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Home My WebLink About219-1421 Winston, Hugh E (CED) From:Winston, Hugh E (CED) Sent:Tuesday, November 16, 2021 9:38 AM To:nathan.sperry@hilcorp.com Subject:MPU S-201 Permit Expired Hi Nathan, The permit for MPU S‐201 (PTD# 219‐142) has expired on November 4th, 2021 under regulation 20 AAC 25.005 (g). The permit has been marked expired in the well history file and in the AOGCC database. Please let me know if you have any questions or concerns regarding this expiration. Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission hugh.winston@alaska.gov 907‐793‐1241 THE STATE °'ALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 u u llnaa��l Re: Milne Point Field, Selimde, Bitiff Oil Pool, MPU S-201 Hilcorp Alaska, LLC Permit to Drill Number: 219-142 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Surface Location: 3213' FSL, 561' FEL, Sec. 12, T12N, R10E, UM, AK Bottomhole Location: 557' FSL, 1172' FEL, Sec. 11, T12N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, �e' rice Chair DATED this ! day of November, 2019. STATE OF ALASKA OCT 17 2019 AL, .A OIL AND GAS CONSERVATION COMM1�_.JN PERMIT TO DRILL®G�(, 20 AAC 25.005 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill 0 Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑� , Service - Winj ❑ Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 - MPU S-201 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 11,659' TVD: 3,565' Milne Point Field Ugnu Undefined 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 3213' FSL, 561' FEL, Sec 12, T12N, R10E, UM, AK ADL380109, ADL380110 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 545' FSL, 803' FEL, Sec 12, T12N, R10E, UM, AK LONS 01-001 11/25/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 557' FSL, 1172' FEL, Sec 11, T12N, R10E, UM, AK 4997 544' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 64.7 15. Distance to Nearest Well Open Surface: x- 565450 y- 5999877 ' Zone-4 GL / BF Elevation above MSL (ft): 38.2 to Same Pool: 1,320' to MPS-203 ' 16. Deviated wells: Kickoff depth: 350 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96.4 degrees Downhole: 1694 Surface: 1307 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) 42" 20" 215# X-42 Weld 107' Surface Surface 107' 107' ±270 ft3 Stg 1 L - 1118 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 6,246' Surface Surface 6,246' 3,846' Stg2L-1937ft3/T-314ft3 Tieback 7-5/8" 29.7# L-80 Hyd 521 6,096' Surface Surface 6,096' 3,859' Tieback Assy 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 5,563' 6,096' 3,859' 11,659' 3,565' 150p Screens Linerw/ Swell Pkrs 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No Q 20. Attachments: Property Plat BOP Sketch ❑ Drilling Program Time v. Depth Plot ❑ ❑✓ Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hIICOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: Q , i . Commission Use Only Permit to Drill umber: Permit Approval See cover letter for other Number: l �—Z 50- 0 _Q -CC) Date: I 11 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. , v l) — T Samples req'd: Yes ❑ No[?' Mud log req'd: Yes ❑ No [J' S HZS measures: Yes ❑ No,--,� Directional svy req'd: Yes [�No ❑ ' S p � S ;_ cti � r!"-Spacing exception req'd: Yes ❑ NoE+ Inclination -only svy req'd: Yes ❑ Noa?" Post initial injection MIT req'd: Yes ❑ No ❑ �}��y^► APPROVED BY 1 Approved by: \ I 1 1 COMMISSIONER THE COMMISSION Date: 1 f/ Submit Form and F9 5/ 17 This permit is valid for 24 months f o h t of p oval per 20 AAC 25.005(g) A achments in Du licat Hilcorp Alaska, LLC Milne Point Unit (MPU) S-201 Drilling Program Version 1 10/17/2019 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 13-5/8" 5M Diverter Configuration.....................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Production Screen Liner...........................................................................................32 17.0 Run 7-5/8" Tieback.......................................................................................................................37 18.0 Run Jet Pump Assembly...............................................................................................................40 19.0 RDMO............................................................................................................................................41 20.0 Innovation Rig Diverter Schematic.............................................................................................42 21.0 Innovation Rig BOP Schematic....................................................................................................43 22.0 Wellhead Schematic......................................................................................................................44 23.0 Days Vs Depth................................................................................................................................45 24.0 Formation Tops & Information...................................................................................................46 25.0 Anticipated Drilling Hazards.......................................................................................................47 26.0 Innovation Rig Layout..................................................................................................................50 27.0 FIT Procedure................................................................................................................................51 28.0 Innovation Rig Choke Manifold Schematic................................................................................52 29.0 Casing Design.................................................................................................................................53 30.0 8-1/2" Hole Section MASP............................................................................................................54 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................55 32.0 Surface Plat (As Built) (NAD 27).................................................................................................56 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 1.0 Well Summary Well MPU S-201 Pad Milne Point "S" Pad Planned Completion Type Jet Pump on 3-1/2" Production Tubing Target Reservoir(s) Ugnu NIB Planned Well TD, MD / TVD 11,658' MD / 3,564' TVD PBTD, MD / TVD 11,648' MD / 3,564' TVD Surface Location (Governmental) 3213' FSL, 561' FEL, Sec 12, T12N, R10E, UM, AK Surface Location (NAD 27) X= 565,450, Y= 5,999,877 Top of Productive Horizon (Governmental) 545' FSL, 803' FEL, Sec 12, T12N, R10E, UM, AK TPH Location (NAD 27) X= 565,231 Y= 5,997,207 BHL (Governmental) 557' FSL, 1172' FEL, Sec 11, T12N, RI OE, UM, AK BHL (NAD 27) X= 559,584 Y=5,997,172 AFE Number 1915273 AFE Drilling Days 17 days AFE Completion Days 4 days AFE Drilling Amount $3,788,915 AFE Completion Amount $2,423,352 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1307 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1694 psig Work String 5" 19.5# S-135 DS-50 & NC 50 KB Elevation above MSL: 26.5 ft + 38.2 ft = 64.7 ft GL Elevation above MSL: 38.2 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 2.0 Management of Change Information Hilcorp Alaska, LLC Hililcorp Changes to Approved Permit to Drilil Date: 10/9/2019 Subject: Changes to Approved Permit to Drill for MPU 5-201 File #: MPU S-201 Drilling and Completion Program Any modifications to MPU S-201 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Date Date Milne Point Unit S-201 Ugnu Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in).in) Drift Conn OD gin- Wt #!# Grade Conn Burst (psi)(psi) Collapse , Tension k- Cond 20" 19.25" - - - X-52 Weld 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 Tieback 7-5/8" 6.875" 6.75" 7.947 29.7 L-80 Hydril521 6,890 4,790 683 8-1/2" 4-1/2 Screens 3.920 3.795 4.714 13.5 L-80 Hydril625 9020 8540 279 4.0 Drill Pipe Information: Hole OD ID (in) TJ' ID TJ OD - Wt Grade Conn M/U WIT Tension Section (in) (in: in #/ft) (Min) Max) . k-lbs) Surface & 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k1b Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcoW.com, mmyers@hilcorp, jenszel@hilcorp.com and cdinger(2hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyersghilcorp,com jengelghilcorp.com and cdingerghilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyersghilcorp.com jengelghilcorp.com and cdin er2hilcorp.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 jengel@hilcoM.com Completion Engineer Taylor Wellman 907.777.8449 907.907.9533 twellman@hilcorp.com Geologist Seth Nolan 907.777.8308 907.519.8225 snolan@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilggM.com Page 5 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 6.0 Planned Wellbore Schematic Milne Point Unit Well: MPU S-201 Proposed Schematic Last Completed: Future PTD: TBD ----------------------------------- --- - - --- - - -- - - -- - Clr`g. t05 Ec: e25.S/GL Eev.:3&2' TREE &WELLHEAD Tree Carr mn 3-1/8" SM Wellhead I TMC Gen V TD=14EW fKO /TD=3,SW{TVq PBTD=11,0V Nq /PBTD=3,5W (TIMI D ----------E--------------------• OPEN HOLE /CEMENT TAIL a✓ Conductar 1270 k3 12•1f4' StgI-lead-MEW /Tail-45a113 1 Sig 2 -Lead-1917 ft3 /Tail - 314 ft3 Ccmcatlm Screen Liner in 8-1 We CASING DETAIL Sae Type Wt/ Grade/ Clue ID Top etm BPF 2D' Conductor 215 / X-S2 / Weld N/A Surface ICIT WA 9-w. Surface 40 / L-20 / TXP SR 8.935 Surface U49 0.0758 7-5/8" Tieback 29.7 / L-W / Vyd S21 1 6.875 Surface 409G DOM 4-1/2" Limr ISOIL Screens 13.S/L-9Q/tIydriI62S 1 1920 6,OW 1X6S9' 1 .0149 TUBING DETAIL 3-1/2" Tub,f-g 9.3/L-80/CUE-8rd 2-992 1 Surface I 16,2W (60067 WELL INCLINATION DETAIL XOP @ 3S0' Max Nate Angle = 96.4 i----"'"------------'---------------'------------- IEWELRY DETAIL Nm No. Top MD Item. ID 1 t22' Tulin K Han (3-1f2' TC-11 Top & &W 2.867' 2 =51179 3.5" Diuharge Aawre Gauge Mandrel (D-rubarge Gauge) 2.975' 3 =5,39W 3.5" CMD Sliding Sleeur 2.913' 4 =S,399' 3.5'Gauge Mkandrel w/ X" Are Itntake Gauge) 2.975' 5-S,421' 3.9'X Nipple 13.E13" Packing Bore 2.813' 6-S,46B' 7-5/9" x 3.5" FIIL Retrievable Packer 2.8a5' 7 =5,4W 3.5" XN Nipple 2.7SO' a z6,20V 3.S"Mule3hoe 2.867' Lower Completion 9 -Q096' 90TSLWLTP.xker/Limrflarger4-1a'x9-5fa' 6.LWI 10-6,096' 7-5/B"Thebackkm. 6.1S3' 11 -6,1IV 7' H563 x 4.5' 625 L-20 XO 3.630" 12 111,654' 1-AV Valve LTC q4&(1" Ball an Seat/Ctosedl 4-1/2" SOLID LINER DETAIL --------------------------------------------------------------- Top TOP Ban w- 4-1/2' Screens LINER DETAIL (MD) (TVD) (MD) CrM) 1tS Top (MD) Tap (TVD) MM {MD} Bt1r1 {TVD] ---------------------------------------- GENERAL WELL INFO API: TBD Com letion Date: Future Page 6 4-1/2" SOLID LINER DETAIL --------------------------------------------------------------- Top TOP Ban w- 4-1/2' Screens LINER DETAIL (MD) (TVD) (MD) CrM) 1tS Top (MD) Tap (TVD) MM {MD} Bt1r1 {TVD] ---------------------------------------- GENERAL WELL INFO API: TBD Com letion Date: Future Page 6 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU S-201 is a grassroots jet pump producer planned to be drilled in the Ugnu MB sand. S-201 is part of multi well program targeting the Ugnu sand on S-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 Ugnu MB sand. An 8.5" lateral section will then be drilled. A 4-1/2" 150µ screen liner will be run in the open hole section and the well produced with an jet pump assembly. s The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately November 25th, 2019, pending rig schedule. Surface casing will be run to 6,245' MD / 3,846' 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 Innovation to well site 2. N/U & Test 13-5/8" 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 4-1/2" screen production liner. 6. Run 7-5/8" tieback. 7. Run production tubing. 8. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: On Site geologist. LWD: GR + Res 2. Production Hole: On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Milne Point Unit S-201 Ugnu 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 S-201. Ensures to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 515 min (annular to 50% rated WP, 2500 psi on the high test for initial LI/ 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: None requested Page 8 Milne Point Unit S-201 Ugnu Producer Hilco+Tt+� E-W Company Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" 0 13-5/8" 5M CTI Annular BOP w/ 16" diverter line Function Test Only • 13-5/8" x 5M Control Technology Inc Annular BOP • 13-5/8" x 5M Control Technology Inc Double Gate Initial Test: 250/3000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 0 13-5/8" x 5M Control Technology Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz c2alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppgalaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(c�r�,alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/o,gc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Hilcorrp �� Milne Point Unit S-201 Ugnu Producer Drilling Procedure 9.0 RX and Preparatory Work 9.1 S-201 will utilize a newly set 20" conductor on S Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers will be used on in the production lateral only. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Ensure 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spur @ 96.5% volumetric efficiency. Page 10 Milne Point Unit S-201 Ugnu Producer HilmiT Drilling Procedure E-W Company 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program). • N/U 20" x 13-5/8" DSA • N/U 13 5/8", 5M diverter "T". • NU 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 Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. • Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 11 10.4 Rig & Diverter Orientation: 75' Radius Clear of ignition Sources — inverter Line MPU S pad Page 12 Milne Point Unit S-201 Ugnu Producer Drilling Procedure S-201 � I 4, I i 203 1 39 37 f 204 f ■ 35 I E 34 E 33 I ■ 32 ■ 3, i M 30 ■ 29i *.Drawing Not To Scale Milne Point Unit S-201 Ugnu Producer Drilling Procedure 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to section TD, in the Ugnu MB 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 cps 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. • AC: There are no wells with a clearance factor of <1.0 in the surface hole section Page 13 Hilcorp Energy C—p-y Milne Point Unit S-201 Ugnu Producer Drilling Procedure Gas hydrates may be present on S-Pad. S-15i encountered hydrates in 2002, no other well have seen hydrates. If seen, they are typically around 2100-2400' TVD (lust 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 • 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. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional Jbarite 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+ (Higher MW for hydrates if seen/needed) 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) BARACARBsBAROFIBRE/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. Page 14 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 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 - 9.8 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section 1 Density Viscosity Plastic Viscosit Yield Point API FL pH Tern Surface 8.8 - 9.8 1 75-175 20 - 40 25-45 <10 8.5 - 9.0 1 -< 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 - 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 - 9.2 ppg PAC-L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb 11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.7 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. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Milne Point Unit S-201 Ugnu Producer 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 assemblv consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. • 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 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth R IN 7—Float Depth hoe "Reference Casing sales tdanual SeCLan 5 Page 17 "A Overall Length B Man. ID After Drlllout C Max. Tcol OD D Opening Seat ID E Closing Seat ID Plug Set Part No. G., 1 Closing Plug 91 Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit S-201 Ugnu Producer Drilling Procedure Hilcorp ES -II Running Order 641 Cementer Shut Off Plug Rattle Adapter By -Pass Plug By Pass Baffle Float Collar Float Shoe Milne Point Unit S-201 Ugnu Producer Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to—2,000' above shoe (Top of U ng_u) • Verify depth of lowest Ugnu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). • 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. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs Page 18 Milne Point Unit S-201 Ugnu Producer Hilcol�I Drilling Procedure Energy Comps-ny TXP@ BTC 11/0812018 Outside Diameter 9.625 in_ Min. Wall 87.5% Thickness (') Grade L80/ Type 1 Wall Thickness 0.395 an. Connection OD REGULAR - Option COUPLING PIPE BODY Body Red istBand: Red Grade L80 Type 1' Drift API Standard 1st Band: Broom 2nd Sand: 2nd Band: - Brown Type Casing 3rd Sand:- 3rd Band: - 4th Band: - PIPE BODY DATA GEOMETRY Nominal OD 9.625 in. Nominal Weight 40 lbs"It Drift 8.679 in. Nominal ID 8.8-15 in. Wa1 Thickness 0.3M '- Plain End kNeight 38.97 IbsYt 00 Tc4-- ante API PERFORMANCE BodyY*4J Strength 916 x1000Its IntemalYied 5750 psi sh1Ys 80000 psi Cr4ase 3090 psi GEOMETRY Compaction OD 10.625 in. Coupling Length 10 825 in. connection ID 8.823 in. Make-up Lis 4.891 in. Threes per in 5 connection OD Option REGULAR PERFORMANCE Tension Ett>aiencp 100.0 % ,k+inty*id stength 916-000 x1000 Internal Pressure Capacity lit 5750.000 psi Ibs Compression Efrciency 100 % Compression Strength 916.000 x1000 Max. Allmvable Bending 38 `,100 ft lbs External Pressrre Capacity 3090.000 ps MAKE-UPTORQUES t+r nimium 19860 ft-`_S Optimum 20960 h-Ibs Maximum 23060 ft-Ibs OPERATION LIMIT TORQUES Opera aq Torque 35600 S- _s Yield Torque 43400 hobs Notes This connection is fully interchangeable with: TXP8 BTC - 9.625 in_ - 36/43.5147 / 53.5 / 58.4 Ibs..* [11 Internal Pressure Capacity related to structural resistance onty. Internal pressure leak resistance as per section 10.3 API 5C31 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. Page 19 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Milne Point Unit S-201 Ugnu Producer Hilco7�T+ Drilling Procedure EneW C® . 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 11t Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" (5,245' - 2500') x .0558 bpf x 1.3 = 199.1 1118 Casing Total Lead 199.1 1118 12-1/4" OH x 9-5/8" (6, 245' - 5, 245') x .0558 b pf x 1.3 = 72.5 407 — Casing ~ [:::j]5:/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 -SCH 5.x Milne Point Unit S-201 Ugnu Producer Hilco � �� Drilling Procedure Cement Slurry Design (lst Stage Cement Job): Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 11.7 I b/ga I 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 6125' x .0758 bpf = 464.3 bbls 80 bbl of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 / Milne Point Unit S-201 Ugnu Producer Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Milne Point Unit S-201 Ugnu Producer Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2" Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) -o 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 J 12-1/4" OH x 9-5/8" Casing (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 — 12-1/4" OH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM 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 Milne Point Unit S-201 Ugnu Producer Hilco Drilling Procedure Eo�� r� 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: ,/ 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run "casing tally & casing and cement report to iengelghilcorp. com and cdin_ er e,hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 14.0 BOP NX and Test 14.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M CTI 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 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5" BOP test plug (if not installed previously). • Test BOP to 250/3000 psi for 515 min. Test annular to 250/2500 psi for 515 min. • 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 14.4 R/D BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.9 Ensure 5" liners in mud pumps. Page 26 ff Hilcorp Energy C—pmy 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22' PDM) Milne Point Unit S-201 Ugnu Producer Drilling Procedure 15.2 TIH w/ 8-1/2" ceanout 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 and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. • Casing test & Fit Digital Data to AOGCC 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" 19.54 5-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1 /2" hole section mud program summary: Page 27 Milne Point Unit S-201 Ugnu Producer Drilling Procedure • 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. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg Baradrill-N drilling fluid Properties: / tA j� Section DensityPlastic ViscosityYield Point Total Solids MBT HPHT Production 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N-VIS 1.0 — 1.5 ppb DEXTRID LT 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppb BARACOR 700 1.0 ppb Page 28 Milne Point Unit S-201 Ugnu Producer Hilco Drilling Procedure Eon BARASCAV D 10.5 ppb X-CIDE 207 0.015 npb 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM:120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • 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 • AC: There are no wells with a clearance factor <1.0 in the production lateral. • S-22, plugged Ugnu producer, is —60' away C-C, however the lateral is fully cemented and is not a risk. • Schrader Bluff NB Concretions: Historically 4-6% of lateral 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. Page 29 Milne Point Unit S-201 Ugnu Producer Hilcorp Drilling Procedure 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 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. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. Proposed brine blend (aiming for an 8 on the 6rpm reading) - KCI: 7.1 bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb • Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 Perform production screen test (PST). Reduce flow rate and RPM as per PST Test Procedure. The mud has been properly conditioned when the mud will pass the production screen test (3 33Oral samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Ugnu MB sand screen completion require passing PST with 150µ coupons • Circulate and condition fluid as much as needed to pass the production screen test 15.20 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm min). • Rotate at maximum rpm that can be sustained. Page 3 0 Milne Point Unit S-201 Ugnu Producer Hilco+rn Drilling Procedure Energy Company • 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 15.21 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow. Increase fluid weight if necessary. If abnormal pressure has been seen, displace to higher MW (determined on closed connections) from surface shoe to surface. Wellbore breathing has been seen on MPU SB wells, may be possible for Ugnu. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.24 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 31 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 16.0 Run 4-1/2" Production Screen Liner 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" production screens, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" screen. • 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. 16.2. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" production screens: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers 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. R/U 4-1 /2" screen running equipment. • Ensure 4-1/2" 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. 16.4. Run 4-1/2" screen production liner — Reference screen handling and running procedure. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound will plug the screens. • Use Hydril 625 stabbing guide on screen joints • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 4-1/2" Screens should auto —fill, top off with completion brine if needed • Swell packers will not be required on this completion unless the well is drilled out of zone Page 32 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 4-1/z" Lower Completion Running Order • 4-%2" Float Shoe, BTC box (Bakerlok all 4-1/2" shoe track connections below the last semi- premium/premium connection) • 4-%2" WIV (wellbore isolation valve), BTC box x pin • 4-'/2" spacer joint, —30 - 40', IBT-M box x BTC pin • 4-1/2" Drillable Pac Off Sub, IBT-M box x pin • 5' 4.5" 13.5# Hydril 625 Box X 4.5" 12.6# IBT Pin crossover • 1 joint 4-1/2" 13.5#/ft L-80 Hydril 625 Liner (optional) a 4-1/2" 13.5#/ft L-80 Hydril 625 Screens • Joints of 4-'/2" 13.5#/ft Hydril 625 L-80 Liner (liner lap) as needed • 4' 4.5" 13.5# Hydril 625 Box X Pin pup joint (safety joint) • 7" 26# HYD 563 Box x 4.5" 13.5# Hydril 625 Pin crossover • Baker SLZXP Liner Hanger/Liner Top Packer w/ 7" 26# Hydril 563 pin 4-1/2" 13.5 # L-80 Hvdril 625 Torque OD Minimum Maximum Operating Torque 4.5" 8,000 ft-lbs 12,800 ft-lbs 12,800 ft-lbs Page 33 Wedge 625C) Page 34 Milne Point Unit S-201 Ugnu Producer Drilling Procedure Pr,m.d-1013112017 Outside Diameter 4.500 in. Min. Walk 87.5% Thickness (") Grade L80 Type 1 Walt Thickness 0190 in. Connection OD REGULAR COUPLING PIPE BODY Option Body: Red 1st Hand: Red Grade L80 Type 1' Drift API Standard 1st Band: Broom 2nd Band: 2nd Band: - Brown Type 3rd Band. - 3rd Band: - Casing 4th Band: - P iPEB'_,r t E PT. GEOMETRY Nominal OD 4500 in. Nominal Weight 13.50lbst.. Drift 3.795 in. Nominal ID 3.920 in. Wall Thickness 0290 in. Plain End Weight 13.05lbs/ft OD Tcleranoe API PERFORMANCE Body Yield Strength 307 x1000 lbs Internal Yield 9020 psi Sl f rs 80000 psi Collapse 8540 psi GEOMETRY Connection 0:) 4714 in. Connection ID 3-M in- Make-up Loss 4.830 in. Threads per in 3-59 Connection OD Option REGULAR UVINKOINt'1lW1112 Tension E.'fivency 91.0 ch Joint Yield Strength 279-370 x "=009 Intema! Pressure Capacity 9020.000 psi Ibis. Compression Eficiency 94.5 % Compression Strength 290.115 0000 Max. Allowable Bending 73.7 1,100 It lb=_ External Pressure Capacity 8540.000 psi MAKE-UP TORQUES Minimum 8000 ft-Ibs Optimum 9600 ft-[bs Maximum 12800 R-tbs OPERATION LIMIT TORQUES OperaSrvg Torque 12800 ft-Ibs `afield Torque 15000 ft-Ibs Milne Point Unit S-201 Ugnu Producer Hilco Drilling Procedure � c Note: Blank Pipe and Swell Packers may be ran if any out of zone excursion occur during lateral drilling 16.6. Pick up enough liner to provide for approximately 150' overlap inside 9-5/8" casing. • 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. 16.7. R/U false rotary and run 2-3/8" 6.4 # Inner String • Drift 2-3/8" inner string with minimum 1.5" drift (WIV closing ball 1.25") 16.8. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U liner hanger/liner top packer to inner string and 4-1 /2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packof. . Wait 30 min for mixture to set up. 16.10. Note PUW, SOW, ROT and torque. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The screens and inner string will prevent the DP from auto filling. Fill DP with PST passed fluid 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, &20rpm 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. 16.18. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. Page 35 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 16.19. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up to 4500 psi to activate the hydraulic pusher tool to set the SLZXP packer. This will also release the HRDE running tool. 16.20. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.21. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. P/U above liner top packer and displace well to completion fluid. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. 16.25. Once liner is on bottom, swap to completion AFE Page 36 Milne Point Unit S-201 Ugnu Producer Hilco+Tf�1+ Drilling Procedure Facw Company 17.0 Run 7-5/8" Tieback 17.1 RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. POOH. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7-5/8" (250/3000 psi) solid body casing rams. , 17.2 R/U 7-5/8" 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 7-5/8" seal assembly has 1" x4 holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7-5/8" annulus. 17.4 M/U first joint of 7-5/8" to seal assy. 17.5 Run 7-5/8" 29.7# H521 tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 3 7 H Hi1mTE--W Milne Point Unit S-201 Ugnu Producer Drilling Procedure Wedge 5210 11 1'08;201 8 Ouitskle Diameter T.US n- Min. Wall 87-5% Thickness Grade 1-80 11111111111106", Type 1 Wall Thickness 0-375 in. Connection OD REGULAR Option COUPLING PIPE 601YY Fs=d,- Red 1 vt Baia Red Grade U18 Type I• Drift AN Standard 1st Fiaml: Brown 2PA David: 2nd Ound Brown Type Casing 3rd Dane 9rd Band &ard 7 7 GEOMETRY OC 7.625.n IYanninalV16ght 29,78 ltsAl C."ti 6.75'n 15.975iri. 'Halt Thickness 0.375 mn Plain End Wacrg 29-06IL5,T CIL, 7.2ioranct AF1 PERFORMANCE ecd, YGid stmr-sith 693 x orm, It,. kNKrral Y.6d 6890 Pei SFJYs 20406 Psi C-DIIAV-D 4790 V-i CONNECTION DATA 'GEOMETRY C,u n n a c I wn CO 7.947 in. C. nnocz,an ID 6A00 Vz�c-.p Lc , 1700'n 7hrc�J� fnn, In 3.25 cnnnaual CC, Cpacr, REGULAR PERFORMANCE Ttrzian F11c,nn." 71-2 Jc4nl Ytid Snn:rgn 48 62% 1 CK,0 Mmmal Pmt;s. re C ;.nzic4,, 61190AN ps, IL camprns",nn Ettt:,-, 27A7,11 C-0rnPrC-s,-*n sifem'T, 597625 xiCic MA, Akwalak,2cr,Irg 34-2 ','1CQ Ili ILS 4750-411041 Psa MAKE-UP TORQUES Vrim.m. 8400 t-ini C)P"M.m 1010Q Mz,MuM 14700, Ins OPERATION UMIT TORQUES Tf,4.p 35000 'tAn. Y.0d Tcn:jua 53M t-ID, Notes This, connection is, IfuRty interchangeabile with: Wedge 521 S - 7.625 in. - 26.4)33.7 139 lbs4t Connections -Afth Dopeless,12) Technok)gy are fully compatible mth the same c:onnectirn in its. Standard version Page 38 Hilcorp E_-W C—Pay 17.6 M/U 7-5/8" 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. Milne Point Unit S-201 Ugnu Producer Drilling Procedure 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 — 1 Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string & remove unnecessary 7-5/8" 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 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8" 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 7-5/8", verify collapse pressure of 7-5/8" 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 7-5/8" x 9-5/8" product' n annuLtoI000 psi / 30 min. 17.3 Set test plug and change top ramso 2-7/8" x 5-1/2" VBR. rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 39 Test annular and lower Milne Point Unit S-201 Ugnu Producer Hilco+rp Energy Company Drilling Procedure 18.0 Run Jet Pump Assembly 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 (reverse circulating) as per the following: 3-1/2" Multi -drop Gauge Mandrel 5' pup joint 3-1/2" Sliding Sleeve 5' pup joint 4-1/2" Gauge Mandrel 4' pup joint 10' pup joint 3-1/2" X Nipple (ID=3.813") 10' pup joint 10' pup joint 7-5/8"x3-1/2" Retrievable Packer 10' pup joint 10' pup joint 3-1/2" XN Nipple (ID=3.75") — set shallower than 70deg deviation. Preload RHC plug body. 10' pup joint 4-1/2" full joints (# joints to be determined by on deviation survey) 4-1 /2" WLEG Confirm depths with OE post drilling and final directional survey (reference updated schematic). 18.3 M/LJ 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 Freeze protect well. 18.8 Drop ball and rod, pressure up to 1,700 psi to start setting of FHL packer. 18.9 Continue to pressure up to 3,000 psi to set packer. 18.10 Pressure up to 3,500 psi to test tubing for 30 minutes and chart. 18.11 Bleed tubing to 2,000 psi. 18.12 Pressure up annulus to 3,500 psi to test casing/packer for 30 minutes and chart. 18.13 Bleed tubing and IA down to 0 psi. 18.14 RILDS and test hanger. LD landing joint. 18.15 Install BPV. N/D BOP. Page 40 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 18.16 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.17 Set BPV plug. Test tree to 250 psi low / 5000 psi high. Pull BPV plug and BPV. 18.18 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.19 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. 18.20 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 RDMO Innovation Rig Page 41 20.0 Innovation Rig Diverter Schematic 3-118' Kill line 13-518' 5M Technology Sint 13-5/8' Page 42 Milne Point Unit S-201 Ugnu Producer Drilling Procedure ;ontrol Technology 3-518' 5M Control 'ethnology Double Ram -118' Choke Line _-16' Diverter Line Hfi=EnmU Company 21.0 Innovation Rig BOP Schematic Page 43 Milne Point Unit S-201 Ugnu Producer Drilling Procedure ---'---13-5/8" 5M Control Technology Annular BOP F. t13-5/8" 5M Control s Technology Double Ram ('IIS�'i/r LL• 1\�C i l 3-1/8* Choke Line O ® -------13-5/8" 5M Control Technology Single Ram 13-5/8" x 5M 11"x5M 9-5/8" DBL D Seal 2-1/16" x 5M Casing Hanger 13-5/8" x 5M S-22 13-518" NOM 9-5/8" BTC Btm x 2-1/16" x 5M 10.5" -4 SA Pin Top W/ Primary Seal jfj 20" Casing 9-5/8" Casing Milne Point Unit S-201 Ugnu Producer Hilcm Emgy Drilling Procedure 22.0 Wellhead Schematic a LIW' -1 C W� C 300 LL I At, j ?Ell 5 SL 111 1 -10 L mil (clIF I(I r, I F 11 fill "M�, Z", 1[1 iv!ft ."T 0, 1,, ,.K A: X. F C1 4 �6 1 11 8M W 16 Gr4l rl,. C1 10 0 Page 44 23.0 Days Vs Depth Page 45 I r MPU S-201 Days vs Depth IN 1ICI , K Milne Point Unit S-201 Ugnu Producer Drilling Procedure icer 8000 10000 12000 0 5 10 15 20 25 Days i" Milne Point Unit S-201 Ugnu Producer Drilling Procedure 24.0 Formation Tops & Information MPU S-201 Formations (wp06) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2254 -1816 1842 810.48 8.46 LA3 4737 -3459 3485 1533.4 8.46 Ugnu MB 5684 1 -3787 1 3851 1694.44 8.46 GENERALIZED GEOLOGICAL INFORMATION FORMATION LITH GEOL. DESCRIPTION COMMENTS SS Al o.er Aetna rGW(YTct 42W o o ° o . o Predominant) y heavy. pe y gravel conglomerate from surface to 1800 ft Predominantly pebbly g VVII I I I IIIIIIJONLO DIRECTIONAL PROBLEMS: 0 0 . HMH DEC;kEE DOGLEGS AT 1397 IN S-21 Lc"dnt tope or1. S.M. Sidetracked at 1,000- • a a badge at 2326 (2201 tvd). 1273' SV5 0 +1- 100` a sao 0 Predominantly conglomerate gravel with increasing concentrations of GAS HYDRATES MAY BE 0 0 o b e clay down to2500. PRESENT AT S-PAD. +I- 10 1O0' SV4 0 o u S-15i (2002) encountered hydrates in 175D' o 0 Base of Permafrost +;-1750 as. and below the permafrost. None of 0 o the other 2002 and 2003 S-Pad wells 0 C rs drilled reported any shallow hydrate! 2,000' a 21G0' SV3JT5 0 q o SV3: Fine grained and well sorted sand, coarsening upward, deposited'n SURFACE CASING AT+A 2500 TVDSS IS +f-100' 2183' SV2TT4 o a shallow marine shelf environment- Overlain by a 65 ft marine shale and REQUIRED ON ALL NEW S-PAD WELLS BEGINNING WITH S-19 IN OCT.2DD2 DUE +1. 100' silty shale bed which acts as a major confining layer and isolates TO POTENTIAL OVER -PRESSURE FROM Sag vanirktok injection into the lower Sagavanirtok sands. SV3 may contain gas INJECTORS. hydrates under5-Pad. SURFACE CASING RUNNINGI SV2: Fine grained and well sorted marine sandstone, coarsening upward, CEMENTING PROBLEMS: 2600' Top SV11T3 with shale in lower section. SV2 may contain gas hydrates under S-Pad. tvbder:Se Incidents. S 01 stuck casing +f- 100' 5ft high and hadto set casing on slips. SVt: Shallow marine sandstone with shale in lower section. SV1 may S+34 hit brrdge,iost returns and h2dio contain gasfgas hydrates under S-Pad. do atop cenweA pb. Cther mnartight hde incident: 5�90 (set :>4 3864 t,xl ). 