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Home My WebLink About224-159MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, July 25, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC S-53 MILNE PT UNIT S-53 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/25/2025 S-53 50-029-23811-00-00 224-159-0 W SPT 3947 2241590 2000 498 498 498 499 242 391 386 380 INITAL P Kam StJohn 6/9/2025 Initial MIT-IA per Sundry 325-088 and PTD 2241590 after 10 days stabilization 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT S-53 Inspection Date: Tubing OA Packer Depth 725 2228 2156 2135IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250609145622 BBL Pumped:2 BBL Returned:2 Friday, July 25, 2025 Page 1 of 1           David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 05/06/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU S-53 PTD: 224-159 API: 50-029-23811-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (02/22/2025 to 04/01/2025) x ROP, AGR, DGR, iCruise, BaseStar and ABG Gamma Ray, EWR-M5, ADR and StrataStar Resistivity x Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolders: Please include current contact information if different from above. 224-159 T40354 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.06 15:17:31 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Ryan Thompson To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:MPU MIT"s - MPR-145 & MPS-53 Date:Thursday, April 10, 2025 2:14:44 PM Attachments:MIT MPU S-53 04-06-25.xlsx MIT MPU R-145 04-06-25.xlsx All – Please see recently completed MIT’s performed in April for MPU. Well PTD# Comment MPS-53 2241590 MIT-IA post running completion – On rig MPR-145 2241500 Initial MIT-IA post coming on injection Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 9 MPS-53 2241590 Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD2241590Type InjNTubing0000 Type TestP Packer TVD 3947 BBL Pump 4.7 IA 0 3700 3590 3550 Interval O Test psi 3500 BBL Return 4.0 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Milne Point, MPU, S Pad Scott Heim / Ian Toomey 04/06/25 Notes:MIT-IA (prior to injection) per PTD# 224-159 to 3500 psi on rig. Witness waived by Brian Bixby via email on 4/4/25 at 08:39 hours. Notes: Notes: Notes: S-53 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2025-0406_MIT_MPU_S-53 9 9 999 9 9 9 9 -5HJJ MIT-IA (prior to injection) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT S-53 JBR 04/29/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 3.5" and 4.5" test joints used for testing. The upper IBOP failed on the low. They will replace it. I left location after every other component was tested and did not witness the retest of the upper IBOP. I asked them to send me the test chart for it once it was tested. 18 charge bottles all with 1000 psi precharge. Test Results TEST DATA Rig Rep:J. Charlie/N. HamiltonOperator:Hilcorp Alaska, LLC Operator Rep:M. Brouilet/J. Vanderpool Rig Owner/Rig No.:Doyon 14 PTD#:2241590 DATE:3/23/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopGDC250323184454 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 8 MASP: 1345 Sundry No: 325-088 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 F Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 P #1 Rams 1 2 7/8"x5" VB P #2 Rams 1 Blinds P #3 Rams 1 2 7/8"x5" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 2 3 1/8" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1700 200 PSI Attained P51 Full Pressure Attained P193 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@2002 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P16 #1 Rams P10 #2 Rams P10 #3 Rams P9 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P3 9 9 9 99999 9 9 9 9 7HVWFKDUWVDQG7HVWVHTXHQFHDWWDFKHG Upper Kelly F 1 The upper IBOP failed left location after every other component was tested and did not witness the retest of the upper IBOP #23('R\RQ 038637' $2*&&,QVSERS*'& %23('R\RQ 038637' $2*&&,QVS ERS*'& %23('R\RQ 038637' $2*&&,QVSERS*'& %23('R\RQ 038637' $2*&&,QVSERS*'& Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272 MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' 325-088 By Gavin Gluyas at 7:57 am, Feb 19, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.02.18 15:53:57 - 09'00' Sean McLaughlin (4311) DSR-2/20/25SFD 2/19/2025 * BOPE test to 3000 psi. Annular to 2500 psi. * MIT-IA to 3500 psi. 24 hour notice. * MIT-IA to 2000 psi after 10 days of stabilized injection. *7-5/8 cement evaluation log to AOGCC upon completion of log. * Documented well control drills for all crews running slotted liners with safety joints spaced out across BOPE. * Pre-production not allowed without spacing exception. 10-407 MGR24FEB25*&: 2/24/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.24 15:29:43 -09'00' RBDMS JSB 022525 Milne Point Unit (MPU) S-53 Application for Permit to Drill Version 2 1/15/2025 (Revised) SFD 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 Diverter System ............................................................................................................... 11 11.0 Drill 13-1/2” Hole Section ....................................................................................................... 13 12.0 Run 10-3/4” Surface Casing ................................................................................................... 16 13.0 Cement 10-3/4” Surface Casing .............................................................................................. 21 14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 26 15.0 Drill 9-7/8” Hole Section ......................................................................................................... 27 16.0 Run 7-5/8” Intermediate Casing ............................................................................................. 