820.71 13,401.64 91.68 125.00 3,876.33 3,817.73 Start Dir 30/100' : 13401.64' MD, 3876.33'TVD 13,424.28 91.00 124.99 3,875.80 3,817.20 13,471.44 89.59 124.99 3,875.56 3,816.96 End Dir : 13471.44' MD, 3875.56' TVD 11,059.87 13,500.00 89.59 124.99 3,875.77 3,817.17 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-16 TVD Reference: MPU M-16 Planned RKB @ 58.60usft MD Reference: MPU M-16 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature 31212019 2:00.48PM Page 7 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,794.07 -6,487.89 5,662.63 6,021,303.86 539,415.53 0.00 8,359.49 -6,54523 5,744.55 6,021,246.90 539,497.70 0.00 8,459.49 -6,602.57 5,826.47 6,021,189.94 539,579.87 0.00 8,559.49 -6,615.78 5,845.35 6,021,176.81 539,598.81 0.00 8,582.53 -6,659.90 5,908.36 6,021,132.98 539,662.01 3.00 8,659.45 -6,683.70 5,942.34 6,021,109.34 539,696.10 3.00 8,700.93 -6,717.15 5,990.08 6,021,076.11 539,743.98 0.00 8,759.23 -6,774.39 6,071.78 6,021,019.25 539,825.93 0.00 8,858.98 -6,788.94 6,092.54 6,021,004.80 539,846.76 0.00 8,884.33 -6,831.66 6,153.55 6,020,962.35 539,907.95 3.00 8,958.81 -6,845.38 6,173.15 6,020,948.72 539,927.62 3.00 8,982.74 -6,888.99 6,235.45 6,020,905.40 539,990.11 0.00 9,058.79 -6,946.33 6,317.36 6,020,848.45 540,072.27 0.00 9,158.77 -7,003.66 6,39927 6,020,791.49 540,154.43 0.00 9,258.75 -7,060.99 6,481.18 6,020,734.54 540,236.59 0.00 9,358.73 -7,118.32 6,563.09 6,020,677.58 540,318.75 0.00 9,458.71 -7,175.66 6,645.00 6,020,620.63 540,400.92 0.00 9,558.70 -7,232.99 6,726.91 6,020,563.67 540,483.08 0.00 9,658.68 -7,290.32 6,808.82 6,020,506.71 540,565.24 0.00 9,758.66 -7,347.65 6,890.73 6,020,449.76 540,647.40 0.00 9,858.64 -7,404.99 6,972.64 6,020,392.80 540,729.56 0.00 9,958.62 -7,462.32 7,054.55 6,020,335.85 540,811.72 0.00 10,058.60 -7,519.65 7,136.46 6,020,278.89 540,893.88 0.00 10,158.58 -7,533.38 7,156.07 6,020,265.26 540,913.55 0.00 10,182.52 -7,576.99 7,218.38 6,020,221.93 540,976.05 3.00 10,258.58 -7,586.49 7,231.95 6,020,212.49 540,989.66 3.00 10,275.14 -7,634.32 7,300.27 6,020,164.98 541,058.19 0.00 10,358.53 -7,691.65 7,382.15 6,020,108.03 541,140.32 0.00 10,458.49 -7,748.97 7,464.04 6,020,051.08 541,222.46 0.00 10,558.45 -7,806.30 7,545.92 6,019,994.13 541,304.59 0.00 10,658.41 -7,863.63 7,627.80 6,019,937.19 541,386.73 0.00 10,758.36 -7,920.95 7,709.69 6,019,880.24 541,468.86 0.00 10,858.32 -7,978.28 7,791.57 6,019,823.29 541,551.00 0.00 10,958.28 -8,036.55 7,874.80 6,019,765.40 541,634.48 0.00 11,059.87 -8,049.53 7,893.34 6,019,752.51 541,653.08 3.00 11,082.51 -8,076.57 7,931.98 6,019,725.64 541,691.83 3.00 11,129.66 -8,092.95 7,955.37 6,019,709.37 541,715.30 0.00 11,158.22 31212019 2:00.48PM 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-16 Wellbore: MPU M-16 Design: MPU M-16 wp03 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-16 MPU M-16 Planned RKB @ 58.60usft MPU M-16 Planned RKB @ 58.60usft True Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,817.89 13,600.00 89.59 124.99 3,876.49 3,817.89 -8,150.30 8,037.29 6,019,652.40 541,797.47 0.00 11,258.22 13,700.00 89.59 124.99 3,877.21 3,818.61 -8,207.65 8,119.21 6,019,595.43 541,879.64 0.00 11,358.22 13,800.00 89.59 124.99 3,877.94 3,819.34 -8,265.00 8,201.13 6,019,538.46 541,961.81 0.00 11,458.22 13,900.00 89.59 124.99 3,878.66 3,820.06 -8,322.35 8,283.04 6,019,481.49 542,043.98 0.00 11,558.21 14,000.00 89.59 124.99 3,879.38 3,820.78 -8,379.69 8,364.96 6,019,424.52 542,126.15 0.00 11,658.21 14,100.00 89.59 124.99 3,880.11 3,821.51 -8,437.04 8,446.88 6,019,367.55 542,208.31 0.00 11,758.21 14,200.00 89.59 124.99 3,880.83 3,822.23 -8,494.39 8,528.80 6,019,310.57 542,290.48 0.00 11,858.21 14,300.00 89.59 124.99 3,881.56 3,822.96 -8,551.74 8,610.72 6,019,253.60 542,372.65 0.00 11,958.20 14,400.00 89.59 124.99 3,882.28 3,823.68 -8,609.09 8,692.64 6,019,196.63 542,454.82 0.00 12,058.20 14,500.00 89.59 124.99 3,883.00 3,824.40 -8,666.44 8,774.55 6,019,139.66 542,536.99 0.00 12,158.20 14,600.00 89.59 124.99 3,883.73 3,825.13 -8,723.79 8,856.47 6,019,082.69 542,619.16 0.00 12,258.20 14,700.00 89.59 124.99 3,884.45 3,825.85 -8,781.14 8,938.39 6,019,025.72 542,701.33 0.00 12,358.19 14,800.00 89.59 124.99 3,885.17 3,826.57 -8,838.49 9,020.31 6,018,968.75 542,783.50 0.00 12,458.19 14,900.00 89.59 124.99 3,885.90 3,827.30 -8,895.83 9,102.23 6,018,911.78 542,865.67 0.00 12,558.19 15,000.00 89.59 124.99 3,886.62 3,828.02 -8,953.18 9,184.14 6,018,854.80 542,947.84 0.00 12,658.18 15,021.47 89.59 124.99 3,886.78 3,828.18 -8,965.50 9,201.73 6,018,842.57 542,965.48 0.00 12,679.65 Start Dir 301100' : 15021.47' MD, 3886.78'TVD 15,024.32 89.50 124.99 3,886.80 3,828.20 -8,967.13 9,204.07 6,018,640.95 542,967.82 3.00 12,682.50 15,100.00 91.77 125.00 3,885.96 3,827.36 -9,010.53 9,266.06 6,018,797.84 543,030.00 3.00 12,758.17 15,132.13 92.73 125.01 3,884.70 3,826.10 -9,028.94 9,292.35 6,018,779.54 543,056.38 3.00 12,790.28 End Dir : 15132.13' MD, 3884.7' TVD 15,200.00 92.73 125.01 3,881.46 3,822.86 -9,067.83 9,347.88 6,018,740.91 543,112.08 0.00 12,858.07 15,300.00 92.73 125.01 3,876.69 3,818.09 -9,125.13 9,429.70 6,018,683.99 543,194.15 0.00 12,957.96 15,400.00 92.73 125.01 3,871.92 3,813.32 -9,182.43 9,511.52 6,018,627.06 543,276.21 0.00 13,057.84 15,443.13 92.73 125.01 3,869.86 3,811.26 -9,207.15 9,546.80 6,018,602.51 543,311.61 