3,000- Continued interbeds of sands, clays and siitstones with occasional shows of coal from 2300 to 3000. STUCK PIPE! S-18i3 5855 (3244 3384-- UG41K15 had to sidetrack around BHA fish. A 3456 CAUSE: LACK OF HOLE CLEANINGM! UGNU: to Gas Cut Mud at 3700 tvd: B Thick hydrocarbon column —200 to 300 ft thick in some S-30i and 20i (both minor). = tC areas. The Ugnu section (interbedded fluvial sandstone and shale) `+ w3 represents the initial progradation of the Ugnu deltaic system over D � the underlying shallow marine Schrader Bluff section. Fluvial nature can snake it difficult to determine top and base of individual units. TIGHT HOLE IN MO N O B O RE S. Bottom bounding surface of the entire Ugnu package is picked at the S-21 i, S-25, S-23, S-05, S-03 and A regional unconformity M70S (see the M-sands below). 5.25 CIRCULATE THOROUGHLY s` 3 6 UP M-sands: Fluvial, deltaic channel sandstones prograded over ORE. OR MORE. USE PWDIECD'S FOR ORUSE PW 'S FOR the underlying shallow marine sandstones of the Schrader Bluff. The MONITORING HOLE CLEANING. B M-Sands are subdivided into three lithostratignaphic units (Ma. Mb, 3870'• Me from top to bottom) that can be difficult to correlate due to their Of fluvial nature. The M70S marks the boundary at the base Of the MC- DIFFERENTIAL STICKING! A 4120' sand. M-sand intervals are typically coarsening upward of 5-10A, OB sand, Treated with sized Ca[ tIl varying thicknesses, ranging from 50,8011tick. All zones are hlgllty unconsolidated sandstones with porosities range in the 3039%and B permeabilities reaching upwards of 2000-5000 md. Each M-sand t0 interval acts as a hydraulically separate reservoir based on current C U) understanding. 3890'- Page 46 J ff Hilcorp E-syC-P.By 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Milne Point Unit S-201 Ugnu Producer Drilling Procedure Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates have been seen on E Pad. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non - pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 47 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 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. Page 48 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 112S. No 112S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 112S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure has not been seen on Ugnu wells on S-Pad Anti -Collision S-22 is <1.0 clearance factor, it is an abandoned ugnu producer that has a fully cemented lateral. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Page 49 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 26.0 Innovation Rig Layout Page 50 Hilcorp Energy Company 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit S-201 Ugnu Producer Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1 /4 to 1 /2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 51 Milne Point Unit S-201 Ugnu Producer Hilco+Tf�1 Drilling Procedure E—gy Company 28.0 Innovation Rig Choke Manifold Schematic Page 52 29.0 Casing Design Milne Point Unit S-201 Ugnu Producer Drilling Procedure 11 Calculation & Casing Design Factors Hillcorp DATE: 10/17/2019 WELL: MPU S-201 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Drilling Mode MASP: MASP: Production Mode MASP: Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: 1307 psi (see attached MASP determination & calculation) 1307 psi (see attached MASP determination & calcu Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 4-1/2" Top (MD) 0 6,245 Top (TVD) 0 3,846 Bottom (MD) 6,245 11,658 Bottom (TVD) 3,846 3,626 Length 6,245 5,413 Weight (ppf) 40 13.5 Grade L-80 L-80 Connection TXP H625 Weight w/o Bouyancy Factor (Ibs) 249,800 73,076 Tension at Top of Section (Ibs) 249,800 73,076 Min strength Tension (1000 Ibs) 916 279 Worst Case Safety Factor (Tension) 3.67 3.82 Collapse Pressure at bottom (Psi) 1,900 1,791 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.63 4.77 MASP (psi) 1,307 1,307 Minimum Yield (psi) 5,750 9,020 Worst case safety factor (Burst) 4.40 6.90 Page 53 I/ Milne Point Unit S-201 Ugnu Producer Drilling Procedure 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hill 8-1/2" Hole Section ` c.P.R' MPU S-201 Milne Point Unit MD TVD Planned Top: 6245 3846 Planned TD: 11658 3564 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Ugn u M B 3,846 1679 1 Oil 8.40 0.440 Offset Well Mud Densities Well MW ranee Top (TVD) Bottom (TVD) Date MPU S-22 9.0-9.5 2412 3733 1 2003 MPU S-203 9-9.2 3815 3626 +�19 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,846 (ft) x 0. 78(psi/ft) = 3000 3000(psi) - [0.1(psi/ft)*3846(ft)]= 2615 psi MASP from pore pressure (complete evacuation of wellbore to gas om Schrader Bluff OA sand) 3846 (ft) x 0.44(psi/ft)= 1692 psi 1692(psi) - 0.1(psi/ft)*3846(ft) 1307 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 54 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 31.0 Spider Plot (NAD 27) (Governmental Sections) Sec. 33 r Sec: 34• ADL025S06 < •,.U013N010E �� Sec 3F ADL025518 Sea 36 i ow i 1 x FAC,+ 5-,461 x 1 ♦ 4 ::-JS • StELS It L !N• s-3w8f -0 V � ` ♦ • /` Ir +�• h.i1 ' I( r`♦ �S.c. ♦`�� a h{�eR3' jYi =. to . 1 I r , , It r r`'T H-ces 1 1 Sec.6 1 KLY3 $eC. 2- t t r E ` 1. 1 { s"� rr &:v=_: •s�_, \ s-13s5 o-16 a Y • .f .xts �y HXBA 1 s.z Pet x If i + �r 1Sec. 3 Mltt�E`i QINT r h,7 —gl ADL3 Q109 �" 1T \ ate— ADL-380110} ADL025627 IV F '�, _ �,•-'� l 1 Ji ti ♦ ! 1 S'`-a. it `' ♦ \i}•1- e-_l.� �;{:_, i + • a 5.33+5S S3f�, ,..� 1 H.C'� 1 + •'S33A15 t,. �I Sec. 1C See. 11 ,.3.1 _ - - Seed,- ,1 • i ��/� i ' U012NO11E c3 U012NO10E ;•I i } i J l� Ica ail ,- as f4S 35 + T9PU $-201 BHL r ,1 zees i{Pt S-21 TP}{ •006000000000 =OCDQ�CPCODODOOOOQf S423 .. 5' toeri I• KUPARUK RIVER UNIT Fe:.G Sec. 15 Sec. 14 I Z9L025636 ADL 5637 ADL047446 Legend PRUDHOE BAY UNIT • MPU S-20t_SHL Other Bottom Holes }EHLj t+ X MPU S-201 TPH - - - Other Well Paths � Oil and Gas Unit Bc _ ^ ae -, t MPU S-20t_BHL _ Sac.22 Its Sec.23 $e 24 Sec.;19 ISo,,, Milne Point Unit ry MPS-201 Well a 1.aoo 2,000 s.c>oa wooam 1911,2015 wpO6 Feet Page 55 Milne Point Unit S-201 Ugnu Producer Drilling Procedure 32.0 Surface Plat (As Built) (NAD 27) Below is the as -staked location. Once the asbuilt is received it will be sent out. i IPLANT E-P I s3-201 I — Z- 4 I "� L150000' C I za ItPID 25 - 30 _ {S-205 ' I 2I m 202 I —I - _ I _ ®J I � I 33♦4 NI -PAD J5 38 3f I I I �311 I T12N I I 2R I " 2 1 tT 1 5 1 i I 5 I 11I!8 jWr_ - - i 2s22 I _R _ ' I in I t1 1 12 �� 7 1 5 ,sI I 17 I � iy VICINITY ASAP N.T.S. I Ia 12 a �1 I I-SEC�Nz S I . I 71 I LEGEND _ 7 AS-STAKEID CONDUCTOR _ EXISTING CONDUCTOR I 81 I r -1 n^ s�I I I I�L J I N I L J I u I Ej = I NOTES! J I 1. DATE OF SURVEY. OCTOSM 4, 2019 / I 2- REFERENCE FIELD BOOK, 14CI9-04 PG& 20-22. HORIZONTAL DATUM IS MAW STATE KANE. ZONE 4, RA027. "- — — — — — — — — — — 4, GEODETIC POSITIONS ARE NADZT, X / 5. PAD MEAN SCALE FACTOR ISI 0.99990192 GRAPHIC SCALE & HORIZONTAL AND VERTTCK CONTROL 6 RASED ON MP S PAD "AMR MONAIMENTS S-EAST, S-MID, AND S-WEST. 0 160 320 7_ 8"ATIONS ARE YUIE PUNT MEAN SEA U V0_ (IN FEET) 1 inch . 140 R. LOCATED VAMN PROTRACTED SEC_ 12_ T_ 12 N._ R_ 10 E__ UMIAT MERIDIAN- AK- WELL A.S.P. PLANT GEODETIC GEODETIC GRAVEL SECTION NO, COORDINATES COORDINATES POSITIGN(OMS) POSITIO14(0.00) PAD ELEV. OFFSETS S-201 Y=5,999,877.25' N=2,237.12' 70'24-36,415" 70.4101154' 368' 3,213' FSL x- 565 450.45" E- 6 310,55' 14928'01,418" 149,4670605' . 561' FEL S-202 Y-5,999,900.83' N-2,237.33 70'24'36.640' 70.4101777' 36,7' 3,236:F5L X= 565,537,67 E= 6 400.90' 14927'58.855' 149.4663487 473FEL S-205 Y-5,999,884.81' N-2,236.97' 702436,487' 70.4101353' 36.9' 3,220'f5l X= 565,479.26' E= 6,340.33' 149-28'00.572` 149.4668256' SV EEL HUcorp Alaska MPU S PAD mar AS -STAKED CONDUCTORS { WELLS S-201, 202, 205 1 v 1 Page 56 H i lcorp Alaska, LLC Milne Point M Pt S Pad Plan: MPU S-201 MPU S-201 Plan: MPU S-201 wp06 Standard Proposal Report 10 October, 2019 HALLIBURTON Sperry Drilling Services it I S-201 wp06 SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 31/100' : 350' M 3 550.00 6.00 150.00 549.63 -9.06 5.23 3.00 150.00 -5.23 Start Dir 41/100' : 550' M 4 1575.00 47.00 150.00 1447.50-396.74 229.06 4.00 0.00 -229.06 End Dir : 1575' MD, 144 5 1650.00 47.00 150.00 1498.65-444.25 256.49 0.00 0.00 -256.49 Start Dir 41/100' : 1650' t 6 2048.65 52.91 130.59 1756.45-675.43 451.38 4.00 -74.80 -451.38 End Dir : 2048.65' MD, 7 2803.61 52.91 130.59 2211.75-1067.26 908.71 0.00 0.00 -908.71 Start Dir 41/100' : 2803.6 8 6095.59 95.00 271.00 3859.10-2668.95-337.47 4.00 121.79 337.47 End Dir : 6095.59' MD, : 9 6245.59 95.00 271.00 3846.03-2666.34-486.88 0.00 0.00 486.88 MPS-201 wp06 Heel Start Dir 41/100' : 6245.5 10 6285.11 96.40 270.27 3842.10-2665.90-526.20 4.00 -27.45 526.20 End Dir : 6285.11' MD, : 11 7110.03 96.40 270.27 3750.11-2662.09-1345.97 0.00 0.00 1345.97 Start Dir 4°/100' : 7110.0 12 7208.79 92.50 270.88 3742.45-2661.10-1444.40 4.00 171.07 1444.40 End Dir : 7208.79' MD, : 13 7808.79 92.50 270.88 3716.28-2651.90-2043.76 0.00 0.00 2043.76 MPS-201 wp06 CP1 Start Dir 41/100' : 7808.7 14 7830.11 92.41 270.03 3715.37-2651.73-2065.06 4.00 -96.08 2065.06 End Dir : 7830.11' MD, : 15 9809.82 92.41 270.03 3632.14-2650.65-4043.03 0.00 0.00 4043.03 MPS-201 wp06 CP2 Start Dir 31/100' : 9809.8 16 9822.54 92.03 270.04 3631.65-2650.64-4055.73 3.00 179.32 4055.73 End Dir : 9822.54' MD, : 17 10906.49 92.03 270.04 3593.29-2649.96-5139.01 0.00 0.00 5139.01 MPS-201 wp06 CP3 Start Dir 3*/100' : 10906. 18 10919.02 92.18 269.69 3592.83-2649.99-5151.52 3.00 -66.77 5151.52 End Dir : 10919.02' MD, 19 11658.53 92.18 269.69 3564.75-2653.99-5890.49 0.00 0.00 5890.49 MPS-201 wp06 toe Total Depth : 11658.53' r SURVEY PROGRAM ated: Yes Version: Tool 306 (MPU S-201) 2_Gyro-NS-GC_Drill collar 106 (MPU S-201) 2_MWD+IFR2+MS+Sag �06 MPU S-201 2 MWD+I R2+MS+Sa Hilcorp Alaska, LLC Method: Minimum Curvature System: ISCWSA Method: Closest Approach 3D Surface: Pedal Curve Method: Error Ratio REFERENCE INFORMATION CASING DET Co-ordinate (N/E) Reference: Well Plan: MPU S-201, True North TVD TVDSS MD Vertical (TVD) Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MPU S-201 wp05 Prelim RKB @ 64.70usft 3846.03 3781.33 6245.59 Measured Depth Reference: 3564.75 3500.05 11658.53 Calculation Method: Minimum Curvature Start Dir 3'/100' : 350' MD, 350'TVD Start Dir 40/100' : 550' MD, 549.637VD 1000 End Dir : 1575' MD, 1447.5' TVD Start Dir 4°/100' : 1650' MD, 1498.65'TVD _ _ _ End Dir : 2048.65' MD, 1756.45' TVD L----- WELL DETAILS: Plan: MPU S-201 38.20 +N/-S +E/-W Northing Easting Latittude 0.00 0.00 5999877.25 565450.45 70' 24' 36.415 N O ,O ,ro O pro h P N na O 0' Aj '� rb FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3589.70 3525.00 4862.40 MP UG LC2 3680.70 3616.00 5061.26 MP UG_LC1 3698.70 3634.00 5105.42 MP UG_LD.1 3755.70 3691.00 5262.20 MP_UG_LEA 3774.70 3710.00 5322-65 MP UG LD.2 3774.70 3710.00 5322.65 MP UG MA.1 3774.70 3710.00 5322.65 MP UG MA.2 3776.70 3712.00 5329.35 MP UG LE.2 3791.70 3727.00 5382.04 MP UG_LD.3 3796.70 3732.00 5400.72 MP-UG-MC 3797.09 3732.39 5402.20 MP UG_MC.1 3827.70 3763.00 5535.11 MP UG_LE.3 3847.70 once �n 3783.00 ��c� nn 5654.02 ccoe co MP UG MA.3 ..o nr ..o 0�0 O O �a row M °^� �O Cb �O rOrh h° ` O' °ry 3500 ` oD �� ^`S °' om`"' ^ryo° moo° oti o° �� ti o 4000 O ono a a rb ` ` y �p c0 D.2 _ _ - _ �° _ - .a - _ _ _ �+ - _ _ - - _ _ _ - _ r ` - - _ - - - - LE.2 - - _ o _-- _ � _ -0T �� U' _- .G_LE.3 JG_MC.1 9 5/81, x 12 1/4" MC MPS-201 wp06 Heel MPS-201 wp06 CP1 MPS-201 wp06 CP2 �O 0, °0. 