30 17.0 Cement 7-5/8” Surface Casing ................................................................................................ 33 18.0 Drill 6-3/4” Hole Section ......................................................................................................... 35 19.0 Run 4-1/2” Injection Liner ..................................................................................................... 40 20.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 44 21.0 Doyon 14 Diverter Schematic ................................................................................................. 46 22.0 Doyon 14 BOP Schematic ....................................................................................................... 47 23.0 Wellhead Schematic ................................................................................................................ 48 24.0 Days Vs Depth ......................................................................................................................... 49 25.0 Formation Tops & Information.............................................................................................. 50 26.0 Anticipated Drilling Hazards ................................................................................................. 52 27.0 Doyon 14 Rig Layout .............................................................................................................. 56 28.0 FIT Procedure ......................................................................................................................... 57 29.0 Doyon 14 Rig Choke Manifold Schematic .............................................................................. 58 30.0 Casing Design .......................................................................................................................... 59 31.0 9-7/8” Hole Section MASP ...................................................................................................... 60 32.0 6-3/4” Hole Section MASP ...................................................................................................... 61 33.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 62 34.0 Surface Plat (As-Staked) (NAD 27) ........................................................................................ 63 Page 2 Milne Point Unit S-53 SB Injector Drilling Program 1.0 Well Summary Well MPU S-53 Pad Milne Point “S” Pad Planned Completion Type Injection Tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 18,076’ MD / 4,061’ TVD PBTD, MD / TVD 18,076’ MD / 4,061’ TVD Surface Location (Governmental) 2075’ FNL, 591’ FEL, Sec. 12, T12N, R10E, UM, AK Surface Location (NAD 27) X= 565421, Y=5999869 Top of Productive Horizon (Governmental)20’ FSL, 888’ FWL, Sec. 7, T12N, R11E, UM, AK TPH Location (NAD 27) X= 566927, Y=5996697 BHL (Governmental) 702' FNL, 1683' FWL, Sec 6, T12N, R11E, UM, AK BHL (NAD 27) X= 567635, Y= 6006542 AFE Drilling Days 23 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 1345 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1740 psig Work String 5” 19.5# S-135 NC 50 4” 14.0# S-135 XT 39 Doyon 14 KB Elevation above MSL: 33.7 ft + 36.6 ft = 70.3 ft GL Elevation above MSL: 36.6 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit S-53 SB Injector Drilling Program 2.0 Management of Change Information Page 4 Milne Point Unit S-53 SB Injector Drilling Program 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 13-1/2” 10-3/4” 9.950”9.794”11.75”45.5 L-80 TXP 5,210 2,470 1040 9-7/8 7-5/8” 6.875” 6.750” 8.500” 29.7 L-80 TXP 6,890 4,790 683 6-3/4” 4-1/2” 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Intermediate 5” 4.276” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560 Production 4” 3.34” 2.5625” 4.875” 14 S-135 XT39 18,500 22,200 403 4” 3.34” 2.5625 4.875 14 S-135 HT38 12,200 17,700 403 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit S-53 SB Injector Drilling Program 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6 am to 6 am x 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. x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp.com, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Completion Engineer Ryan Lewis Ryan.lewis@hilcorp.com Geologist Patrick Boyle 907.564.4649 Patrick.boyle@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 Adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: JNL 12/13/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPU S-53 Last Completed: TBD PTD: TBD TD =18,076’(MD) / TD =4,061’(TVD) 4 20” Orig. KB Elev.: 70.3’ / GL Elev.: 36.6’ 7-5/8” 5 10-3/4” 2 3 See Slotted Liner Detail PBTD =18,076’ (MD) / PBTD =4,061’ (TVD) 5 7 3, 4 12 10-3/4” ES Cementer @~2,500’ 1 2 3-1/2” JEWELRY DETAIL No. MD Item ID 1 7,470’ Zenith Gauge Carrier w/ Control Line 2.992” 2 7,500’ XN Nipple, 2.813” with 2.75” No-Go, at 70 degrees Inc 2.813” 3 8,000’ 7-5/8” x 5-1/2” Baker Liner Top Packer 4.890” 4 8,000’ Baker Liner Hanger 6.180” 5 18,076’ Shoe TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs OPEN HOLE / CEMENT DETAIL 42” 18 yds Concrete 13-1/2"Stage 1 Lead – 390 sx / Tail – 464 sx Stage 2 Lead – 807 sx / Tail – 311 sx 9-7/8” Tail – 398 sx 6-3/4” Uncemented Slotted Liner CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 80’ N/A 10-3/4" Surface 45.5 / L-80 / TXP 9.950 Surface 5,437’ 0.0962 7-5/8” Intermediate 29.7 / L-80 / 563 6.875 Surface 8,150’ 0.0459 4-1/2” Solid/Slotted Liner 13.5 / L-80 / Hyd 625 3.920 8,000’ 18,076’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 3.958 Surface 8,000’ 0.0152 WELL INCLINATION DETAIL KOP @ 250’ 90° Hole Angle = @ 10,300’ 4-1/2” SOLID/SLOTTED LNR DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) GENERAL WELL INFO API: TBD Completion Date: TBD Page 7 Milne Point Unit S-53 SB Injector Drilling Program 7.0 Drilling / Completion Summary MPU S-53 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. S-53 is part of a multi well program targeting the Schrader Bluff sand on S-pad The directional plan is 13-1/2” surface hole with 10-3/4” surface casing set in the lower SV’s. The 9-7/8” intermediate hole will use 7-5/8” intermediate casing set in the top of the Schrader Bluff NB sand. A 6-3/4” lateral section will be drilled and completed with a 4-1/2” liner. The well will be completed with injection tubing. Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately February 19th, 2025, pending rig schedule. Surface casing will be run to 5,437’ MD / 2,312’ TVD and cemented to surface. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will be discussed with AOGCC authorities. Intermediate casing will be run to 8,150’ MD / 3,957’ TVD and cemented to 500’ MD above the hydrocarbon bearing Schrader Bluff formation. TOC will be verified with a CBL. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 13-1/2” hole to TD of surface hole section. 4. Run and cement 10-3/4” surface casing 5. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 6. Drill 9-7/8” intermediate to TD. 7. Run and cement 7-5/8” intermediate casing. 8. Run e-line conveyed CBL to confirm TOC. 9. Drill 6-3/4” lateral to well TD 10. Run 4-1/2” injection liner 11. Run Upper Completion 12. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res 2. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 3. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit S-53 SB Injector Drilling Program 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU S-53. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x 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 x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x None Page 9 Milne Point Unit S-53 SB Injector Drilling Program Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 9-7/8” & 6-3/4” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit S-53 SB Injector Drilling Program 9.0 R/U and Preparatory Work 9.1 S-53 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 Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 13-1/2” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit S-53 SB Injector Drilling Program 10.0 N/U Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit S-53 SB Injector Drilling Program 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit S-53 SB Injector Drilling Program 11.0 Drill 13-1/2” Hole Section 11.1 PU 13-1/2” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Use GWD until MWD surveys clean up and then swap to MWD. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 13-1/2” hole section to section TD in the SV1 shale. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 500-750 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x If the hole shows signs of being dirty, perform clean up cycles or reduce ROP (if packoff’s, increase in pump pressure, or changes in hookload are seen). x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x Adjust MW and viscosity as necessary to maintain hole stability. x Be prepared for gas hydrates. In MPU they have been encountered between 2,100’-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x 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 Page 14 Milne Point Unit S-53 SB Injector Drilling Program zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x 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. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 13-1/2” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface –Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: 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. x Rheology:MI Gel and CF Desco II should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: MI PAC UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of SCREENKLEEN 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 Busan 1060 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit S-53 SB Injector Drilling Program System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENKLEEN 55 gal dm 0.5 11.5 At TD, PU 2-3 stands off bottom to avoid washing out the hole. CBU, pump tandem sweeps, and drop viscosity. 11.6 RIH to bottom and begin BROOH to HWDP x Pump at full drill rate and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit S-53 SB Injector Drilling Program 12.0 Run 10-3/4” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 10-3/4” casing running equipment (CRT & Tongs) x Ensure 10-3/4” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 10-3/4” Float Shoe 1 joint – 10-3/4” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –10-3/4” TXP, 1 Centralizer mid joint w/ stop ring 10-3/4” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –10-3/4” TXP, 1 Centralizer mid joint with stop ring 10-3/4” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit S-53 SB Injector Drilling Program 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit S-53 SB Injector Drilling Program 12.6 Continue running 10-3/4” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x 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. 10-3/4” 45.5# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 10-3/4”20,370 ft-lbs 22,630 ft-lbs 24,890 ft-lbs Page 19 Milne Point Unit S-53 SB Injector Drilling Program Page 20 Milne Point Unit S-53 SB Injector Drilling Program 12.7 Continue running 10-3/4” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 12.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.9 Slow in and out of slips. 12.10 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. 12.11 Lower casing to setting depth. Confirm measurements. 12.12 Have slips staged in cellar, along with necessary equipment for the operation. 