0.00 13,100.93 Start Dir 301100': 15443.13' MD, 3869.86'TVD 15,500.00 91.03 124.99 3,868.00 3,809.40 -9,239.75 9,593.36 6,018,570.13 543,358.31 3.00 13,157.76 15,520.94 90.40 124.99 3,867.73 3,809.13 -9,251.76 9,610.51 6,018,558.20 543,375.52 3.00 13,178.70 End Dir : 15520.94' MD, 3867.73' TVD 15,600.00 90.40 124.99 3,867.18 3,808.58 -9,297.09 9,675.28 6,018,513.16 543,440.48 0.00 13,257.76 15,700.00 90.40 124.99 3,866.48 3,807.88 -9,354.43 9,757.21 6,018,456.20 543,522.66 0.00 13,357.76 15,800.00 90.40 124.99 3,865.79 3,807.19 -9,411.77 9,839.13 6,018,399.23 543,604.83 0.00 13,457.75 15,900.00 90.40 124.99 3,865.09 3,806.49 -9,469.12 9,921.05 6,018,342.27 543,687.01 0.00 13,557.75 16,000.00 90.40 124.99 3,864.39 3,805.79 -9,526.46 10,002.98 6,018,285.31 543,769.18 0.00 13,657.75 16,100.00 90.40 124.99 3,863.69 3,805.09 -9,583.80 10,084.90 6,018,228.34 543,851.35 0.00 13,757.75 16,200.00 90.40 124.99 3,862.99 3,804.39 -9,641.14 10,166.82 6,018,171.38 543,933.53 0.00 13,857.74 1 16,300.00 90.40 124.99 3,862.30 3,803.70 -9,698.48 10,248.75 6,018,114.41 544,015.70 0.00 13,957.74 ^�\ 16,370.94 - 90.40 124.99 3,861.80. 3,803.20 -9,739.16 10,306.86 6,018,074.00 544,074.00 0.00 14,028.68 1 Total Depth : 16370.94' MD, 3861.8' TVD - 6 5/8" x 8 1/2" 1- 3/212019 2:00.48PM Page 8 COMPASS 5000.15 Build 91 Halliburton H A L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-16 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-16 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-16 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-16 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-16 16,370.94 Design: MPU M-16 wp03 6-5/8 8-1/2 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 6,617.24 3,810.55 9 5/8" x 12 1/4" 9-5/8 12-114 16,370.94 3,861.80 6 5/8" x 8 1/2" 6-5/8 8-1/2 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 460.00 460.00 0.00 0.00 Start Dir 30/100' : 460' MD, 460'TVD 800.00 798.21 -28.36 10.32 Start Dir 50/100': 800' MD, 798.2l'TVD 1,774.48 1,577.12 -516.49 231.18 End Dir : 1774.48' MD, 1577.12' TVD 5,566.68 3,53727 -3,452.80 1,615.61 Start Dir 50/100' : 5566.68' MD, 3537.27'TVD 6,317.24 3,779.19 -3,976.25 2,074.92 End Dir : 6317.24' MD, 3779.19' TVD 6,617.24 3,810.55 -4,147.34 2,319.35 Start Dir40/100':6617.24' MD, 3810.55'TVD 6,756.19 3,818.35 -4,226.86 2,432.96 End Dir : 6756.19' MD, 3818.35' TVD 7,721.74 3,825.80 -4,780.59 3,223.92 Start Dir 3.06°/100' : 7721.74' MD, 3825.8'TVD 7,903.41 3,836.01 -4,884.61 3,372.42 End Dir : 7903.41' MD, 3836.01' TVD 7,942.93 3,840.14 -4,907.17 3,404.61 Start Dir 3.06°/100' : 7942.93' MD, 3840.14'TVD 8,122.71 3,850.33 -5,010.10 3,551.57 End Dir : 8122.71' MD, 3850.33' TVD 9,322.71 3,860.80 -5,698.19 4,534.63 Start Dir 30/100' : 9322.71' MD, 3860.8'TVD 9,417.63 3,859.27 -5,752.62 4,612.37 End Dir : 9417.63' MD, 3859.27' TVD 9,728.12 3,646.55 -5,930.60 4,866.47 Start Dir 30/100': 9728.12' MD, 3846.55'TVD 9,823.04 3,845.02 -5,985.03 4,944.20 End Dir : 9823.04' MD, 3845.02' TVD 10,923.04 3,854.62 -6,615.78 5,845.35 Start Dir 30/100': 10923.04' MD, 3854.62'TVD 11,041.56 3,859.33 -6,683.70 5,942.34 End Dir : 11041.56' MD, 3859.33' TVD 11,225.42 3,872.33 -6,788.94 6,092.54 Start Dir 30/100' : 11225.42' MD, 3872.33'TVD 11,323.94 3,876.76 -6,845.38 6,173.15 End Dir : 11323.94' MD, 3876.76' TVD 12,523.94 3,899.80 -7,533.38 7,156.07 Start Dir 30/100': 12523.94' MD, 3899.8'TVD 12,616.57 3,899.33 -7,586.49 7,231.95 End Dir : 12616.57' MD, 3899.33' TVD 13,401.64 3,876.33 -8,036.55 7,874.80 Start Dir 30/100': 13401.64' MD, 3876.33'TVD 13,471.44 3,875.56 -8,076.57 7,931.98 End Dir : 13471.44' MD, 3875.56' TVD 15,021.47 3,886.78 -8,965.50 9,201.73 Start Dir 30/100' : 15021.47' MD, 3886.78'TVD 15,132.13 3,884.70 -9,028.94 9,292.35 End Dir : 15132.13' MD, 3884.7' TVD 15,443.13 3,869.86 -9,207.15 9,546.80 Start Dir 30/100' : 15443.13' MD, 3869.86'TVD 15,520.94 3,867.73 -9,251.76 9,610.51 End Dir : 15520.94' MD, 3867.73' TVD 16,370.94 3,861.80 -9,739.16 10,306.86 Total Depth : 16370.94' MD, 3861.8' TVD 3/212019 2:00:48PM Page 9 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-16 MPU M-16 MPU M-16 wp03 Sperry Drilling Services Clearance Summary Anticollision Report 21 March, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Well Coordinates: 6,027,765.37 N, 533,724.10 E (70° 29' 12.78" N, 1491 43'27.70" W) Datum Height: MPU M-16 Planned RKB @ 58.60usft Scan Range: 33.70 to 6,617.24 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: • • - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Hileorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-16 - MPU M-16 -MPU M-16 wp03 Scan Range: 33.70 to 6,617.24 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad M Pt L Pad MPL-36 - MPL-36 - MPL-36 6,108.70 970.09 6,108.70 846.40 13,979.50 7.843 Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36 6,617.24 769.69 6,617.24 684.71 13,897.44 9.058 Ellipse Separation Pass - MPL-36-MPL-36L1-MPL-361_1 6,D83.70 967.36 6,083.70 856.84 13,980.56 7.565 Clearance Factor Pass - MPL-36 - MPL-361_1 - MPL-361_1 6,617.24 769.69 6,617.24 684.68 13,897.44 9.054 Ellipse Separation Pass - MPL-36 - MPL-361_1 PB1 - MPL-361-1 P81 6,083.70 987.36 6,083.70 853.34 13,960.56 7.367 Clearance Factor Pass - MPL-36 - MPL-361_1 PB1 - MPL-361_1 PB1 6,61724 769.69 6,617.24 684.65 13,897.44 