4 a o� ro r � a OmQ r r - MPS-201 wp06 CP3 MPS-20 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 600C Vertical Section at 270.00' (1000 usft/in) WELL DETAU.S: Plan: N TU S-201 Project: Milne Point H 38.20 Site: M Pt S Pad +N/-S +E/-W Northing Easting latittude Longitude Well: Plan: MPU S-201 Sr 0.00 0.00 5999877.25 565450.45 70' 24'36.415 N 149' 28' 1.418 W Wellbore: MPU S-201 EM Plan: MPU S-201 wp06 CASING DETAILS REFERENCE INFORMATIOP TVD TVDSS MD Size Name Co-ordinate (N/E) Reference: Well Plan: MPU S-201, 3846.03 3781.33 6245.59 9-5/8 9 5/8" x 12 1/4" Vertical (TVD) Reference: MPU 5-201 wp05 Prelin 3564.75 3500.05 11658.53 6-5/8 6 5/8" x 8 1/2" Measured Depth Reference: MPU S-201 wp05 Prelin Calculation Method: Minimum Curvature Stet Dir 31/100' : 350' MD, 350'TVD- - - - - -7 Start Dir 4o/100' : 550' MD, 549.63'TVD \� End Dir : 1575' iM, 1447.5' TVD 0 Start Dir 4°/I00' : 1650' MD, 1498.65'TVD End Dir : 2048.65' MD, 1756.45' TVD Start Dir 4°/100' : 2803.61' NO, 2211.75'TVD toe 8 1/2" MPS-201 wp06 CP3 MPS-201 wp06 CP2 MPS-201 wp06 CPI i MPS-201 wp06 Heel ` ` 9 5/8" x 12 1/4" � A o N O 00, .T .0�, O o �!'A j �`JCAJ O 500 -5000 -4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 I -500 0 West( -)/East(+) (750 usft/in) 0 Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU 5-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt S Pad Site Position: Northing: 5,999,978.00usft Latitude: 70° 24' 37.329 N From: Map Easting: 566,345.00usft Longitude: 149° 27' 35.171 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.51 ° Well Plan: MPU S-201 Well Position +N/-S 0.00 usft Northing: +E/-W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore MPU 5-201 5,999,877.25 usft Latitude: 565,450.45 usft Longitude: usft Ground Level: 70° 24' 36.415 N 149° 28' 1.418 W 38.20 usft Magnetics Model Name Sample Date Declination Dip Angle Field Strength (I V) (nT) BGGM2018 11 /23/2019 16.40 80.91 57,405.46690173 Design MPU S-201 wp06 Audit Notes: Jet Pump Producer Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 270.00 1011012019 1:42:21PM Page 2 COMPASS 5000.15 Build 91 Halliburton HALLI BU RTO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU S-201 Company: Hilcorp Alaska, LLC TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft Project: Milne Point MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft Site: M Pt S Pad North Reference: True Well: Plan: MPU S-201 Survey Calculation Method: Minimum Curvature Wellbore: MPU S-201 Design: MPU S-201 wp06 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 26.50 0.00 0.00 26.50 -38.20 0.00 0.00 0.00 0.00 0.00 0.00 350.00 0.00 0.00 350.00 285.30 0.00 0.00 0.00 0.00 0.00 0.00 550.00 6.00 150.00 549.63 484.93 -9.06 5.23 3.00 3.00 0.00 150.00 1,575.00 47.00 150.00 1,447.50 1,382.80 -396.74 229.06 4.00 4.00 0.00 0.00 1,650.00 47.00 150.00 1,498.65 1,433.95 -444.25 256.49 0.00 0.00 0.00 0.00 2,048.65 52.91 130.59 1,756.45 1,691.75 -675.43 451.38 4.00 1.48 -4.87 -74.80 2,803.61 52.91 130.59 2,211.75 2,147.05 -1,067.26 908.71 0.00 0.00 0.00 0.00 6,095.59 95.00 271.00 3,859.10 3,794.40 -2,668.95 -337.47 4.00 1.28 4.27 121.79 6,245.59 95.00 271.00 3,846.03 3,781.33 -2,666.34 -486.88 0.00 0.00 0.00 0.00 6,285.11 96.40 270.27 3,842.10 3,777.40 -2,665.90 -526.20 4.00 3.55 -1.86 -27.45 7,110.03 96.40 270.27 3,750.11 3,685.41 -2,662.09 -1,345.97 0.00 0.00 0.00 0.00 7,208.79 92.50 270.88 3,742.45 3,677.75 -2,661.10 -1,444.40 4.00 -3.95 0.62 171.07 7,808.79 92.50 270.88 3,716.28 3,651.58 -2,651.90 -2,043.76 0.00 0.00 0.00 0.00 7,830.11 92.41 270.03 3,715.37 3,650.67 -2,651.73 -2,065.06 4.00 -0.42 -3.98 -96.08 9,809.82 92.41 270.03 3,632.14 3,567.44 -2,650.65 -4,043.03 0.00 0.00 0.00 0.00 9,822.54 92.03 270.04 3,631.65 3,566.95 -2,650.64 -4,055.73 3.00 -3.00 0.04 179.32 10,906.49 92.03 270.04 3,593.29 3,528.59 -2,649.96 -5,139.01 0.00 0.00 0.00 0.00 10,919.02 92.18 269.69 3,592,83 3,528.13 -2,649.99 -5,151.52 3.00 1.18 -2.76 -66.77 11,658.53 92.18 269.69 3,564.75 3,500.05 -2,653.99 -5,890.49 0.00 0.00 0.00 0.00 1011012019 1:42:21PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Planned Survey Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (1) (usft) usft 26.50 0.00 0.00 26.50 -38.2C 100.00 0.00 0.00 100.00 35.30 200.00 0.00 0.00 200.00 135.3C 300.00 0.00 0.00 300.00 235.30 350.00 0.00 0.00 350.00 285.3C Start Dir 30/100' : 350' MD, 350'TVD 400.00 1.50 150.00 399.99 335.29 500.00 4.50 150.00 499.85 435.15 550.00 6.00 150.00 549.63 484.93 Start Dir 4°/100' : 550' MD, 549.63'TVD 600.00 8.00 150.00 599.26 534.56 700.00 12.00 150.00 697.72 633.02 800.00 16.00 150.00 794.73 730.03 900.00 20.00 150.00 889.82 825.12 1,000.00 24.00 150.00 982.52 917.82 1,100.00 28.00 150.00 1,072.38 1,007.68 1,200.00 32.00 150.00 1,158.96 1,094.26 1,300.00 36.00 150.00 1,241.85 1,177.15 1,400.00 40.00 150.00 1,320.63 1,255.93 1,500.00 44.00 150.00 1,394.93 1,330.23 1,575.00 47.00 150.00 1,447.50 1,382.80 End Dir : 1575' MD, 1447.5' TVD 1,600.00 47.00 150.00 1,464.55 1,399.85 1,650.00 47.00 150.00 1,498.65 1,433.95 Start Dir 4*/100' : 1650' MD, 1498.65'TVD 1,700.00 47.55 147.38 1,532.57 1,467.87 1,800.00 48.84 142.30 1,599.25 1,534.55 1,900.00 50.33 137.43 1,664.11 1,599.41 2,000.00 52.02 132.77 1,726.82 1,662.12 2,048.65 52.91 130.59 1,756.46 1,691.76 End Dir : 2048.65' MD, 1756.45' ND 2,100.00 52.91 130.59 1,787.42 1,722.72 2,200.00 52.91 130.59 1,847.73 1,783.03 2,300.00 52.91 130.59 1,908.04 1,843.34 2,400.00 52.91 130.59 1,968.34 1,903.64 2,500.00 52.91 130.59 2,028.65 1,963.95 2,600.00 52.91 130.59 2,088.96 2,024.26 2,700.00 52.91 130.59 2,149.26 2,084.56 2,803.61 52.91 130.59 2,211.75 2,147.05 Start Dir 4°/100' : 2803.61' MD, 2211.75'TVD 2,900.00 50.95 134.81 2,271.20 2,206.50 3,000.00 49.09 139.43 2,335.46 2,270.76 3,100.00 47.43 144.31 2,402.06 2,337.36 3,200.00 45.98 149.43 2,470.66 2,405.96 3,300.00 44.77 154.79 2,540.93 2,476.23 Map Map +N/-S +E/-W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -38.20 0.00 0.00 5,999,877.25 565,450.45 0.00 0.00 0.00 0.00 5,999,877.25 565,450.45 0.00 0.00 0.00 0.00 5,999,877.25 565,450.45 0.00 0.00 0.00 0.00 5,999,877.25 565,450.45 0.00 0.00 0.00 0.00 5,999,877.25 565,450.45 0.00 0.00 -0.57 0.33 5,999,876.69 565,450.78 3.00 -0.33 -5.10 2.94 5,999,872.18 565,453.44 3.00 -2.94 -9.06 5.23 5,999,868.24 565,455.76 3.00 -5.23 -14.34 8.28 5,999,862.99 565,458.85 4.00 -8.28 -29.37 16.96 5,999,848.03 565,467.66 4.00 -16.96 -50.32 29.05 5,999,827.19 565,479.94 4.00 -29.05 -77.08 44.50 5,999,800.57 565,495.62 4.00 -44.50 -109.51 63.23 5,999,768.31 565,514.63 4.00 -63.23 -147.47 85.14 5,999,730.55 565,536.87 4.00 -85.14 -190.76 110.14 5,999,687.48 565,562.24 4.00 -110.14 -239.18 138.09 5,999,639.31 565,590.62 4.00 -138.09 -292.48 168.87 5,999,586.28 565,621.86 4.00 -168.87 -350.42 202.32 5,999,528.65 565,655.81 4.00 -202.32 -396.74 229.06 5,999,482.57 565,682.96 4.00 -229.06 -412.58 238.20 5,999,466.81 565,692.23 0.00 -238.20 -444.25 256.49 5,999,435.31 565,710.79 0.00 -256.49 -475.62 275.57 5,999,404.11 565,730.15 4.00 -275.57 -536.51 318.50 5,999,343.61 565,773.60 4.00 -318.50 -594.66 367.57 5,999,285.89 565,823.19 4.00 -367.57 -649.79 422.57 5,999,231.25 565,878.65 4.00 -422.57 -675.44 451.38 5,999,205.86 565,907.69 4.00 -451.38 -702.09 482.49 5,999,179.49 565,939.02 0.00 -482.49 -753.99 543.06 5,999,128.12 566,000.05 0.00 -543.06 -805.88 603.64 5,999,076.76 566,061.07 0.00 -603.64 -857.78 664.22 5,999,025.40 566,122.09 0.00 -664.22 -909.68 724.79 5,998,974.04 566,183.12 0.00 -724.79 -961.58 785.37 5,998,922.68 566,244.14 0.00 -785.37 -1,013.48 845.95 5,998,871.32 566,305.16 0.00 -845.95 -1,067.26 908.71 5,998,818.10 566,368.39 0.00 -908.71 -1,118.67 964.48 5,998,767.18 566,424.60 4.00 -964.48 -1,016.63 -1,062.71 -1,102.49 -1,135.79 1011012019 1:42:21PM Page 4 COMPASS 5000.15 Build 91 Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 2,547.83 3,400.00 43.82 160.35 2,612.53 2,547.83 -1,421.61 1,162.44 5,998,466.02 566,625.19 4.00 -1,162.44 3,500.00 43.15 166.09 2,685.11 2,620.41 -1,487.44 1,182.31 5,998,400.37 566,645.64 4.00 -1,182.31 3,600.00 42.78 171.93 2,758.32 2,693.62 -1,554.28 1,195.31 5,998,333.65 566,659.21 4.00 -1,195.31 3,700.00 42.70 177.83 2,831.80 2,767.10 -1,621.81 1,201.36 5,998,266.19 566,665.86 4.00 -1,201.36 3,800.00 42.92 183.70 2,905.18 2,840.48 -1,689.70 1,200.45 5,998,198.30 566,665.54 4.00 -1,200.45 3,900.00 43.45 189.50 2,978.13 2,913.43 -1,757.62 1,192.57 5,998,130.32 566,658.26 4.00 -1,192.57 4,000.00 44.26 195.16 3,050.27 2,985.57 -1,825.24 1,177.77 5,998,062.57 566,644.05 4.00 -1,177.77 4,100.00 45.33 200.62 3,121.26 3,056.56 -1,892.23 1,156.11 5,997,995.41 566,622.99 4.00 -1,156.11 4,200.00 46.66 205.87 3,190.75 3,126.05 -1,958.26 1,127.70 5,997,929.13 566,595.16 4.00 -1,127.70 4,300.00 48.22 210.87 3,258.40 3,193.70 -2,023.01 1,092.69 5,997,864.08 566,560.72 4.00 -1,092.69 4,400.00 49.99 215.62 3,323.89 3,259.19 -2,086.17 1,051.24 5,997,800.57 566,519.83 4.00 -1,051.24 4,500.00 51.94 220.12 3,386.89 3,322.19 -2,147.43 1,003.55 5,997,738.90 566,472.68 4.00 -1,003.55 4,600.00 54.05 224.38 3,447.10 3,382.40 -2,206.48 949.85 5,997,679.38 566,419.51 4.00 -949.85 4,700.00 56.30 228.40 3,504.22 3,439.52 -2,263.05 890.41 5,997,622.30 566,360.57 4.00 -890.41 4,800.00 58.68 232.22 3,557.98 3,493.28 -2,316.86 825.52 5,997,567.94 566,296.16 4.00 -825.52 4,862.40 60.21 234.50 3,589.70 3,525.00 -2,348.91 782.40 5,997,535.51 566,253.33 4.00 -782.40 MP_UG_LC2 4,900.00 61.16 235.84 3,608.11 3,543.41 -2,367.63 755.49 5,997,516.55 566,226.58 4.00 -755.49 5,000.00 63.74 239.30 3,654.37 3,589.67 -2,415.14 680.66 5,997,468.40 566,152.18 4.00 -680.66 5,061.26 65.35 241.33 3,680.70 3,616.00 -2,442.52 632.61 5,997,440.60 566,104.38 4.00 -632.61 MP_UG_LC1 5,100.00 66.39 242.60 3,696.54 3,631.84 -2,459.14 601.40 5,997,423.71 566,073.32 4.00 -601.40 5,105.42 66.54 242.77 3,698.70 3,634.00 -2,461.42 596.99 5,997,421.39 566,068.93 4.00 -596.99 MP_UG_LD.1 5,200.00 69.11 245.76 3,734.40 3,669.70 -2,499.42 518.10 5,997,382.70 565,990.38 4.00 -518.10 5,262.20 70.84 247.67 3,755.70 3,691.00 -2,522.51 464.42 5,997,359.14 565,936.91 4.00 -464.42 MP_UG_LE.1 5,300.00 71.89 248.82 3,767.78 3,703.08 -2,535.79 431.15 5,997,345.58 565,903.76 4.00 -431.15 5,322.65 72.53 249.49 3,774.70 3,710.00 -2,543.46 411.00 5,997,337.73 565,883.68 4.00 -411.00 MP_UG_MA.1 - MP_UG_LD.2 - MP_UG_MA.2 5,329.35 72.72 249.69 3,776.70 3,712.00 -2,545.69 405.01 5,997,335.45 565,877.71 4.00 -405.01 MP_UG_LE.2 5,382.04 74.21 251.25 3,791.70 3,727.00 -2,562.58 357.40 5,997,318.15 565,830.26 4.00 -357.40 MP_UG_LD.3 5,400.00 74.72 251.77 3,796.51 3,731.81 -2,568.06 340.99 5,997,312.52 565,813.90 4.00 -340.99 5,400.72 74.74 251.79 3,796.70 3,732.00 -2,568.28 340.33 5,997,312.30 565,813.24 4.00 -340.33 MP_UG_MC 5,402.20 74.78 251.84 3,797.09 3,732.39 -2,568.73 338.97 5,997,311.84 565,811.88 4.00 -338.97 IMP _UG_MCA 5,500.00 77.58 254.65 3,820.45 3,755.75 -2,596.09 248.05 5,997,283.68 565,721.22 4.00 -248.05 5,535.11 78.59 255.64 3,827.70 3,763.00 -2,604.89 214.85 5,997,274.59 565,688.10 4.00 -214.85 MP UG LE.3 5,600.00 80.47 257.46 3,839.49 3,774.79 -2,619.72 152.79 5,997,259.21 565,626.18 4.00 -152.79 5,654.02 82.04 258.96 3,847.70 3,783.00 -2,630.63 100.52 5,997,247.85 565,574.01 4.00 -100.52 MP_UG_MA.3 1011012019 1:42:21PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (°) (°) (usft) Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature TVDss +N/-S usft (usft) 5,684.63 82.94 259.81 3,851.70 3,787.00 -2,636.22 MP_UG_MB 5,700.00 83.39 260.23 3,853.53 3,788.83 -2,638.86 5,800.00 86.32 262.97 3,862.50 3,797.80 -2,653.40 5,900.00 89.25 265.68 3,866.37 3,801.67 -2,663.28 6,000.00 92.19 268.40 3,865.10 3,800.40 -2,668.44 6,095.59 95.00 271.00 3,859.10 3,794.40 -2,668.95 End Dir : 6095.59' MD, 3859.1' TVD 6,100.00 95.00 271.00 3,858.72 3,794.02 -2,668.87 6,200.00 95.00 271.00 3,850.00 3,785.30 -2,667.13 6,245.59 95.00 271.00 3,846.03 3,781.33 -2,666.34 Start Dir 4°/100' : 6245.59' MD, 3846.03'TVD - 9 5/8" x 12 1/4" 6,285.11 96.40 270.27 3,842.10 3,777.40 -2,665.90 End Dir : 6285.11' MD, 3842.1 TVD 6,300.00 96.40 270.27 3,840.44 3,775.74 -2,665.84 6,400.00 96.40 270.27 3,829.29 3,764.59 -2,665.37 6,500.00 96.40 270.27 3,818.14 3,753.44 -2,664.91 6,600.00 96.40 270.27 3,806.99 3,742.29 -2,664.45 6,700.00 96.40 270.27 3,795.84 3,731.14 -2,663.99 6,800.00 96.40 270.27 3,784.69 3,719.99 -2,663.52 6,900.00 96.40 270.27 3,773.54 3,708.84 -2,663.06 7,000.00 96.40 270.27 3,762.38 3,697.68 -2,662.60 7,100.00 96.40 270.27 3,751.23 3,686.53 -2,662.13 7,110.03 96.40 270.27 3,750.11 3,685.41 -2,662.09 Start Dir 41/100' : 7110.03' MD, 3750.11'TVD 7,208.79 92.50 270.88 3,742.45 3,677.75 -2,661.10 End Dir : 7208.79' MD, 3742.45' TVD 7,300.00 92.50 270.88 3,738.47 3,673.77 -2,659.70 7,400.00 92.50 270.88 3,734.11 3,669.41 -2,658.17 7,500.00 92.50 270.88 3,729.75 3,665.05 -2,656.63 7,600.00 92.50 270.88 3,725.39 3,660.69 -2,655.10 7,700.00 92.50 270.88 3,721.03 3,656.33 -2,653.57 7,808.79 92.50 270.88 3,716.28 3,651.58 -2,651.90 Start Dir 411100' : 7808.79' MD, 3716.28'TVD 7,830.11 92.41 270.03 3,715.37 3,650.67 -2,651.73 End Dir : 7830.11' MD, 3715.37' TVD 7,900.00 92.41 270.03 3,712.43 3,647.73 -2,651.69 8,000.00 92.41 270.03 3,708.22 3,643.52 -2,651.63 8,100.00 92.41 270.03 3,704.02 3,639.32 -2,651.58 8,200.00 92.41 270.03 3,699.82 3,635.12 -2,651.52 8,300.00 92.41 270.03 3,695.61 3,630.91 -2,651.47 8,400.00 92.41 270.03 3,691.41 3,626.71 -2,651.42 8,500.00 92.41 270.03 3,687.20 3,622.50 -2,651.36 8,600.00 92.41 270.03 3,683.00 3,618.30 -2,651.31 8,700.00 92.41 270.03 3,678.80 3,614.10 -2,651.25 Map Map +E/-W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,787.00 70.70 5,997,242.00 565,544.24 4.00 -70.70 55.67 5,997,239.23 565,529.24 4.00 -55.67 -42.84 5,997,223.83 565,430.87 4.00 42.84 -142.25 5,997,213.08 565,331.55 4.00 142.25 -242.09 5,997,207.04 565,231.77 4.00 242.09 -337.47 5,997,205.70 565,136.41 4.00 337.47 -341.87 5,997,205.74 565,132.01 0.00 341.87 -441.47 5,997,206.61 565,032.41 0.00 441.47 -486.88 5,997,207.00 564,987.00 0.00 486.88 -526.20 5,997,207.09 564,947.68 4.00 526.20 -541.00 5,997,207.03 564,932.88 0.00 541.00 -640.37 5,997,206.62 564,833.52 0.00 640.37 -739.75 5,997,206.21 564,734.15 0.00 739.75 -839.12 5,997,205.81 564,634.78 0.00 839.12 -938.50 5,997,205.40 564,535.42 0.00 938.50 -1,037.87 5,997,204.99 564,436.05 0.00 1,037.87 -1,137.25 5,997,204.58 564,336.69 0.00 1,137.25 -1,236.62 5,997,204.17 564,237.32 0.00 1,236.62 -1,336.00 5,997,203.76 564,137.95 0.00 1,336.00 -1,345.97 5,997,203.72 564,127.99 0.00 1,345.97 -1,444.41 5,997,203.85 564,029.56 4.00 1,444.41 -1,535.52 5,997,204.45 563,938.44 0.00 1,535.52 -1,635.41 5,997,205.11 563,838.55 0.00 1,635.41 -1,735.30 5,997,205.77 563,738.66 0.00 1,735.30 -1,835.20 5,997,206.42 563,638.76 0.00 1,835.20 -1,935.09 5,997,207.08 563,538.87 0.00 1,935.09 -2,043.76 5,997,207.80 563,430.20 0.00 2,043.76 -2,065.06 5,997,207.78 563,408.90 4.00 2,065.06 -2,134.89 5,997,207.21 563,339.08 0.00 2,134.89 -2,234.80 5,997,206.39 563,239.18 0.00 2,234.80 -2,334.71 5,997,205.57 563,139.28 0.00 2,334.71 -2,434.63 5,997,204.75 563,039.38 0.00 2,434.63 -2,534.54 5,997,203.93 562,939.48 0.00 2,534.54 -2,634.45 5,997,203.10 562,839.59 0.00 2,634.45 -2,734.36 5,997,202.28 562,739.69 0.00 2,734.36 -2,834.27 5,997,201.46 562,639.79 0.00 2,834.27 -2,934.18 5,997,200.64 562,539.89 0.00 2,934.18 1011012019 1:42:21PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Planned Survey Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Depth Inclination Azimuth Depth TVDss +N/-S (usft) (1) (usft) usft (usft) 8,800.00 92.41 270.03 3,674.59 3,609.89 -2,651.2C 8,900.00 92.41 270.03 3,670.39 3,605.69 -2,651.14 9,000.00 92.41 270.03 3,666.18 3,601.48 -2,651.09 9,100.00 92.41 270.03 3,661.98 3,597.28 -2,651.03 9,200.00 92.41 270.03 3,657.78 3,593.08 -2,650.98 9,300.00 92.41 270.03 3,653.57 3,588.87 -2,650.93 9,400.00 92.41 270.03 3,649.37 3,584.67 -2,650.87 9,500.00 92.41 270.03 3,645.16 3,580.46 -2,650.82 9,600.00 92.41 270.03 3,640.96 3,576.26 -2,650.76 9,700.00 92.41 270.03 3,636.76 3,572.06 -2,650.71 9,809.82 92.41 270.03 3,632.14 3,567.44 -2,650.65 Start Dir 3*/100' : 9809.82' MD, 3632.14'TVD 9,822.54 92.03 270.04 3,631.65 3,566.95 -2,650.64 End Dir : 9822.54' MD, 3631.65' TVD 9,900.00 92.03 270.04 3,628.91 3,564.21 -2,650.59 10,000.00 92.03 270.04 3,625.37 3,560.67 -2,650.53 10,100.00 92.03 270.04 3,621.83 3,557.13 -2,650.47 10,200.00 92.03 270.04 3,618.29 3,553.59 -2,650.40 10,300.00 92.03 270.04 3,614.75 3,550.05 -2,650.34 10,400.00 92.03 270.04 3,611.21 3,546.51 -2,650.28 10,500.00 92.03 270.04 3,607.67 3,542.97 -2,650.22 10,600.00 92.03 270.04 3,604.14 3,539.44 -2,650.16 10,700.00 92.03 270.04 3,600.60 3,535.90 -2,650.09 10,800.00 92.03 270.04 3,597.06 3,532.36 -2,650.03 10,906.49 92.03 270.04 3,593.29 3,528.59 -2,649.96 Start Dir 3°/100' : 10906.49' MD, 3593.29'TVD 10,919.02 92.18 269.69 3,592.83 3,528.13 -2,649.99 End Dir : 10919.02' MD, 3592.83' TVD 11,000.00 92.18 269.69 3,589.76 3,525.06 -2,650.43 11,100.00 92.18 269.69 3,585.96 3,521.26 -2,650.97 11,200.00 92.18 269.69 3,582.16 3,517.46 -2,651.51 11,300.00 92.18 269.69 3,578.36 3,513.66 -2,652.05 11,400.00 92.18 269.69 3,574.57 3,509.87 -2,652.59 11,500.00 92.18 269.69 3,570.77 3,506.07 -2,653.13 11,600.00 92.18 269.69 3,566.97 3,502.27 -2,653.67 11,658.53 92.18 269.69 3,564.75 3,500.05 -2,653.99 Total Depth : 11658.53' MD, 3564.75' TVD - 6 5/8" x 8 1/2" Map Map +E/-W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,609.89 -3,034.10 5,997,199.82 562,439.99 0.00 3,034.10 -3,134.01 5,997,199.00 562,340.09 0.00 3,134.01 -3,233.92 5,997,198.18 562,240.19 0.00 3,233.92 -3,333.83 5,997,197.36 562,140.29 0.00 3,333.83 -3,433.74 5,997,196.54 562,040.40 0.00 3,433.74 -3,533.65 5,997,195.72 561,940.50 0.00 3,533.65 -3,633.56 5,997,194.89 561,840.60 0.00 3,633.56 -3,733.48 5,997,194.07 561,740.70 0.00 3,733.48 -3,833.39 5,997,193.25 561,640.80 0.00 3,833.39 -3,933.30 5,997,192.43 561,540.90 0.00 3,933.30 -4,043.02 5,997,191.53 561,431.19 0.00 4,043.02 -4,055.73 5,997,191.43 561,418.48 3.00 4,055.73 -4,133.14 5,997,190.80 561,341.08 0.00 4,133.14 -4,233.08 5,997,189.98 561,241.16 0.00 4,233.08 -4,333.02 5,997,189.17 561,141.23 0.00 4,333.02 -4,432.96 5,997,188.36 561,041.31 0.00 4,432.96 -4,532.89 5,997,187.54 560,941.38 0.00 4,532.89 -4,632.83 5,997,186.73 560,841.46 0.00 4,632.83 -4,732.77 5,997,185.92 560,741.54 0.00 4,732.77 -4,832.71 5,997,185.10 560,641.61 0.00 4,832.71 -4,932.64 5,997,184.29 560,541.69 0.00 4,932.64 -5,032.58 5,997,183.48 560,441.76 0.00 5,032.58 -5,139.00 5,997,182.61 560,335.35 0.00 5,139.00 -5,151.53 5,997,182.47 560,322.83 3.00 5,151.53 -5,232.45 5,997,181.32 560,241.93 0.00 5,232.45 -5,332.37 5,997,179.91 560,142.02 0.00 5,332.37 -5,432.30 5,997,178.49 560,042.11 0.00 5,432.30 -5,532.22 5,997,177.08 559,942.20 0.00 5,532.22 -5,632.15 5,997,175.66 559,842.29 0.00 5,632.15 -5,732.08 5,997,174.24 559,742.39 0.00 5,732.08 -5,832.00 5,997,172.83 559,642.48 0.00 5,832.00 -5,890.49 5,997,172.00 559,584.00 0.00 5,890.49 1011012019 1:42.21PM Page 7 COMPASS 5000.15 Build 91 Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Targets Target Name Local Co-ordinate Reference: Well Plan: MPU 5-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature - hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting - Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPS-201 wp06 CP2 0.00 0.00 3,632.14-2,650.65-4,043.03 5,997,191.53 561,431.19 plan hits target center Point MPS-201 wp06 CP1 0.00 plan hits target center Point MPS-201 wp06 Heel 0.00 plan hits tarqet center Circle (radius 50.00) MPS-201 wp06 toe 0.00 plan hits tarqet center Point MPS-201 wp06 CP3 0.00 plan hits tarqet center Point Casing Points Measured Vertical Depth Depth (usft) (usft) 6,245.59 3,846.03 9 5/8" x 12 1/4" 11,658.53 3,564.75 6 5/8" x 8 112" 0.00 3,716.28 -2,651.90 -2,043.76 5,997,207.80 563,430.20 0.00 3,846.03 -2,666.34 -486.88 5,997,207.00 564,987.00 0.00 3,564.75 -2,653.99 -5,890.49 5,997,172.00 559,584.00 0.00 3,593.29 -2,649.96 -5,139.01 5,997,182.61 560,335.35 Casing Hole Diameter Diameter Name (') (11) 9-5/8 12-1/4 6-5/8 8 Formations Measured Vertical Vertical Depth Depth Depth SS (usft) (usft) Name 5,400.72 3,796.70 MP_UG_MC 5,654.02 3,847.70 MP_UG_MA.3 5,061.26 3,680.70 MP_UG_LC1 5,535.11 3,827.70 MP_UG_LE.3 5,262.20 3,755.70 MP_UG_LEA 5,329.35 3,776.70 MP_UG_LE.2 5,105.42 3,698.70 MP_UG_LD.1 5,322.65 3,774.70 MP_UG_MA.2 5,322.65 3,774.70 MP_UG_LD.2 5,684.63 3,851.70 MP_UG_MB 5,382.04 3,791.70 MP_UG_LD.3 4,862.40 3,589.70 MP_UG_LC2 5,402.20 3,797.09 MP_UG_MCA 5,322.65 3,774.70 MP UG MA.1 Dip Dip Direction Lithology (°) (°) 1011012019 1:42:21PM Page 8 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-201 Wellbore: MPU S-201 Design: MPU S-201 wp06 Plan Annotations Local Co-ordinate Reference: Well Plan: MPU S-201 TVD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft MD Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 350.00 350.00 0.00 0.00 Start Dir 3'/100' : 350' MD, 350'TVD 550.00 549.63 -9.06 5.23 Start Dir 4'1100' : 550' MD, 549.63'TVD 1,575.00 1,447.50 -396.74 229.06 End Dir : 1575' MD, 1447.5' TVD 1,650.00 1,498.65 -444.25 256.49 Start Dir4°/100' : 1650' MD, 1498.65'TVD 2,048.65 1,756.46 -675.44 451.38 End Dir : 2048.65' MD, 1756.45' TVD 2,803.61 2,211.75 -1,067.26 908.71 Start Dir 4'/100' : 2803.61' MD, 2211.75'TVD 6,095.59 3,859.10 -2,668.95 -337.47 End Dir : 6095.59' MD, 3859.1' TVD 6,245.59 3,846.03 -2,666.34 -486.88 Start Dir 4'/100' : 6245.59' MD, 3846.03'TVD 6,285.11 3,842.10 -2,665.90 -526.20 End Dir : 6285.11' MD, 3842.1' TVD 7,110.03 3,750.11 -2,662.09 -1,345.97 Start Dir 4'/100' : 7110.03' MD, 3750.11'TVD 7,208.79 3,742.45 -2,661.10 -1,444.41 End Dir : 7208.79' MD, 3742.45' TVD 7,808.79 3,716.28 -2,651.90 -2,043.76 Start Dir 4'/100' : 7808.79' MD, 3716.28'TVD 7,830.11 3,715.37 -2,651.73 -2,065.06 End Dir : 7830.11' MD, 3715.37' TVD 9,809.82 3,632.14 -2,650.65 -4,043.02 Start Dir 3'/100' : 9809.82' MD, 3632.14'TVD 9,822.54 3,631.65 -2,650.64 -4,055.73 End Dir : 9822.54' MD, 3631.65' TVD 10,906.49 3,593.29 -2,649.96 -5,139.00 Start Dir Y/100' : 10906.49' MD, 3593.29'TVD 10,919.02 3,592.83 -2,649.99 -5,151.53 End Dir : 10919.02' MD, 3592.83' TVD 11,658.53 3,564.75 -2,653.99 -5,890.49 Total Depth : 11658.53' MD, 3564.75' TVD 1011012019 1:42:21PM Page 9 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt S Pad Plan: MPU S-201 MPU S-201 MPU S-201 wp06 Sperry Drilling Services Clearance Summary Anticollision Report 10 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt S Pad - Plan: MPU S-201 - MPU S-201 - MPU S-201 wp06 Well Coordinates: 5,999,877.25 N, 565,450.45 E (70° 24' 36.42" N, 149' 28' 01.42" W) Datum Height: MPU S-201 wp05 Prelim RKB @ 64.70usft Scan Range: 26.50 to 6,245.59 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBUR 7 Sperry Drilling Be Hilcoi IJRTON n Report for Plan: MPU S-201- MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU S-201 - MPU S-201 - MPU S-201 wp06 :) 6,245.59 usft. Measured Depth. cited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum SepE I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft - MPS-05 5,260.82 395.92 5,260.82 322.62 8,810.00 5.401 Centre Distance Pass - - MPS-05 5,326.50 402.61 5,326.50 316.24 8,810.00 4.662 Ellipse Separation Pass - - MPS-05 5,451.50 449.11 5,451.50 341.37 8,810.00 4.169 Clearance Factor Pass - L1 - MPS-051-1 5,141.29 387.86 5,141.29 302.59 8,745.00 4.548 Centre Distance Pass - L1 - MPS-05L1 5,201.50 393.67 5,201.50 295.58 8,745.00 4.013 Ellipse Separation Pass - L1 - MPS-051-1 5,301.50 427.26 5,301.50 311.64 8,745.00 3.696 Clearance Factor Pass - - MPS-06 1,532.50 484.99 1,532.50 470.39 1,619.31 33.218 Ellipse Separation Pass - - MPS-06 6,201.50 765.99 6,201.50 673.25 5,186.42 8.260 Clearance Factor Pass - - MPS-08 1,733.33 367.91 1,733.33 351.97 1,838.10 23.070 Ellipse Separation Pass - - MPS-08 4,826.50 846.68 4,826.50 784.77 4,724.80 13.675 Clearance Factor Pass - ,P61 - MPS-08PB1 1,733.33 367.91 1,733.33 351.97 1,838.10 23.070 