12.13 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 21 Milne Point Unit S-53 SB Injector Drilling Program 13.0 Cement 10-3/4” 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x 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. Page 22 Milne Point Unit S-53 SB Injector Drilling Program Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation is in the Stage 1 Table in step 13.7. 80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 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. 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. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 23 Milne Point Unit S-53 SB Injector Drilling Program 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.15 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. 13.16 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 24 Milne Point Unit S-53 SB Injector Drilling Program Second Stage Surface Cement Job: 13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.19 Fill surface lines with water and pressure test. 13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.21 Mix and pump cmt per below recipe for the 2 nd stage. 13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.25 Displacement is in the Stage 2 table in step 13.22. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 765.5 367.4 392.7 2204.5 2062.6 Page 25 Milne Point Unit S-53 SB Injector Drilling Program 13.26 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. 13.27 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 13.28 Make initial cut on final joint. L/D cut joint. Make final cut. Dress off stump. Install 10-3/4” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Milne Point Unit S-53 SB Injector Drilling Program 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x 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 x Double gate ram should be dressed with 7-5/8” FBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5” BOP test plug 14.4 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test FBR rams with 7-5/8” test joint x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 RD BOP test equipment 14.6 Set wearbushing in wellhead. 14.7 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.8 Ensure 5” liners in mud pumps. Page 27 Milne Point Unit S-53 SB Injector Drilling Program 15.0 Drill 9-7/8” Hole Section 15.1 P/U 9-7/8” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the intermediate hole section. 15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,210 / 2 = ~2,605 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. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 11.0 ppg FIT is the minimum required to drill ahead. x 11.0 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swab kick at 9.2ppg BHP). 15.7 Drill 9-7/8” hole section to section TD in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Well control procedures x Flow rates, hole cleaning, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500-620 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Perform clean up cycles as needed. Reduce ROP if packoffs, increase in pump pressure, or changes in hookload are seen. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x Intermediate Hole AC: x There are no wells with a clearance factor of <1.0 Page 28 Milne Point Unit S-53 SB Injector Drilling Program 15.8 9-7/8” hole mud program summary: x The base plan is to use an LSND mud system for the intermediate. x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. Depth Interval MW (ppg) SV1 - TD 8.8+ x PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x Rheology: MI GEL 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. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. x Wellbore and mud stability:Additions of SCREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. 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. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg LSND Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F 15.9 At TD, PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. Page 29 Milne Point Unit S-53 SB Injector Drilling Program 15.10 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 15.11 TOOH and LD BHA 15.12 No open hole logging program planned. Page 30 Milne Point Unit S-53 SB Injector Drilling Program 16.0 Run 7-5/8” Intermediate Casing 16.1 R/U and pull wearbushing. 16.2 R/U 7-5/8” casing running equipment x Ensure 7-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Plan to land the 7-5/8” casing on a mandrel hanger. 16.3 P/U shoe joint and visually verify no debris inside joint. 16.4 Continue M/U & thread locking 80’ shoe track assembly consisting of: 7-5/8” Float Shoe 1 joint – 7-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –7-5/8” TXP, 1 Centralizer mid joint with stop ring 7-5/8” Float Collar 16.5 Continue running 7-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 500’ MD above Schrader Bluff x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. 7-5/8” 29.7# L-80 563 Make-Up Torques: Casing OD Minimum Optimum Maximum 7-5/8”8,600 ft-lbs 10,300 ft-lbs 15,100 ft-lbs Page 31 Milne Point Unit S-53 SB Injector Drilling Program Page 32 Milne Point Unit S-53 SB Injector Drilling Program 16.6 Continue running 7-5/8” casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 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. 16.10 Lower casing to setting depth. Confirm measurements. 16.11 Have emergency slips staged along with necessary equipment for the operation. 16.12 Circulate and condition mud through CRT. Ensure MW does not exceed 9.1ppg. 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 33 Milne Point Unit S-53 SB Injector Drilling Program 17.0 Cement 7-5/8” Surface Casing 17.1 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. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 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. 