9.051 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,108.70 970.09 6,108.70 846.40 13,979.50 7.843 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,617.24 769.69 6,617.24 684.71 13,897.44 9.058 Ellipse Separation Pass - M Pt M Pad M-01 - M-01 - M-01 6,236.98 699.36 6,236.98 586.04 4,135.29 6.172 Centre Distance Pass - M-01 - M-01 - M-01 6,333.70 704.70 6,333.70 579.53 4,188.56 5.630 Ellipse Separation Pass - M-01 - M-01 - M-01 6,617.24 770.80 6,617.24 617.14 4,342.79 5.016 Clearance Factor Pass - M Pt Moose Pad Backup Proposal: MPU M-XX(IRA) - Slot 17 - Wellbore 458.70 180.12 458.70 176.16 458.80 45.498 Centre Distance Pass - Backup Proposal: MPU M-XX(IRA) - Slot 17 - Wellbore 508.70 180.34 508.70 176.03 508.79 41.865 Ellipse Separation Pass - Backup Proposal: MPU M-XX(IRA) - Slot 17 - Wellbore 933.70 211.61 933.70 204.31 921.16 28.983 Clearance Factor Pass - MPU M-12 - MPU M-12 - MPU M-12 365.17 242.54 365.17 238.86 365.84 65.910 Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12 408.70 242.76 408.70 238.71 405.93 59.998 Ellipse Separation Pass - MPU M-12 - MPU M-12 - MPU M-12 933.70 328.50 933.70 320.16 862.41 39.364 Clearance Factor Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 365.17 242.54 365.17 238.86 365.84 65.910 Centre Distance Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 406.70 242.76 408.70 236.71 405.93 59.998 Ellipse Separation Pass - MPU M-12 - MPU M-12PB1 - MPU M-12PB1 933.70 328.50 933.70 320.16 862.41 39.364 Clearance Factor Pass - MPU M -I2 -MPU M-12PB2-MPU M-12PB2 365.17 242.54 365.17 238.86 365.84 65.910 Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2 408.70 242.76 408.70 238.71 405.93 59.998 Ellipse Separation Pass - 21 March, 2019 - 14:01 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Scan Range: 33.70 to 6,617.24 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 21 March, 2019 - 14:01 Page 3 of 7 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPU M-12 - MPU M-12PB2 - MPU M-12PB2 933.70 328.50 933.70 320.16 862.41 39.364 Clearance Factor Pass - MPU M-20 - M-20 - M-20 wp02 385.84 172.42 385.84 168.98 385.94 50.179 Centre Distance Pass - MPU M-20 - M-20 - M-20 wp02 408.70 172.44 408.70 168.84 408.19 47.928 Ellipse Separation Pass - MPU M-20 - M-20 - M-20 wp02 5,683.70 605.51 5,683.70 476.50 8,445.38 4.694 Clearance Factor Pass - MPU M-211 - M-21 i - M -21i wp02 458.70 128.18 458.70 124.43 458.80 34.224 Centre Distance Pass - MPU M -21i - M -21i - M -21i wp02 483.70 128.30 483.70 124.38 483.80 32.725 Ellipse Separation Pass - MPU M -21i - M -21i - M -21i wp02 5,633.70 1,351.15 5,633.70 1,234.62 7,828.88 11.595 Clearance Factor Pass - MPU M-22 - M-22 - M-22 wp02 365.84 138.38 385.84 134.78 385.94 38.489 Centre Distance Pass - MPU M-22 - M-22 - M-22 wp02 406.70 138.40 408.70 134.62 408.23 36.607 Ellipse Separation Pass - MPU M-22 - M-22 - M-22 wp02 658.70 164.36 656.70 158.63 639.12 28.718 Clearance Factor Pass - MPU M -23i - M -23i - M -23i wp02 383.70 195.12 383.70 191.91 383.80 60.830 Centre Distance Pass - MPU M -23i - M -23i - M -23i wp02 408.70 195.17 408.70 191.79 407.64 57.699 Ellipse Separation Pass - MPU M -23i - M -23i - M -23i wp02 733.70 236.09 733.70 230.54 700.00 42.546 Clearance Factor Pass - MPU M -25i - Slot 16 - M -25i - M-251 wp03 458.70 244.31 458.70 240.35 458.80 61.712 Centre Distance Pass - MPU M -25i - Slot 16 - M -25i - M -25i wp03 483.70 244.42 483.70 240.29 483.80 59.126 Ellipse Separation Pass - MPU M -25i - Slot 16 - M -25i - M -25i wp03 808.70 290.98 808.70 284.72 766.14 46.503 Clearance Factor Pass - Plan: MPU M -13i - M-131 - M-1 3i wp03 748.30 267.72 748.30 261.26 734.55 41.413 Centre Distance Pass - Plan: MPU M -13i - M -13i - M-1 3i wp03 758.70 267.75 758.70 261.21 743.35 40.947 Ellipse Separation Pass - Plan: MPU M -13i - M-1 3i - M-131 wp03 1,733.70 450.65 1,733.70 435.04 1,552.24 28.864 Clearance Factor Pass - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp06 361.51 179.72 361.51 176.46 361.31 55.112 Centre Distance Pass - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp06 408.70 179.84 408.70 176.25 407.00 50.109 Ellipse Separation Pass - Plan: MPU M-14 - MPU M-14 - MPU M-14 wp06 1,808.70 265.08 1,808.70 244.56 1,710.10 12.918 Clearance Factor Pass - Plan: MPU M -15i - M -15i - M-1 5i wp04 619.63 89.21 619.63 83.79 617.00 16.471 Centre Distance Pass - Plan: MPU M -15i - M -15i - M -15i wp04 733.70 89.61 733.70 83.33 728.88 14.267 Ellipse Separation Pass - Plan: MPU M -15i - M-1 5i - M -15i wp04 6,617.24 815.01 6,617.24 660.19 6,560.99 5.264 Clearance Factor Pass - Plan: MPU M-171 - M -17i - M-171 wp02 921.51 82.87 921.51 75.49 928.91 11.237 Centre Distance Pass - Plan: MPU M -17i - M-1 7i - M -17i wp02 1,008.70 83.37 1,008.70 75.18 1,016.59 10.173 Ellipse Separation Pass - Plan: MPU M-1 7i - M -17i - MAT wp02 2,958.70 221.97 2,958.70 163.73 2,970.87 3.811 Clearance Factor Pass - Plan: MPU M-18 - M-18 - Custer - MPU M-18 wp03 1,783.70 119.92 1,783.70 102.03 1,775.00 6.704 Clearance Factor Pass - Plan: MPU M-18 - M-18 - Custer - MPU M-18 wp03 1,787.45 119.92 1,787.45 102.03 1,778.43 6.706 Ellipse Separation Pass - 21 March, 2019 - 14:01 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-16 -MPU M-16 - MPU M-16 wp03 Scan Range: 33.70 to 6,617.24 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 