Ellipse Separation Pass - ;PB1 - MPS-08PB1 4,826.50 846.68 4,826.50 784.77 4,724.80 13.675 Clearance Factor Pass - - MPS-11 3,121.59 463.94 3,121.59 389.56 3,075.21 6.238 Centre Distance Pass - - MPS-11 3,251.50 468.11 3,251.50 385.77 3,202.39 5.685 Ellipse Separation Pass - - MPS-11 3,626.50 532.27 3,626.50 426.35 3,561.02 5.025 Clearance Factor Pass - MPS-13 1,439.50 340.32 1,439.50 327.88 1,462.94 27.353 Ellipse Separation Pass - - MPS-13 6,226.50 1,472.94 6,226.50 1,397.80 4,643.15 19.603 Clearance Factor Pass - - MPS-14 1,275.39 265.28 1,275.39 252.50 1,353.54 20.744 Centre Distance Pass - MPS-14 1,276.50 265.29 1,276.50 252.49 1,354.50 20.725 Ellipse Separation Pass - MPS-14 1,401.50 281.30 1,401.50 266.95 1,452.05 19.604 Clearance Factor Pass - - MPS-22 1,111.50 254.88 1,111.50 244.54 1,141.53 24.642 Ellipse Separation Pass - - MPS-22 1,226.50 266.92 1,226.50 255.54 1,229.67 23.446 Clearance Factor Pass - - MPS-23 916.29 305.84 916.29 299.61 911.62 49.092 Centre Distance Pass - - MPS-23 926.50 305.86 926.50 299.55 921.34 48.486 Ellipse Separation Pass - - MPS-23 6,245.59 636.04 6,245.59 497.06 8,110.00 4.577 Clearance Factor Pass - L1 - MPS-23L1 916.29 305.84 916.29 299.61 911.62 49.092 Centre Distance Pass - .L1 - MPS-231-1 926.50 305.86 926.50 299.55 921.34 48.486 Ellipse Separation Pass - ,L1 - MPS-23L1 6,245.59 638.85 6,245.59 498.93 8,082.00 4.566 Clearance Factor Pass - 19 - 13:44 Page 2 of 9 Hilcol LJRTON n Report for Plan: MPU S-201- MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU S-201 - MPU S-201 - MPU S-201 wp06 :) 6,245.59 usft. Measured Depth. fited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum Sepz I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPS-24 915.53 283.33 915.53 275.14 925.38 34.587 Centre Distance Pass - MPS-24 926.50 283.37 926.50 275.11 936.03 34.327 Ellipse Separation Pass - - MPS-24 1,126.50 305.30 1,126.50 295.69 1,105.54 31.790 Clearance Factor Pass - PB1 - MPS-24PB1 915.53 283.33 915.53 275.14 925.38 34.587 Centre Distance Pass - PB1 - MPS-24PB1 926.50 283.37 926.50 275.11 936.03 34.327 Ellipse Separation Pass - PB1 - MPS-24PB1 1,126.50 305.30 1,126.50 295.69 1,105.54 31.790 Clearance Factor Pass - PB2 - MPS-24PB2 915.53 283.33 915.53 275.14 925.38 34.587 Centre Distance Pass - PB2 - MPS-24PB2 926.50 283.37 926.50 275.11 936.03 34.327 Ellipse Separation Pass - PB2 - MPS-24PB2 1,126.50 305.30 1,126.50 295.69 1,105.54 31.790 Clearance Factor Pass - - MPS-25 690.29 281.34 690.29 276.26 686.04 55.387 Centre Distance Pass - - MPS-25 701.50 281.36 701.50 276.21 696.57 54.666 Ellipse Separation Pass - - MPS-25 1,051.50 325.83 1,051.50 317.83 996.95 40.731 Clearance Factor Pass - L1 - MPS-251-1 690.29 281.34 690.29 276.26 686.04 55.385 Centre Distance Pass - L1 - MPS-25L1 701.50 281.36 701.50 276.21 696.57 54.665 Ellipse Separation Pass - 1L1-MPS-25L1 1,051.50 325.83 1,051.50 317.83 996.95 40.730 Clearance Factor Pass- - MPS-26 1,273.61 133.38 1,273.61 123.82 1,313.28 13.951 Centre Distance Pass - MPS-26 1,276.50 133.39 1,276.50 123.81 1,315.95 13.921 Ellipse Separation Pass - MPS-26 1,401.50 151.01 1,401.50 139.56 1,429.26 13.192 Clearance Factor Pass - - MPS-27 875.22 245.51 875.22 239.16 883.62 38.696 Centre Distance Pass - - MPS-27 876.50 245.51 876.50 239.15 884.82 38.630 Ellipse Separation Pass - - MPS-27 1,076.50 272.08 1,076.50 263.85 1,047.12 33.062 Clearance Factor Pass - 'L1 - MPS-27L1 875.22 245.51 875.22 239.17 883.62 38.700 Centre Distance Pass - 'L1 - MPS-27L1 876.50 245.51 876.50 239.16 884.82 38.634 Ellipse Separation Pass - L1 - MPS-271-1 1,076.50 272.08 1,076.50 263.85 1,047.12 33.075 Clearance Factor Pass - 'PB1 - MPS-27PB1 875.22 245.51 875.22 238.62 883.62 35.652 Centre Distance Pass - 'PB1 - MPS-27PB1 876.50 245.51 876.50 238.61 884.82 35.596 Ellipse Separation Pass - 'PB1 - MPS-27PB1 1,051.50 265.11 1,051.50 256.57 1,029.78 31.011 Clearance Factor Pass - MPS-28 887.16 224.49 887.16 216.09 905.08 26.736 Ellipse Separation Pass - MPS-28 1,001.50 233.25 1,001.50 224.18 1,000.95 25.714 Clearance Factor Pass - ;PB1 - MPS-28PB1 887.16 224.49 887.16 216.09 905.08 26.736 Ellipse Separation Pass - 19 - 13:44 Page 3 of 9 URTON n Report for Plan: MPU S-201 - MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU 5-201 - MPU S-201 - MPU 5-201 wp06 :) 6,245.59 usft. Measured Depth. fited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse Depth Distance Depth Separation I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) P131 - MPS-28PB1 1,001.50 233.25 1,001.50 224.18 PB2 - MPS-28PB2 887.16 224.49 887.16 216.09 PB2 - MPS-28PB2 1,001.50 233.25 1,001.50 224.18 MPS-29 669.60 217.24 669.60 212.38 MPS-29 676.50 217.25 676.50 212.35 MPS-29 926.50 250.01 926.50 243.10 L1 - MPS-29L1 669.60 217.24 669.60 212.38 L1 - MPS-291-1 676.50 217.25 676.50 212.35 L1 - MPS-291-1 926.50 250.01 926.50 243.10 MPS-30 829.07 195.64 829.07 186.05 MPS-30 951.50 201.46 951.50 191.35 MPS-31 1,019.67 150.97 1,019.67 143.80 MPS-31 1,026.50 151.01 1,026.50 143.77 MPS-31 1,126.50 160.54 1,126.50 152.40 MPS-32 657.11 177.07 657.11 169.38 MPS-32 776.50 183.23 776.50 174.82 MPS-33 814.99 158.72 814.99 153.06 MPS-33 826.50 158.77 826.50 153.04 MPS-33 1,001.50 175.89 1,001.50 168.92 -A- MPS-33A 814.99 158.72 814.99 153.06 ,A- MPS-33A 826.50 158.77 826.50 153.04 A- MPS-33A 1,001.50 175.89 1,001.50 168.92 MPS-34 696.20 131.08 MPS-34 701.50 131.10 MPS-34 801.50 141.21 L1 - MPS-341-1 696.20 131.08 L1 - MPS-341-1 701.50 131.10 L1 - MPS-34L1 801.50 141.21 L2 - MPS-341-2 L2 - MPS-341-2 696.20 131.08 701.50 131.10 @Measured Clearance Summary Based on Depth Factor Minimum usft 1,000.95 25.714 Clearance Factor 905.08 26.736 Ellipse Separation 1,000.95 25.714 Clearance Factor 673.01 44.691 Centre Distance 679.42 44.263 Ellipse Separation 891.90 36.190 Clearance Factor 673.01 44.691 Centre Distance 679.42 44.263 Ellipse Separation 891.90 36.190 Clearance Factor 837.38 20.418 Ellipse Separation 953.76 19.941 Clearance Factor 1,047.22 21.035 Centre Distance 1,053.53 20.872 Ellipse Separation 1,143.68 19.719 Clearance Factor 664.73 23.041 Ellipse Separation 773.85 21.796 Clearance Factor 817.35 28.049 Centre Distance 828.43 27.694 Ellipse Separation 991.91 25.236 Clearance Factor 823.66 28.050 Centre Distance 834.74 27.694 Ellipse Separation 998.22 25.235 Clearance Factor 696.20 125.46 713.40 23.306 Centre Distance 701.50 125.43 718.28 23.134 Ellipse Separation 801.50 134.61 805.31 21.404 Clearance Factor 696.20 125.46 713.40 23.306 Centre Distance 701.50 125.43 718.28 23.134 Ellipse Separation 801.50 134.61 805.31 21.404 Clearance Factor 696.20 125.46 713.40 23.306 Centre Distance 701.50 125.43 718.28 23.134 Ellipse Separation T - 13:44 Page 4 of 9 Mew SepE Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - LJRTON n Report for Plan: MPU S-201 - MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU S-201 - MPU 5-201 - MPU S-201 wp06 :) 6,245.59 usft. Measured Depth. cited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse Depth Distance Depth Separation I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) L2 - MPS-341-2 801.50 141.21 801.50 134.61 MPS-35 693.00 106.67 693.00 99.91 - MPS-35 751.50 109.76 751.50 102.67 PB1 - MPS-35PB1 693.00 106.67 693.00 99.91 PB1 - MPS-35PB1 751.50 109.76 751.50 102.67 PB2 - MPS-35PB2 693.00 106.67 693.00 99.91 P132 - MPS-35PB2 751.50 109.76 751.50 102.67 MPS-37 273.73 103.46 273.73 99.56 - MPS-37 1,001.50 103.87 1,001.50 91.36 MPS-37 1,276.50 119.96 1,276.50 103.56 - MPS-39 106.75 74.24 106.75 72.63 - MPS-39 251.50 75.06 251.50 72.09 - MPS-39 1,126.50 94.42 1,126.50 84.02 MPS-41 557.25 40.78 557.25 34.26 MPS-41 4,701.50 575.88 4,701.50 478.40 A - MPS-41 A 557.25 40.78 557.25 34.26 A-MPS-41A 4,626.50 493.35 4,626.50 395.72 APB1 -MPS-41APB1 557.25 40.78 557.25 34.26 APB1 - MPS-41APB1 4,626.50 493.35 4,626.50 395.61 AP132 - MPS-41AP132 557.25 40.78 557.25 34.26 APB2 - MPS-41APB2 4,626.50 493.35 4,626.50 395.61 MPS-43 107.27 14.35 107.27 12.69 MPS-43 151.50 14.67 151.50 12.45 - MPS-43 4,976.50 208.34 4,976.50 112.18 1 S-203 - MPU S-203 26.50 59.38 26.50 58.47 1 S-203 - MPU S-203 176.50 60.37 176.50 58.21 J 5-203 - MPU S-203 1,451.50 129.01 1,451.50 113.95 1 S-203PB1 - MPU S-203P61 26.50 59.38 26.50 58.47 1 S-203P61 - MPU S-203PB1 176.50 60.37 176.50 58.21 1 S-203PB1 - MPU S-203PB1 1,451.50 129.01 1,451.50 113.95 f9 - 13:44 Page 5 of 9 Hilcoi @Measured Clearance Summary Based on Depth Factor Minimum Sepr usft 805.31 21.404 Clearance Factor Pass - 708.93 15.780 Ellipse Separation Pass - 762.94 15.470 Clearance Factor Pass - 708.93 15.780 Ellipse Separation Pass - 762.94 15.470 Clearance Factor Pass - 708.93 15.780 Ellipse Separation Pass - 762.94 15.470 Clearance Factor Pass - 280.93 26.505 Centre Distance Pass - 1,003.48 8.308 Ellipse Separation Pass - 1,283.24 7.314 Clearance Factor Pass - 107.48 46.191 Centre Distance Pass - 251.56 25.276 Ellipse Separation Pass - 1,103.02 9.073 Clearance Factor Pass - 563.36 6.257 Ellipse Separation Pass - 4,506.18 5.908 Clearance Factor Pass - 563.36 6.257 Ellipse Separation Pass - 4,605.29 5.053 Clearance Factor Pass - 563.36 6.257 Ellipse Separation Pass - 4,605.29 5.047 Clearance Factor Pass - 563.36 6.257 Ellipse Separation Pass - 4,605.29 5.047 Clearance Factor Pass - 113.64 8.656 Centre Distance Pass - 157.66 6.585 Ellipse Separation Pass - 4,541.24 2.167 Clearance Factor Pass - 26.70 65.117 Centre Distance Pass - 174.65 28.050 Ellipse Separation Pass - 1,417.72 8.565 Clearance Factor Pass - 26.70 65.117 Centre Distance Pass - 174.65 28.050 Ellipse Separation Pass - 1,417.72 8.565 Clearance Factor Pass - Hilew LJRTON n Report for Plan: MPU S-201 - MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU S-201 - MPU 5-201 - MPU S-201 wp06 :) 6,245.59 usft. Measured Depth. cited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum Sepa I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 1 5-203PB2 - MPU S-203PB2 26.50 59.38 26.50 58.47 26.70 65.117 Centre Distance Pass - 1 5-203PB2 - MPU S-203PB2 176.50 60.37 176.50 58.21 174.65 28.050 Ellipse Separation Pass - 1 S-203PB2 - MPU S-203PB2 1,451.50 129.01 1,451.50 113.95 1,417.72 8.565 Clearance Factor Pass - 'U S-202 - MPU 5-202 - 5-202 wpOE 1,076.72 54.41 1,076.72 45.83 1,083.19 6.341 Ellipse Separation Pass - 'U S-202 - MPU S-202 - S-202 wpOE 1,126.50 55.11 1,126.50 46.29 1,133.37 6.242 Clearance Factor Pass - )U 5-204 - MPU S-204 - S-204 wpOE 277.14 121.45 277.14 118.59 277.14 42.466 Centre Distance Pass - 'U 5-204 - MPU S-204 - S-204 wpOE 326.50 121.64 326.50 118.41 325.48 37.648 Ellipse Separation Pass - )U S-204 - MPU 5-204 - S-204 wpOE 1,551.50 313.92 1,551.50 298.27 1,462.12 20.060 Clearance Factor Pass - 'U S-205 - MPU S-205 - 5-205 wp04 524.27 28.17 524.27 23.67 524.03 6.268 Centre Distance Pass - 'U S-205 - MPU S-205 - S-205 wp04 526.50 28.17 526.50 23.67 526.25 6.256 Ellipse Separation Pass - 'U S-205 - MPU 5-205 - S-205 wp04 576.50 28.71 576.50 23.98 575.96 6.078 Clearance Factor Pass - 'U S-206 - S-206 - UGNU#6 - S-206 445.16 13.83 445.16 9.49 445.63 3.190 Centre Distance Pass - )U S-206 - S-206 - UGNU#6 - S-206 451.50 13.84 451.50 9.47 451.96 3.164 Ellipse Separation Pass - 'U S-206 - S-206 - UGNU#6 - 5-206 476.50 14.29 476.50 9.75 476.86 3.150 Clearance Factor Pass - 'U 5-207 - MPU S-207 - MPU S-207 424.67 29.55 424.67 25.34 426.75 7.023 Centre Distance Pass - 'U S-207 - MPU S-207 - MPU S-207 426.50 29.55 426.50 25.33 428.57 7.004 Ellipse Separation Pass - 'U 5-207 - MPU 5-207 - MPU S-207 476.50 30.51 476.50 25.97 478.21 6.721 Clearance Factor Pass - 'U S-208 - MPU S-208 - MPU S-208 404.14 45.53 404.14 41.46 406.10 11.172 Centre Distance Pass - 'U S-208 - MPU 5-208 - MPU 5-208 426.50 45.62 426.50 41.40 428.42 10.814 Ellipse Separation Pass - 'U S-208 - MPU 5-208 - MPU 5-208 501.50 48.03 501.50 43.33 502.54 10.225 Clearance Factor Pass - 'U S-209 - S-209 - MPU S-209 wp01 361.02 61.28 361.02 57.55 362.55 16.470 Centre Distance Pass - 'U S-209 - S-209 - MPU S-209 wp01 401.50 61.45 401.50 57.40 402.96 15.150 Ellipse Separation Pass - 'U S-209 - S-209 - MPU S-209 wpO1 501.50 64.86 501.50 60.17 501.58 13.818 Clearance Factor Pass - 'U 5-210 - MPU S-210 - MPU 5-210 326.50 76.57 326.50 73.14 327.90 22.320 Centre Distance Pass - 'U S-210 - MPU S-210 - MPU S-210 401.50 76.82 401.50 72.77 402.69 18.944 Ellipse Separation Pass - 'U S-210 - MPU 5-210 - MPU 5-210 551.50 82.91 551.50 77.98 550.00 16.808 Clearance Factor Pass - 19 - 13:44 Page 6 of 9 URTON n Report for Plan: MPU S-201- MPU S-201 wp06 iey tool program From To Survey/Plan (usft) (usft) 26.50 400.00 MPU S-201 wp06 400.00 6,245.59 MPU 5-201 wp06 6,245.59 11,658.53 MPU S-201 wp06 correlated across survey tool tie -on points. orporate surface errors. 