17.4 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. 17.5 Fill surface lines with water and pressure test. 17.6 Pump remaining 30 bbls 10 ppg tuned spacer. 17.7 Mix and pump cmt per below recipe. 17.8 Cement volume based on annular volume + open hole excess (30%). Job will consist of tail, TOC brought to 500’ MD above the Ugnu LA3.Note: If the Ugnu LA3 is wet, TOC may be pushed deeper. If Hilcorp wants to deepen the TOC, Hilcorp will submit the LWD data to the AOGCC staff for approval. If the TOC will remain 500’ MD above the LA3, no additional approval from the AOGCC will be sought. Estimated Total Cement Volume: NOTE: Per 20 AAC 25.030(d)(5), TOC must be brought to 500' MD or 250' TVD, whichever is greater, above all significant hydrocarbon zones. Provide field-quality LWD data in .las and .pdf format to AOGCC for review before beginning cementing operations. SFD Page 34 Milne Point Unit S-53 SB Injector Drilling Program Cement Slurry Design: 17.9 After pumping cement, drop top plug and displace cement with mud out of mud pits. 17.10 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.11 Land top plug on stage collar and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 17.12 Lay down any remaining 5” DP. Swap handling equipment over to 4”. 17.13 Rig up e-line to run a CBL. Include a tractor and a temperature log. a. Contact OE to confirm the tractor provider. b. Do not begin logging with the CBL until cement has reached 500 psi compressive strength. c. Sent the results to the drilling engineer and operations engineer immediately upon receiving them. Tail Slurry System HalCem Density 14.8 lb/gal Yield 1.332 ft3/sk Mixed Water 6.293 gal/sk Page 35 Milne Point Unit S-53 SB Injector Drilling Program 18.0 Drill 6-3/4” Hole Section Note: After the intermediate cement has developed 500 psi compressive strength, bullhead freeze protect fluids into the 10-3/4” x 7-5/8” annulus to 100’ TVD below the permafrost. DO NOT PUMP MORE THAN 1.1X THE ANNULUS VOLUME (calculated from the 10-3/4” shoe). 18.1 PU 6-3/4” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 4” 14.0# S-135 HT38 or XT39. x Run a ported float in the production hole section. 18.2 TIH w/ 6-3/4” BHA to shoetrack. Note depth TOC tagged on AM report. 18.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 6,890 / 2 = ~3,445 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. 18.4 Drill out shoe track and 20’ of new formation. 18.5 CBU and condition mud for FIT. 18.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.7 ppg FIT is the minimum required to drill ahead x 9.7 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swab kick at 9.2ppg BHP) 18.7 POOH and LD cleanout BHA 18.8 6-3/4” hole section mud program summary: x 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. Page 36 Milne Point Unit S-53 SB Injector Drilling Program x 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. x Rheology: Keep viscosifier additions to an absolute minimum. Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 6.75 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole as this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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:8.8 – 9.8 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.8-9.8 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 18.9 TIH with 6-3/4” directional assembly to bottom 18.10 Install MPD RCD Page 37 Milne Point Unit S-53 SB Injector Drilling Program 18.11 Displace wellbore to 8.8 ppg FloPro drilling fluid 18.12 Begin drilling 6-3/4” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 18.13 Drill 6-3/4” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 200-300 GPM, target min. AV’s 200 ft/min, 250 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Check for holes in screens on every connection. x Take MWD surveys every stand. Surveys can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor torque and drag with pumps on every stand (confirm frequency with co-man) x Monitor ECD, pump pressure & hookload trends for indications of poor hole cleaning x Good drilling and tripping practices are vital to avoid differential sticking. Make every effort to minimize static periods. x Use ADR to stay in section. Reservoir plan is to stay in NB sand. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff NB Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 6-3/4” Lateral A/C: x MPU S-08 has a 0.055 CF. S-08 is a Schrader jet pump producer that will be shut- in. There is no HSE risk. 18.14 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 18.15 At TD, CBU 4 times (minimum) at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary Page 38 Milne Point Unit S-53 SB Injector Drilling Program 18.16 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. 18.17 Displace 1.5 OH + liner volume with +/- 8.45ppg viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: As needed for 8.45 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 18.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 18.18 BROOH with the drilling assembly to the 7-5/8” casing shoe x Circulate at full drill rate (less if losses are seen). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 18.19 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 18.20 CBU minimum two times at 7-5/8” shoe and clean casing with high vis sweeps. Continue circulated as long as needed to clean up the casing.Expect to have cuttings beds in the high angle portions of the intermediate casing! Page 39 Milne Point Unit S-53 SB Injector Drilling Program 18.21 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise. x If necessary, increase MW at shoe for any higher than expected pressure seen. x Ensure fluid coming out of hole has passed a PST at the possum belly. 