21 March, 2019 - 14:01 Page 4 of 7 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp02 540.84 148.35 540.84 143.86 539.28 33.060 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp02 583.70 148.49 583.70 143.70 582.20 31.005 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp02 6,617.24 1,290.18 6,617.24 1,130.19 6,354.12 8.064 Clearance Factor Pass - Plan: MPU M -19i - M-191 - Jeb Stuart - MPU M -19i wp( 648.35 206.65 648.35 201.36 651.20 39.126 Centre Distance Pass - Plan: MPU M -19i - M-191 - Jeb Stuart - MPU M -19i wp( 708.70 206.85 708.70 201.11 711.88 36.044 Ellipse Separation Pass - Plan: MPU M -19i - M-1 9i - Jeb Stuart - MPU M-191 wp( 6,008.70 1,496.87 6,008.70 1,375.58 5,749.01 12.342 Clearance Factor Pass - Plan: MPU M-1 9i P2 - M -19i P2 - M-1 9i P2 wp02 364.73 240.12 364.73 236.87 360.86 73.855 Centre Distance Pass - Plan: MPU M -19i P2 - M -19i P2 - M -19i P2 wp02 483.70 240.32 483.70 236.24 479.27 58.896 Ellipse Separation Pass - Plan: MPU M-1 9i P2 - M-1 9i P2 - M-191 P2 wp02 5,933.70 1,494.56 5,933.70 1,373.94 5,747.80 12.392 Clearance Factor Pass - Prelim Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) v 681.79 267.68 681.79 262.17 669.24 48.655 Centre Distance Pass - Prelim Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) v 708.70 267.78 708.70 262.10 693.21 47.169 Ellipse Separation Pass - Prelim Plan: MPU M-13 - M-13 - M-13 (Stonewall Inj) v 1,683.70 452.43 1,683.70 436.61 1,521.02 28.602 Clearance Factor Pass - Prelim Plan: MPU M -23i - M118 - M -23i wp03 285.60 180.12 285.60 177.45 266.00 67.385 Centre Distance Pass - Prelim Plan: MPU M -23i - M118 - M -23i wp03 333.70 180.31 333.70 177.29 312.13 59.897 Ellipse Separation Pass - Prelim Plan: MPU M -23i - M118 - M -23i wp03 808.70 241.77 808.70 235.57 748.65 38.984 Clearance Factor Pass - Prelim Plan: MPU M -23i - Bad Copy?? - M -23i - M -23i 409.59 180.62 409.59 177.05 389.99 50.708 Centre Distance Pass - Prelim Plan: MPU M -23i - Bad Copy?? - M -23i - M-231 433.70 180.66 433.70 176.93 412.91 48.441 Ellipse Separation Pass - Prelim Plan: MPU M -23i - Bad Copy?? - M -23i - M -23i 783.70 223.04 783.70 217.02 726.10 37.053 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mcl 1,983.70 65.31 1,983.70 48.48 2,055.96 3.882 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mcl 2,054.38 63.03 2,054.38 49.82 2,124.54 4.772 Centre Distance Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mcl 2,383.70 101.57 2,383.70 66.84 2,444.08 2.925 Clearance Factor Pass - Proposal: M-XX(IRA) - Slot 22 - Wellbore #1 - M -XX - v 458.70 173.10 458.70 169.14 458.80 43.724 Centre Distance Pass - Proposal: M-XX(IR4) - Slot 22 - Wellbore #1 - M -XX - v 483.70 173.23 483.70 169.10 483.80 41.904 Ellipse Separation Pass - Pmposal: M-XX(IRA) - Slot 22 - Wellbore #1 - M -XX - v 858.70 212.33 658.70 205.56 855.79 31.368 Clearance Factor Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 458.70 218.10 458.70 214.14 421.10 55.097 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 508.70 218.25 508.70 213.95 471.09 50.668 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 1,033.70 256.05 1,033.70 247.94 984.84 31.593 Clearance Factor Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 458.70 269.73 458.70 265.77 421.10 68.140 Centre Distance Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 558.70 270.05 558.70 265.40 521.06 58.053 Ellipse Separation Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 1,056.70 298.15 1,058.70 289.65 1,000.00 35.934 Clearance Factor Pass - 21 March, 2019 - 14:01 Page 4 of 7 COMPASS HA1_LIBURTON Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 From (usft) 33.70 6,617.24 To (usft) 6,617.24 MPU M-16 wp03 16,370.94 MPU M-16 wp03 Survey/Plan Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point 21 March, 2019 - 14:01 Page 5 of COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELLDETABS:PIan:MPUM-16 NAD1927(NADCONCONUS) Alaska Zone04 Coordinate (NIE) Reference: Web Plan: MPU TrueNorth 6. Site: M Pt Moose Pad (ND) Reference: MPU M-16 Planned ed RNorthKB @ 58.60uait 24.90 spnmv O�nn..g Well: Plan: MPU M-16 tlottedemont,a MPLI M-16 Planned RKB®58.60estt MwearCalculation +0.00 Noshing 112.784c Longitude Wellbore: MPU M-16 Method: Minimal Curvature 0.00 33724. 6027765.37 533724.L0 70°29'72]fi49N 149°43'2]]026W Plan: MPU M-16 wp03 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering criteria Date: 2017-11-14700:00:00 Validated: Yes Version: ur 33.70 To 16370.94 Ladder/S.F. Plots Depth From Depth To l Tool 33.70 6617.24 MPUPUM-16M-16 wp03 (MPU M-16) 2 MW D+IFR2+MS+Sa9 I CASING DETAILS SH (1 of 2) 6617.24 16370.94 MPU M-16 wp03(MPU M-16) 2_MWD+IFR2+MS+Sa TVD TVDSS MD Size Name 3810.55 3751.95 6617.24 9-58 95/8"x121/4" 3861.80 3803.20 16370.94 6-58 65/8"x81/2" c150.00 M-18 P2 02 _ ._.. M-22 02on f., j ! j i 0120.00 M -21i wp 2 MPU M 18 wp03 ' -._-....._..-- _.......__.-- � c wp04j !-15i 90.00 d rb M-080 3W wp02 - McLaws 60.00 _- -- ---- -- 30.00 0.00 0 350 700 1050 1400 1750 21 DO 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650 Measured Depth (700 usft/in) 4.00----. ! --' -- I -- 0 - 3.00 _ ............. _...__ .... - - 1' L. O '... 2.00 n Collision Risk Procedures Req. ! '.. d Collision Avoidance Req. ! 1.00 No -Go Zone - Stop Drilling' NOERRORS ! ! 