31 distance between ellipsoids. tres is the straight line distance between wellbore centres. Stance Between Profiles / (Distance Between Profiles - Ellipse Separation). were calculated using the Minimum Curvature method. '9 - 13:44 Page 7 of 9 Survey Tool 2_Gyro-NS-GC_Drill collar 2_MWD+IFR2+MS+Sag 2_M W D+IFR2+MS+Sag Hilco: Project: Milne Point .." �,...' WELL DETAns:rlan: MPU S-201 NAD 1927(NADCON Site: M Pt S Pad Co-ordinate (N/E) Reference: Well Plan: MPU S-201, True North 38.20 Vertical (TVD) Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft Well: Plan: MPU S-201 Measured Depth Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft +N/-S +E/-W Northing Easting L Wellbore: MPU S-201 Calculation Method: Minimum Curvature 0.00 0.00 5999877.25 565450.45 70' 2 Plan: MPU S-201 Wp06 SURVEY PROGRAM GLOBAL FILTER APPLIED: All wellpaths within Date: 2019-07-05T00:00:00 Validated: Yes Version: 26.50 To 11658.53 Depth From Depth To Survey/Plan Tool CASING DETAILS Ladder / S.F. Plots 26.50 400.00 MPU S-201 wp06 (MPU S-201) 2_Gyro-NS-GC_Drill collar TVD TVDSS MD Size I SH(1 of 2) 400.00 6245-59 MPU S-201 wp06 (MPU S-201) 2_MWD+IFR2+MS+Sag 3846.03 3781.33 6245.59 9-5/8 ! 6245.59 11658.53 MPU S-201 wp06 (MPU S-201) 2_MWD+IFR2+MS+Sag 3564.75 3500..05 11658.53 6-5/8 I i i I i � j I ' I 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 Measured Depth (650 usft/in) — 3k Procedures _ Req. i -- I ILI I oidance Req. j - Stop Drilling j II S j j I I i I I b5U Ulb 1JUU 1b25 lySU 22/5 2bUU "Ly25 J25U :35/5 39UU 4225 455U 481b 5200 5525 Measured Depth (650 usft/in) Hilcorp Alaska, LLC Milne Point M Pt S Pad Plan: MPU S-201 MPU S-201 MPU S-201 wp06 Sperry Drilling Services Clearance Summary Anticollision Report 10 October, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt S Pad - Plan: MPU S-201 - MPU S-201 - MPU S-201 wp06 Well Coordinates: 5,999,877.25 N, 565,450.45 E (70' 24' 36.42" N, 149° 28' 01.42" W) Datum Height: MPU S-201 wp05 Prelim RKB @ 64.70usft Scan Range: 6,245.59 to 11,658.53 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBUR Sperry Drilling Bt Hilco URTON n Report for Plan: MPU S-201 - MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU S-201 - MPU 5-201 - MPU S-201 wp06 9 to 11,658.53 usft. Measured Depth. fited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum Sepz I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft - MPS-05 6,245.59 1,144.75 6,245.59 1,008.18 8,810.00 8.382 Clearance Factor Pass - L1 - MPS-05L1 6,245.59 1,266.72 6,245.59 1,125.56 8,745.00 8.974 Clearance Factor Pass - - MPS-06 6,245.59 754.64 6,245.59 663.45 5,200.25 8.275 Clearance Factor Pass - - MPS-06 6,370.59 737.08 6,370.59 653.48 5,238.57 8.817 Ellipse Separation Pass - - MPS-06 6,421.33 735.51 6,421.33 655.48 5,254.09 9.191 Centre Distance Pass - - MPS-13 6,245.59 1,474.37 6,245.59 1,399.17 4,644.66 19.605 Clearance Factor Pass - - MPS-22 ® ® - MPS-22 ® ® ®® - - MPS-23 6,420.59 511.78 6,420.59 391.12 8,110.00 4.241 Clearance Factor Pass - - MPS-23 6,670.59 406.21 6,670.59 333.85 8,110.00 5.613 Ellipse Separation Pass - - MPS-23 6,739.42 400.34 6,739.42 337.36 8,110.00 6.357 Centre Distance Pass - ,L1 - MPS-23L1 6,495.59 451.46 6,495.59 334.81 8,082.00 3.870 Clearance Factor Pass - ,L1 - MPS-23L1 6,695.59 361.44 6,695.59 287.79 8,082.00 4.907 Ellipse Separation Pass - .L1 - MPS-231-1 6,778.52 351.80 6,778.52 294.20 8,082.00 6.108 Centre Distance Pass - MPS-24 9,770.59 567.48 9,770.59 346.20 8,205.00 2.565 Clearance Factor Pass - MPS-24 9,820.59 563.24 9,820.59 344.59 8,205.00 2.576 Ellipse Separation Pass - - MPS-24 9,845.59 562.71 9,845.59 345.92 8,205.00 2.596 Centre Distance Pass - PB2 - MPS-24PB2 8,420.59 1,160.98 8,420.59 975.66 6,760.00 6.265 Clearance Factor Pass - PB2 - MPS-24PB2 8,520.59 1,152.94 8,520.59 970.15 6,760.00 6.307 Ellipse Separation Pass - PB2 - MPS-24PB2 8,563.64 1,152.14 8,563.64 970.78 6,760.00 6.353 Centre Distance Pass - - MPS-25 9,295.65 424.07 9,295.65 331.57 10,250.00 4.585 Centre Distance Pass - - MPS-25 9,370.59 430.64 9,370.59 328.93 10,250.00 4.234 Ellipse Separation Pass - MPS-25 9,595.59 519.42 9,595.59 373.03 10,250.00 3.548 Clearance Factor Pass - L1 - MPS-25L1 8,970.59 488.19 8,970.59 364.64 10,178.00 3.951 Clearance Factor Pass - L1 - MPS-251-1 9,257.91 394.68 9,257.91 314.18 10,178.00 4.903 Ellipse Separation Pass - - MPS-26 7,995.59 827.68 7,995.59 671.56 5,575.83 5.302 Clearance Factor Pass - - MPS-26 8,170.59 809.50 8,170.59 660.53 5,693.53 5.434 Ellipse Separation Pass - MPS-26 8,233.25 808.10 8,233.25 662.73 5,732.79 5.559 Centre Distance Pass - f 9 - 13.46 Page 2 of 5 Mew URTON n Report for Plan: MPU S-201- MPU S-201 wp06 i Proximity Scan on Current Survey Data (North Reference) I Pt S Pad - Plan: MPU 5-201 - MPU S-201 - MPU S-201 wp06 9 to 11,658.53 usft. Measured Depth. cited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum Sepz I Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft - MPS-43 6,245.59 1,357.05 6,245.59 1,231.65 4,620.12 10.821 Clearance Factor Pass - 1 S-203 - MPU S-203 6,501.88 1,304.46 6,501.88 1,230.87 5,023.09 17.726 Centre Distance Pass - 1 S-203 - MPU S-203 9,620.59 1,342.24 9,620.59 1,173.32 8,118.13 7.946 Ellipse Separation Pass - 1 S-203 - MPU 5-203 11,658.53 1,401.77 11,658.53 1,175.02 10,225.37 6.182 Clearance Factor Pass - 1 S-203PB1 - MPU 5-203PB1 6,501.88 1,304.46 6,501.88 1,230.87 5,023.09 17.726 Centre Distance Pass - 1 S-203PB1 - MPU S-203PB1 11,270.59 1,343.77 11,270.59 1,088.59 9,787.00 5.266 Ellipse Separation Pass - 1 S-203PB1 - MPU S-203PB1 11,320.59 1,345.59 11,320.59 1,089.58 9,787.00 5.256 Clearance Factor Pass - J S-203PB2 - MPU S-203PB2 6,501.88 1,304.46 6,501.88 1,230.87 5,023.09 17.726 Centre Distance Pass - 1 S-203PB2 - MPU S-203PB2 11,658.53 1,340.32 11,658.53 1,104.70 10,259.35 5.688 Clearance Factor Pass - 'U S-202 - MPU S-202 - S-202 wpOE 9,826.45 640.59 9,826.45 449.28 8,662.14 3.348 Centre Distance Pass - 'U S-202 - MPU 5-202 - 5-202 wpOE 11,658.53 648.18 11,658.53 374.93 10,492.57 2.372 Clearance Factor Pass - iey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 400.00 MPU S-201 wp06 2_Gyro-NS-GC_Drill collar 400.00 6,245.59 MPU S-201 wp06 2_MWD+IFR2+MS+Sag 6,245.59 11,658.53 MPU S-201 wp06 2_MWD+IFR2+MS+Sag correlated across survey tool tie -on points. orporate surface errors. 31 distance between ellipsoids. tres is the straight line distance between wellbore centres. Stance Between Profiles / (Distance Between Profiles - Ellipse Separation). were calculated using the Minimum Curvature method. f 9 - 13.46 Page 3 of 5 V Project: Milne Point --' - -' _- " ' - WELL DETAILS:Plan: MPU S-201 NAD 1927(NADCONi Site: M Pt S Pad Co-ordinate (N/E) Reference: Well Plan: MPU S-201, True North 38.20 Vertical (TVD) Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft Northing Well: Plan: MPU S-201 Measured Depth Reference: MPU S-201 wp05 Prelim RKB @ 64.70usft +N/-S +E/-W Easting Latittud Wellbore: MPU S-201 Calculation Method: Minimum Curvature 0.00 0.00 5999877.25 565450.45 70° 24' 36. Plan: MPU S-201 wp06 SURVEY PROGRAM GLOBAL FILTER APPLIED: All wellpaths within Date: 2019-07-05T00:00:00 Validated: Yes Version: 26.50 To 11658.53 Ladder / S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS 26.50 400.00 MPU S-201 wp06 (MPU S-201) 2_Gyro-Gyro-GC Drill collar TVD TVDSS MD Size P H (2 2) 400.00 6245.59 MPU S-201 wp06 (MPU S-201) 2_MWD+IFR2+MS+Sag of 6245.59 11658.53 MPU S-201 wp06 (MPU S-201) 2 MWD+IFR2+MS+Sag 3846.03 3781.33 6245.59 9-5/8 3564.75 3500.05 11658.53 6-5/8 i 6600 6900 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 Measured Depth (600 usft/in) >k Procedures oidance Req. - Stop Drilling 5 6600 6900 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 Measured Depth (600 usft/in) Transform Points Source coordinate system State Plane 1927 - Alaska Zone 4 � C) Datum: NAD 1927 - North America Datum of 1927 (Mean) CU ,3 Kw) I Target coordinate system Nbers Equal Area (-150) C R b er 5 Datum: NAD 1927 - North America Datum of 1927 (Mean) ype values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctfl+C to opy and Ctfl+Vto paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. <-8--ack -Finish i Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: NP Gt PTD: vZ 1 1 14 -p� �evelopment _ Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: I t ► ' h. P. P©! Lt T POOL: � q % GL U L4 J e`"in ej Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -_) from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, UGNU UNDEFINE OIL - 525160 Well Name: MILNE PT UNIT S-201 Program DEV Well bore seg ❑ PTD#: 2191420 Company Hilcorp Alaska LLC---___— -- Initial Class/Type DEV / PEND GeoArea 890 _ Unit 11328 _ On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate_ Yes 3 Unique well name and number Yes 4 Well located in-a_defined pool No Ugnu Undefined Oil pool 5 Well _located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit Yes _ 8 If deviated, is_wellbore plat -included Yes _ 9 Operator only affected party - Yes 10 Operator has appropriate bond in force Yes 11 Permit_ can be issued without conservation order Yes Appr Date 12 Permit_Gan be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes DLB 10/22/2019 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 Nonconven. gas conforms to AS31.05.030Q.1_.A),0.2.A-D) NA 18 Conductor string provided Yes 20" conductor set at 107_ ft - - - - - Engineering 19 _Surface casing protects all known_ USDWs NA 20 CMT vol adequate to circulate on conductor & surf csg Yes - 9 5/8" surfacecasingwill be cemented in_2-stages.._ ES at 2500 ft. 21 CMT vol adequate to tie-in long string to surf csg Yes 22 CMT-will coverall known -productive horizons_ - - Yes -------- -------------- 23 Casing designs adequate for C, T, B &_permafr_ost_ Yes BTC calc supplied. ----------------- 24 Adequate tankage or reserve pit - Yes Rig has steel pits, 25 If_a re -drill, has a 1.0-403 for abandonment been approved NA 126 Adequate wellbore separation proposed- Yes - - S-22 has close crossing but is separated vertically ... S-22 in_SB 27 If-diverter required, does it meet regulations_ Yes Appr Date i28 Drilling fluid program schematic & equip listadequate Yes Max form pressure = 1694 psi ( 8.6 ppg EMW) will drill with_8.8-9.8 ppg mud. _On_diverter till Ungnu GLS 10/30/2019 29 �30 BOPEs, do the meet regulation _ _ _ _ _ _ y- g Yes BOPE_press rating appropriate; test to _(put psig in comments)_ Yes MASP =1300 psi _testing BOPE to_3000 psi 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown_ Yes 33 Is presence of 112S gas_ probable No 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen_sul_fide measures Yes No H2S anticipated Geology 36 Data presented on potential overpressure zones _ Yes Appr Date �37 Seismic analysis of shallow gas -zones NA DLB 10/22/2019 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly_ progress reports_ [exploratory only] - NA Geologic Engineering Public Ugnu development well... sized screens with RC Jet pump. GLS Date: Date Date Commissioner: Commissioner: Com issioner