18.22 POOH and LD BHA. 18.23 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, 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 40 Milne Point Unit S-53 SB Injector Drilling Program 19.0 Run 4-1/2” Injection Liner 19.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” liner, the following well control response procedure will be followed: x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. 19.2 Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high. 19.3 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.4 Run 4-1/2” injection liner x Injection liner will be a combination of slotted and solid joints. Every third joint in the open hole is to be a slotted joint. Confirm with OE. x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2” 13.5# L-80 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 41 Milne Point Unit S-53 SB Injector Drilling Program Page 42 Milne Point Unit S-53 SB Injector Drilling Program 19.6. Ensure to run enough liner to provide for approx 150’ overlap inside 7-5/8” casing. Ensure hanger/pkr will not be set in a 7-5/8” connection. x 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 10-3/4” connection. 19.7. Before picking up Baker liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.8. M/U Baker liner top packer assembly to 4-1/2” liner. 19.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 19.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 4” DP/HWDP has been drifted 19.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 19.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 19.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 19.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 19.15. Rig up to pump down the work string with the rig pumps. 19.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 19.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 19.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 43 Milne Point Unit S-53 SB Injector Drilling Program 19.19. Continue pressuring up to 2,700 psi to set the liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the liner hanger/packer to ensure the setting tool is in compression for release from the liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 19.20. Bleed DP pressure to 0 psi. 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. 19.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.22. Bleed off pressure and open BOPE. Pickup to verify that the 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. 19.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 19.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 44 Milne Point Unit S-53 SB Injector Drilling Program 20.0 Run 3-1/2” Tubing (Upper Completion) 20.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 20.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD (Set below 70 degrees) x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” SGM-FS XDPG Gauge at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down 20.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. Page 45 Milne Point Unit S-53 SB Injector Drilling Program 20.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. 20.5 Makeup the tubing hanger and landing joint. 20.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 20.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 20.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel. 20.9 Land hanger. RILDs and test hanger. 20.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes. i.Provide proper notification to the AOGCC for the right to witness the test. ii. Complete form 10-426 and submit to the required recipients. Copy nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail. 20.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.12 Pull BPV. Set TWC. Test tree to 5000 psi. 20.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 20.14 Secure the tree and cellar. Page 46 Milne Point Unit S-53 SB Injector Drilling Program 21.0 Doyon 14 Diverter Schematic Page 47 Milne Point Unit S-53 SB Injector Drilling Program 22.0 Doyon 14 BOP Schematic 7-5/8” FBR 2-7/8” x 5” VBRs Page 48 Milne Point Unit S-53 SB Injector Drilling Program 23.0 Wellhead Schematic 3 3 Page 49 Milne Point Unit S-53 SB Injector Drilling Program 24.0 Days Vs Depth Page 50 Milne Point Unit S-53 SB Injector Drilling Program 25.0 Formation Tops & Information Formations TVD (ft) MD (ft) Formation Pressure (psi) EMW (ppg) BPRF 1578 2141 694 8.46 SV1 2252 5346 991 8.46 UG4A 2577 5788 1134 8.46 Ugnu LA3 3451 6827 1518 8.46 UG_MB 3702 7205 1629 8.46 SCHRADER NB 3955 8130 1740 8.46 Page 51 Milne Point Unit S-53 SB Injector Drilling Program S-pad Data Sheet Formation Description Page 52 Milne Point Unit S-53 SB Injector Drilling Program 26.0 Anticipated Drilling Hazards 13-1/2” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates are generally not seen on S-pad. Remember that hydrate gas behaves 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. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 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. Page 53 Milne Point Unit S-53 SB Injector Drilling Program H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 54 Milne Point Unit S-53 SB Injector Drilling Program 9-7/8” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 55 Milne Point Unit S-53 SB Injector Drilling Program 6-3/4” 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 are multiple planned fault crossings for S-53. The maximum expected throw for a fault is 50’ on the fault crossed mid-lateral. H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: x MPU S-08 has a 0.055 CF. S-08 is a Schrader jet pump producer that will be shut-in. There is no HSE risk. Page 56 Milne Point Unit S-53 SB Injector Drilling Program 27.0 Doyon 14 Rig Layout Page 57 Milne Point Unit S-53 SB Injector Drilling Program 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. 