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650 Measured Depth (700 usft/in) Hilcorp Milne Point Alaska, LLC M Pt Moose Pad Plan: MPU M-16 MPU M-16 MPU M-16 wp03 Sperry Drilling Services Clearance Summary Anticollision Report 21 March, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Well Coordinates: 6,027,765.37 N, 533,724.10 E (70° 29' 12.78" N, 149° 43'27.70" W) Datum Height: MPU M-16 Planned RKB @ 58.60usft Scan Range: 6,617.24 to 16,370.94 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: • • - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -16 -MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Scan Range: 6,617.24 to 16,370.94 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point Measured Minimum @Measured Ellipse @Measured Clearance SummaryBased on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft M Pt J Pad MPJ -24 - MPJ -24A- MPJ -24A 6,670.69 766.92 6,670.69 679.86 13,887.19 8.609 - Pass - MPJ -24 - MPJ -24L1 - MPJ -24L1 6,717.24 769.02 6,717.24 678.41 13,878.00 8.487 - Pass - MPL-36-MPL-36L1-MPL-361_1 7,217.24 MPJ-24-MPJ-24L1PB1-MPJ-24L1PB1 7,217.24 609.74 13,762.06 6.459 Clearance Factor Pass - - 6,670.69 MPJ -24 - MPJ-24L1PB2 - MPJ-24L1PB2 6,670.69 679.62 13,887.19 8.784 Centre Distance Pass - - 6,717.24 MPJ -24 - MPU J-24 - MPJ -24 6,717.24 677.84 13,878.00 8.435 Ellipse Separation Pass - - 7,217.24 958.08 7,217.24 805.27 13,762.06 MPJ -27 - MPJ -27 - MPJ -27 16,370.94 1,262.61 16,370.94 855.20 10,197.66 3.099 Clearance Factor Pass - M Pt L Pad Centre Distance Pass - MPL-35 - MPL-35 - MPL-35 8,792.24 1,116.20 8,792.24 993.70 13,372.07 9.112 Clearance Factor Pass - MPL-35 - MPL-35 - MPL-35 9,342.24 967.08 9,342.24 867.93 13,336.70 9.753 Ellipse Separation Pass - MPL-35 - MPL-35A- MPL-35A 8,792.24 1,116.20 8,792.24 993.52 13,372.87 9.099 Clearance Factor Pass - MPL-35 - MPL-35A- MPL-35A 9,342.24 967.08 9,342.24 867.93 13,337.50 9.753 Ellipse Separation Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 8,792.24 1,116.20 8,792.24 993.39. 13,372.87 9.089 Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 9,342.24 967.08 9,342.24 867.82 13,337.50 9.743 Ellipse Separation Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 8,792.24 1,116.20 8,792.24 993.39 13,372.87 9.089 Clearance Factor Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 9,342.24 967.08 9,342.24 867.82 13,337.50 9.743 Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 8,792.24 1,116.20 8,792.24 993.39 13,372.87 9.089 Clearance Factor Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 9,342.24 967.08 9,342.24 867.82 13,337.50 9.743 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 6,670.69 766.92 6,670.69 680.17 13,887.19 8.840 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 6,717.24 769.D2 6,717.24 679.14 13,878.00 8.556 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 7,192.24 943.57 7,192.24 803.35 13,768.49 6.729 Clearance Factor Pass - MPL-36 - MPL-361_1 - MPL-361_1 6,670.69 766.92 6,670.69 679.86 13,887.19 8.609 Centre Distance Pass - MPL-36 - MPL-361_1 - MPL-361_1 6,717.24 769.02 6,717.24 678.41 13,878.00 8.487 Ellipse Separation Pass - MPL-36-MPL-36L1-MPL-361_1 7,217.24 958.08 7,217.24 609.74 13,762.06 6.459 Clearance Factor Pass - MPL-36-MPL-36L1 PB1 -MPL-361_1 PB1 6,670.69 766.92 6,670.69 679.62 13,887.19 8.784 Centre Distance Pass - MPL-36-MPL-361_1 PB1 -MPL-361_1 P81 6,717.24 769.02 6,717.24 677.84 13,878.00 8.435 Ellipse Separation Pass - MPL-36 - MPL-361_1 PB1 - MPL-361_1 PB1 7,217.24 958.08 7,217.24 805.27 13,762.06 6.270 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,670.69 766.92 6,670.69 660.17 13,887.19 8.840 Centre Distance Pass - 21 March, 2019 - 14.02 Page 2 of 6 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Scan Range: 6,617.24 to 16,370.94 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 21 March, 2019 - 14:02 Page 3 of 6 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPL-36 - MPL-36PB1 - MPL-36PB1 6,717.24 769.02 6,717.24 679.14 13,878.00 8.556 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 7,192.24 943.57 7,192.24 803.35 13,768.49 6.729 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 12,567.24 471.07 12,567.24 217.29 13,874.00 1.856 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 12,617.24 458.80 12,617.24 213.94 13,874.00 1.874 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 12,708.20 449.69 12,708.20 227.51 13,874.00 2.024 Centre Distance Pass - MPU L-52 - MPU L-52 - MPU L-52 10,817.24 506.41 10,817.24 294.70 14,000.00 2.392 Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-52 10,917.24 480.71 10,917.24 285.02 14,000.00 2.456 Ellipse Separation Pass - MPU L-52 - MPU L-52 - MPU L-52 10,989.06 474.90 10,989.06 293.17 14,000.00 2.613 Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53 9,467.24 200.60 9,467.24 72.58 14,759.32 1.567 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 9,492.24 186.85 9,492.24 70.44 14,768.64 1.595 Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53 9,584.51 167.67 9,584.51 79.79 14,800.00 1.908 Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-54 13,067.24 1,149.71 13,067.24 889.15 13,500.00 4.412 Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54 13,242.24 1,124.11 13,242.24 874.76 13,500.00 4.508 Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-54 13,321.07 1,121.34 13,321.07 878.77 13,500.00 4.623 Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56 10,217.24 304.12 10,217.24 115.41 14,330.00 1.612 Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56 10,242.24 295.45 10,242.24 113.03 14,330.00 1.620 Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56 10,333.75 280.92 10,333.75 122.90 14,330.00 1.778 Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57 11,692.24 495.48 11,692.24 276.19 13,941.00 2.259 Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-57 11,767.24 476.55 11,767.24 269.12 13,941.00 2.297 Ellipse Separation Pass - MPUL-57-MPU L -57 -MPU L-57 11,852.44 468.87 11,852.44 279.34 13,941.00 2.474 Centre Distance Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,242.24 1,187.99 11,242.24 972.21 13,186.00 5.506 Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,492.24 1,145.25 11,492.24 945.41 13,186.00 5.731 Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 11,567.87 1,142.75 11,567.87 948.77 13,186.00 5.891 Centre Distance Pass - M Pt M Pad M-01 - M-01 - M-01 6,617.24 770.80 6,617.24 617.14 4,342.79 5.016 Clearance Factor Pass - M Pt Moose Pad MPU M-20 - M-20 - M-20 wp02 6,617.24 1,253.27 6,617.24 1,097.31 9,002.64 8.036 Clearance Factor Pass - Plan: MPU M-151 - M -15i - M-1 5i wp04 12,576.83 810.94 12,576.83 449.38 12,518.40 2.243 Centre Distance Pass - 21 March, 2019 - 14:02 Page 3 of 6 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-16 - MPU M-16 wp03 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -Plan: MPU M-16 - MPU M-16 - MPU M-16 wp03 Scan Range: 6,617.24 to 16,370.94 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point From To Survey/Plan Survey Tool (usft) (usft) 33.70 6,617.24 MPU M-16 wp03 2_MWD+IFR2+MS+Sag 6,617.24 16,370.94 MPU M-16 wp03 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles I (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 21 March, 2019 - 14.:02 Page 4 of 6 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M -15i - M -15i - M -15i wp04 16,370.94 813.10 16,370.94 278.18 16,311.45 1.520 Clearance Factor Pass - Plan: MPU M-171- M-1 7i - M -17i wp02 6,617.24 819.41 6,617.24 642.11 6,748.96 4.622 Centre Distance Pass - Plan: MPU M -1 7i - M -1 7i - M -17i wp02 12,417.24 836.07 12,417.24 490.84 12,673.35 2.422 Ellipse Separation Pass - Plan: MPU M -17i - M -1 7i - M-171 wp02 12,542.24 846.14 12,542.24 495.06 12,752.72 2.410 Clearance Factor Pass - Plan: MPU M-18 - M-18 - Custer - MPU M-18 wp03 6,617.24 1,089.94 6,617.24 938.23 6,376.02 7.184 Ellipse Separation Pass - Plan: MPU M-18 - M-18 - Custer- MPU M-18 wp03 12,692.24 1,468.96 12,692.24 1,126.41 12,860.84 4.288 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp02 6,617.24 1,290.18 6,617.24 1,130.19 6,354.12 8.064 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Me[ 6,617.24 1,238.18 6,617.24 1,144.42 5,910.50 13.205 Clearance Factor Pass - Milne Point Exploration MPU-Liviano-01 - Liviano-01 - Liviano-01 9,418.15 359.05 9,418.15 219.95 3,942.61 2.581 Centre Distance Pass - MPU-Liviano-01 - Liviano-01 - Liviano-01 9,442.24 359.77 9,442.24 219.55 3,934.68 2.566 Clearance Factor Pass - MPU-Liviano-0l-Liviano-01A-Liviano-01A 9,585.57 290.76 9,585.57 160.36 3,898.06 2.230 Centre Distance Pass - MPU-Liviano-0l-Liviano-01A-Liviano-01A 9,617.24 292.39 9,617.24 159.60 3,890.59 2.202 Clearance Factor Pass - From To Survey/Plan Survey Tool (usft) (usft) 33.70 6,617.24 MPU M-16 wp03 2_MWD+IFR2+MS+Sag 6,617.24 16,370.94 MPU M-16 wp03 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles I (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 21 March, 2019 - 14.:02 Page 4 of 6 COMPASS REFERENCE INFORMATION WELL DETAILS:PIan: MI'U M-16 NAD 1927 (NADCON CONUS) Alaska Zone 04 Project: Milne Point HALLIBURTON Co-orrinate (NIE) Reference: WoR Plan: MPU M-16, Two Nodh Site: MPt Moose Pad 24.90 Ver6cal(TVD)Reference: MPU W16 Planned RKB@58.60mit SPuny O�illing Well: Plan: MPU M-16 Measured Depth Reference: MPU W16 Planned RKB@5160ush +N/ -S +E/ -W Northing Fading Lalillude Longitude Wellbore: MPU MPU Calculation Method Minimum Cuwalure 0.00 000 6027765.37 533724.10 7W 29'12.9849N 149.43'27.9036W -16 Plan: MPU M-16 Wp03 SURVEY PROGRAM O GLOBAL FILTER: Using user defined selection 8 filtering criteria Date: 2017-11-14TOD:00:00 Validated: Yes Version: 33.70 To 16370.94 Ladder/S.F. Plots Depth From Deplh To Tool CAS NG DETA LS MPUSuiweylPlan 33.70 6617.24 MPU M-16 wp03 (MPU M-18) 2_MWD+IFR2+MS+Sag E PH (2 of 2) 6617.24 16370.94 MPUM-16wp03(MPUM-16) 2_MWD+IFR2+MS+SagTVD TVDSS MD Siu Name 810.55 3751.95 6617.24 9-5/8 95/8"x121/4" 861.80 3803.20 16370.94 6-5/8 6 5/8" n 8 12" . .. X150.00 O L-56 olzo.00 _t__...__._._._.. _— _._..._.. - - -- 6 o 90 .00- - _ L-53/ - - _ ; - - --- - J 24 - I I m L_-- - L) o - -- fi .. ...__.- - .:i.. - i 0.00 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 Measured Depth (1000 usfUin) 400 —�T777 -- - —t—.