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 58 Milne Point Unit S-53 SB Injector Drilling Program 29.0 Doyon 14 Rig Choke Manifold Schematic Page 59 Milne Point Unit S-53 SB Injector Drilling Program 30.0 Casing Design Page 60 Milne Point Unit S-53 SB Injector Drilling Program 31.0 9-7/8” Hole Section MASP Page 61 Milne Point Unit S-53 SB Injector Drilling Program 32.0 6-3/4” Hole Section MASP Page 62 Milne Point Unit S-53 SB Injector Drilling Program 33.0 Spider Plot (NAD 27) (Governmental Sections) Page 63 Milne Point Unit S-53 SB Injector Drilling Program 34.0 Surface Plat (As-Staked) (NAD 27) 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU S-53 Hilcorp Alaska, LLC Permit to Drill Number: 224-159 Surface Location: 3205' FSL, 591' FEL, Sec 12, T12N, R10E, UM, AK Bottomhole Location: 702' FNL, 1683' FWL, Sec 06, T12N, R11E, UM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 2th day of January 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.28 16:00:26 -09'00' Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.20 09:06:23 - 09'00' Sean McLaughlin (4311) By Grace Christianson at 9:44 am, Dec 20, 2024 * BOPE test to 3000 psi. Annular to 2500 psi. * MIT-IA to 3500 psi. 24 hour notice. * MIT-IA to 2000 psi after 10 days of stabilized injection. * 7-5/8" cement evaluation log to AOGCC upon completion of log. * Documented well control drills for all crews running slotted liners with safety joints spaced out across BOPE. 224-159 MGR02JAN2024 DSR-12/20/24 50-029-23811-00-00 Pre-production not allowed without spacing exception. A.Dewhurst 27JAN25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.28 16:00:43 -09'00' 01/28/25 01/28/25 RBDMS JSB 013025 Area of Review MPS-44PTDAPI WELL STATUSTop of SB NB(MD)Top of SB NB(TVD)Top of Cement(MD)Top of Cement(TVD)Schrader NBstatus Zonal Isolation202-137 50-029-23100-00-00 MPU S-05 OB Producer 4,854 3,985 Surface Surface ClosedThey pumped 990 bbls of 10.7ppg lead and 43 bbls of 15.8ppg tail cement. They reported 100 bblsof contaminated cement and 60 bbls of good 10.7ppg cement returned to surface.202-138 50-029-23100-60-00 MPU S-05L1 OA Producer 4,854 3,985 Surface Surface ClosedThey pumped 990 bbls of 10.7ppg lead and 43 bbls of 15.8ppg tail cement. They reported 100 bblsof contaminated cement and 60 bbls of good 10.7ppg cement returned to surface.202-137 50-029-23100-70-00 MPU S-05PB1 Plug Back 4,854 3,985 Surface Surface ClosedThey pumped 990 bbls of 10.7ppg lead and 43 bbls of 15.8ppg tail cement. They reported 100 bblsof contaminated cement and 60 bbls of good 10.7ppg cement returned to surface.203-123 50-029-23168-00-00 MPU S-08 NB Producer 5,242 3,992 3,090 2,676 OpenThey pumped 990 bbls of 10.7ppg lead and 43 bbls of 15.8ppg tail cement. They reported 100 bblsof contaminated cement and 60 bbls of good 10.7ppg cement returned to surface.203-123 50-029-23168-70-00 MPU S-08PB1 Plug Back 5,242 3,992 3,090 2,676 OpenThey pumped 990 bbls of 10.7ppg lead and 43 bbls of 15.8ppg tail cement. They reported 100 bblsof contaminated cement and 60 bbls of good 10.7ppg cement returned to surface.205-125 50-029-23152-01-00 MPU S-10A OA/OB Injector 5,405 4,023 3,807 3,109 ClosedThe 7" casing was cemented with 387 sx inside 8-3/4" hole. The drilling report notes full returnsthroughout the job. Assuming 20% washout, TOC is 3807' MD.202-113 50-029-23092-00-00 MPU S-11 NB/OA/OB Injector 5,374 4,003 Surface Surface OpenThe 7" casing was cemented with 1290 sx of 10.7ppg lead and 500 sx of 15.8ppg tail. Theycirculated 336 bbls of cement to surface.203-023 50-029-23139-00-00 MPU S-12 OB Producer 4,850 3,981 3,056 3,019 ClosedThe 7-5/8" was cemented with 49 bbls of 12.0ppg lead and 85 bbls of 15.6ppg tail cement inside 9-7/8" hole. The drilling report notes full returns throughout the job. Assuming 20% washout, TOC is3056' MD.203-024 50-029-23139-60-00 MPU S-12L1 OA Producer 4,850 3,981 3,056 3,019 ClosedThe 7-5/8" was cemented with 49 bbls of 12.0ppg lead and 85 bbls of 15.6ppg tail cement inside 9-7/8" hole. The drilling report notes full returns throughout the job. Assuming 20% washout, TOC is3056' MD.203-023 50-029-23139-70-00 MPU S-12PB1 Plug Back 4,850 3,981 3,056 3,019 ClosedThe 7-5/8" was cemented with 49 bbls of 12.0ppg lead and 85 bbls of 15.6ppg tail cement inside 9-7/8" hole. The drilling report notes full returns throughout the job. Assuming 20% washout, TOC is3056' MD.201-245 50-029-23061-00-00 MPU S-15 OA/OB Injector 4,401 4,179 Surface Surface ClosedThe 7" casing was cemented with 500 sx of 10.7ppg lead and 225 sx of 15.8ppg tail. They circulated80 bbls of cement to surface.202-204 50-029-23121-00-00 MPU S-19 OA Producer - Abandoned 7,523 4,237 5,085 3,157 ClosedThe 7" casing was cemented with 29 bbls of 10.0ppg lead and 56 bbls of 15.8ppg tail inside 8-1/2"hole. Assuming 20% washout, TOC is 5085' MD.202-233 50-029-23121-01-00 MPU S-19A OA Producer 7,540 4,240 5,085 3,157 ClosedThe 7" casing was cemented with 29 bbls of 10.0ppg lead and 56 bbls of 15.8ppg tail inside 8-1/2"hole. Assuming 20% washout, TOC is 5085' MD.202-234 50-029-23121-60-00 MPU S-19AL1 OA Producer 7,540 4,240 5,085 3,157 ClosedThe 7" casing was cemented with 29 bbls of 10.0ppg lead and 56 bbls of 15.8ppg tail inside 8-1/2"hole. Assuming 20% washout, TOC is 5085' MD.202-233 50-029-23121-70-00 MPU S-19APB1 Plug Back 7,540 4,240 5,085 3,157 ClosedThe 7" casing was cemented with 29 bbls of 10.0ppg lead and 56 bbls of 15.8ppg tail inside 8-1/2"hole. Assuming 20% washout, TOC is 5085' MD.207-052 50-029-23355-00-00 MPU S-37 Ugnu 4,400 3,993 3,372 3,041 ClosedThe 7" casing was cemented with 61.3 bbls of 15.8ppg tail inside 8-1/2" hole. Assuming 20%washout, TOC is 2641' MD. They opened the ES cementer at 3372' MD to circulate in CI and