- — - – _ — -- - o 3.00 ----- ---1--- -t—. ___ I LL I O 2.00 o. Collision Risk Procedures Req. d rn Collision Avoidance Req. 1.00 No -Go Zone - Stop Drillini NOERRORS 0.00 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 Measured Depth (1000 usfUin) Davies, Stephen F (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Wednesday, April 17, 2019 11:07 AM To: Davies, Stephen F (DOA) Subject: RE: [EXTERNAL] MPU M-16 (PTD 219-061) - Another Question Steve — M-16 planned TO is 16,371. My apologies for the typo error on the PTD form. Regarding abnormal pressure, page 29, section 15.14 has the prior history of pressure seen while drilling laterals on M - Pad. Pressure seen while drilling the lateral on M-10, which was the most severe, was due to offset injection of F-110 and L-50. Pressure value was determined after shutting in the well and confirmed with mud weight. On subsequent j wells, M-12 and M-11, managed pressure drilling equipment was used to monitor the well for pressure on connections. Once at the surface casing shoe, if necessary, sufficient overbalance is confirmed with an increase in MW and static flow check. Observed pressure values are below. M-10: 11.5 M-12: 10.2 M-11: 10.0 As we get further away from F-110 and L-50, we expect the pressure to decrease to zero. The current well we are drilling, M-14, has not seen any pressure on connections while drilling the lateral at current depth. Our planned mud program will account for any abnormal pressure seen. Please let me know if you have any questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 1 99503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.gov] Sent: Tuesday, April 16, 2019 10:17 AM To: Joe Engel <jengel@hilcorp.com> Subject: [EXTERNAL] MPU M-16 (PTD 219-061) - Another Question Joe, On page 48 of this application, Hilcorp states: "Abnormal pressure has been seen on M -Pad." The Formation Tops & Information table on page 45 indicates a constant pressure gradient of 8.46 ppg EMW. Page 53 states the expected pressure in the OA sand is 8.46 ppg EMW. In which M -Pad wells, and at what depths, were abnormal pressures encountered? What were the measured values of those pressures? How were they determined? Will Hilcorp's planned mud program be sufficient to control those pressures? Thank you, Steve Davies AOGCC 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 Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. From: Davies, Stephen F (DOA) Sent: Tuesday, April 16, 2019 9:44 AM To: Joe Engel <lenael@hilcorp.com> Subject: MPU M-16 (PTD 219-061) - Question Joe, Just checking: Will the total depth of this well be 16,731' MD or 16,371' MD? The reason I ask is that the Permit to Drill form indicates 16,731' in both the "Proposed Depth" and "Casing Program MD" boxes, but the directional survey proposal report stops at a total depth of 16,370.94' MD. If 16,731' is the proper value, I'm assuming that the borehole azimuth and inclination values will remain constant throughout the lowest part of the proposed well. Correct? Thank you, Steve Davies AOGCC 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 savingor forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesC7alaska.gov. Schwartz, Guy L (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Monday, April 22, 2019 1:09 PM To: Schwartz, Guy L (DOA) Cc: Davies, Stephen F (DOA); Cody Dinger Subject: RE: [EXTERNAL] M-16 PTD 219-061 Attachments: MP M-16 Wellhead Proposed 4-22-19.pdf; Milne Point Unit M-16 Drilling Program -Page 26 RU MPD.PDF Guy - The Jet pump will be reverse flow. Tree diagram attached. Please find the updated page 26 of the drilling program, highlighting MPD RU on step 14.3 We will include a OH sidetrack summary with the 10-407. Please let me know if you have any other questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Schwartz, Guy L (DOA) (mailto:guy.schwartz@alaska.gov] Sent: Monday, April 22, 2019 9:44 AM To: Joe Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: [EXTERNAL] M-16 PTD 219-061 Joe, Couple of items on the PTD. 1. Will the Jet pump be reserve flow? Please include a tree diagram with SVS shown 2. Looks like MPD will be rigged up for lateral. Make sure this is in the procedure where BOPE are installed instead of just in remarks on Page 29. 3. We discussed notify AGOCC when you need to do OH sidetracks in zone. I would also like a summary page with the 10-407 that outlines each PB section (date, depth of sidetrack, KOP etc ) Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Development —Service —Exploratory Stratigraphic Test Non -Conventional FIELD: &e m r POOL: % of v 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. (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - _ _-) from records, data and logs acquired for well name on ermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first cau ht 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 (CompanyName) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Comnanv 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 da s after com letion, sus ension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT M-16 Program DEV Well bore seg ❑ PTD#:2190610 Company HI_LQORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11338 On/Off Shore On Annular Disposal ❑ Administration '1 Permit fee attached__________ ___________ ____________ __ NA-..__.._________..______..__....._....__ _............_................-- 2 Lease number appropriate_ _ _ _ _ _ ............. . ..... Yes .. _ .. Surf. Loc 8 Top prod Int lie in ADL0025514; TO lies. in A440025515. _ _ 3 Unique well. name and number------ -- ------------------------------ YeS_. ------------------..... _ _. _.. _. 4 Well located ina. defined pool _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ - Milne Point Schrader Bluff. Oil Pool (.525140), governed by. CO 477, amended by CO 477.05.. _ .. _ . _ ..... . 5 Well located proper distance from drilling unit -boundary.. _ ______ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ CO 477.05 specifies:. "There are no restrictions as to well spacing except that no pay shall - - . - _ _ _ _ _ _ _ _ _ 6 Well located proper distance. from other wells _ _ _ _ _ . ............. Yes be opened -in a well closer than 500 feet from the exterior boundary of the. affected area." 7 Sufficient acreage available in drilling unit... _ _ _ _ _ _ _ _ _ _ _ Yes _ _ As planned, well conforms to spacing requirements, _.................................. . 8 If deviated, is wellbore plat. included - - - - - - _ _ _ .. _ .. _ ... Yes - 9 Operator only affected party------ - - - - - - - - - - - - - - - - - - - - - - - - - Yes- ---------------------- 10 Operator has. appropriate bond in force _ - - - - - - - - - - - - - - - - - - - - - - - Yes - 11 Permit can be issued without conservation order _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes. Appr Date 12 Permit can be issued without administrativeapproval- _ _ _ _ .... ......... Yes 13 Can permit be approved before 14 -day wait. - Yes _ _ _ _ _ _ _ _ ..... .. ..... ..... ..... ... . SFO 4/16/2019 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 Pre -produced injector; duration of pre production less than_3 months (For service well only) - - NA _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ............. 17 Nonoonven, gas conforms to AS31,05.03%1.A),(-2.A-D) _ - - - - - - - - - _ . NA - - - - - - - _ _ - _ - - ..... _ _ _ 18 Conductor string.provided _ _ _ _ _ _ _ _ _ _ _ ................... Yes ....... 20 inch. conductor set at. 113' - - - - - - - - - - - - - Engineering- 19 Surface casing, protects all known USDWs . . . . . . . . . . . . . ................. NA. _ _ .Permafrost area.., waived, 20 CMT.vol adequate to circulate on conductor& suit-csg . . . . . . . ............... Yes ....... 9 5/8" surface casing will use ES tool at 2500 ft._ 2 stages- _ - _ _ _ .................. . _ _ _ .. _ 21 CMT. vol adequate to tie-in long string to surf osg ........... . . . . . . . . . . . . . . No- _ horizontal lateral will use slotted liner.,. no cement.. 22 CMT. will cover all known productive horizons . . . . . . . . . ....... . . .... Yes 23 Casing designs adequate for C. T, B &_permafrost. _ _ _ _ _ _ _ _ ... Yes _ - BTC calcs provided. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 24 Adequate tankage -or reserve pit .. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Rig Doyon 14 has steel pits. AJI waste to. approved disposal well .. _ 25 If a. re -drill, has.a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ . NA. _ _ _ _ . 26 Adequate wellbore separation proposed _ _ _ . . . ..................... Yes J-24 well -is very. close at very _end of the lateral. (15300 ft. MD) -CA zone is abandoned, 27 If diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .... ..... _ ....... _ . Appr Date 28 Drilling fluid. program schematic & equip list adequate... ..... _ _ _ _ _ _ _ Yes _ _ Max formation press. 1676 psi.(&.6. ppg EMW ) will drill with 0.979.5 ppg Mud and MPD to control wet{. ---- GLS 4/19/2019'29 BOPEs,.do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ MPD being used ,. Could be some higher pressure from close offset SB injectors.... 30 BOPS press rating appropriate; test to (put psig in comments)_ ... _ _ _ _ _ Yes _ _ _ . 13 5/8" 5000 psi WP BOPE-on Doyon 14___ 31 Choke. manifold complies w/API. RP -53 (May 84)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 32 .Work will occur without operation shutdown..... _ - - - - _ . - - _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 33 Is presence of H2$ gas probable . . . . . . ............................. No........ H2$ not expected .... _ ........... 34 Mechanical epnOtion of wells within AOR verified (For. service well only) . - - _ - . . 35 Permit can be issued w/o hydrogen sulfide measures _ _ _ _ . .............. Yes ....... H2S not anticipated from drilling of offset wells; however, rig wig have H2S sensors and alarms- Geology 36 Data.presented on potential overpressure zones _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - Gas_ hydrates not expected from drilling of offset wells..However-mitigiticin.mejasures are discussedin . . Appr Date 37 Seismic analysis of shallow gas zones . . . . . ............... . .. . . .. . . . . . . NA _ _ _ _ _ _ "Anticipated Drilling Hazards" -section. _Abnormal pressure up to 11,5 ppg EMW has. been encountered in SFD 4/18/2019 38 Seabed .condition survey(if off -shore) . . ................... . . . . . . ..... . . NA _ _ _ WPad wells due to. nearby injection, Managed. Pressure Drilling will be used to monitor and control _ 39 Contact name/phone for weekly progress reports_ [exploratory only] ................. NA. _ pressure, Onsite materials sufficient to build system to1_ppg above highest antioipated mud weight. Geologic Engineering DPublic Date Will be a reverse Jet Pump completion. MPD being used for lateral to control possible pressure from offset SB injectors. GIs. Date: ate Commissioner: Commissioner: Commissioner