freezeprotect fluids. They noted cement in the returns while circulating seawater prior to pumping the CIand FP.208-159 50-029-23401-00-00 MPU S-41 Ugnu - Abandoned 4,945 3,982 4,045 3,426 ClosedThe 7" liner was cemented with 186 sx of 15.8ppg cement inside 8-1/2" hole. They cut the 7" at4,277' MD and abandoned the well with a 17 ppg cement plug to 4045' MD.208-176 50-029-23404-00-00 MPU S-43 Ugnu 4,861 3,992 4,081 3,378 ClosedThe 7" liner was cemented with 41 bbls of 15.8ppg tail inside 8-1/2" hole. The drilling report notes 9bbls of cement off the top of the liner (4081' MD).200-186 50-029-22867-01-00 MPU E-24A OB Producer 8,978 4,161 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 164 bbls of good cement back to surface.200-187 50-029-22867-60-00 MPU E-24AL1 OA Producer 8,978 4,161 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 164 bbls of good cement back to surface.219-096 50-029-23640-00-00 MPU E-39 OA Injector 7,700 4,209 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 294 bbls of good cement back to surface.219-099 50-029-23640-60-00 MPU E-39L1 OB Injector 7,700 4,209 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 294 bbls of good cement back to surface.219-082 50-029-23635-00-00 MPU E-42 OB Injector 7,302 4,228 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 406 bbls of good cement back to surface.219-091 50-029-23635-60-00 MPU E-42L1 OA Injector 7,302 4,228 Surface Surface ClosedThe 9-5/8" was cemented via a two stage cement job with full returns during both stages. Thedrilling report notes 406 bbls of good cement back to surface. Milne Point Unit (MPU) S-53 Application for Permit to Drill Version 1 12/6/2024 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 Diverter System ............................................................................................................... 11 11.0 Drill 13-1/2” Hole Section ....................................................................................................... 13 12.0 Run 10-3/4” Surface Casing ................................................................................................... 16 13.0 Cement 10-3/4” Surface Casing .............................................................................................. 19 14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 22 15.0 Drill 9-7/8” Hole Section ......................................................................................................... 23 16.0 Run 7-5/8” Intermediate Casing ............................................................................................. 26 17.0 Cement 7-5/8” Surface Casing ................................................................................................ 29 18.0 Drill 6-3/4” Hole Section ......................................................................................................... 31 19.0 Run 4-1/2” Injection Liner ..................................................................................................... 36 20.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 40 21.0 Doyon 14 Diverter Schematic ................................................................................................. 42 22.0 Doyon 14 BOP Schematic ....................................................................................................... 43 23.0 Wellhead Schematic ................................................................................................................ 44 24.0 Days Vs Depth ......................................................................................................................... 45 25.0 Formation Tops & Information.............................................................................................. 46 26.0 Anticipated Drilling Hazards ................................................................................................. 48 27.0 Doyon 14 Rig Layout .............................................................................................................. 52 28.0 FIT Procedure ......................................................................................................................... 53 29.0 Doyon 14 Rig Choke Manifold Schematic .............................................................................. 54 30.0 Casing Design .......................................................................................................................... 55 31.0 9-7/8” Hole Section MASP ...................................................................................................... 56 32.0 6-3/4” Hole Section MASP ...................................................................................................... 57 33.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 58 34.0 Surface Plat (As-Staked) (NAD 27) ........................................................................................ 59 Page 2 Milne Point Unit S-53 SB Injector Drilling Program 1.0 Well Summary Well MPU S-53 Pad Milne Point “S” Pad Planned Completion Type Injection Tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 18,076’ MD / 4,061’ TVD PBTD, MD / TVD 18,076’ MD / 4,061’ TVD Surface Location (Governmental) 2075’ FNL, 591’ FEL, Sec. 12, T12N, R10E, UM, AK Surface Location (NAD 27) X= 565421, Y=5999869 Top of Productive Horizon (Governmental)20’ FSL, 888’ FWL, Sec. 7, T12N, R11E, UM, AK TPH Location (NAD 27) X= 566927, Y=5996697 BHL (Governmental) 702' FNL, 1683' FWL, Sec 6, T12N, R11E, UM, AK BHL (NAD 27) X= 567635, Y= 6006542 AFE Drilling Days 23 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 1345 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1740 psig Work String 5” 19.5# S-135 NC 50 4” 14.0# S-135 XT 39 Doyon 14 KB Elevation above MSL: 33.7 ft + 36.6 ft = 70.3 ft GL Elevation above MSL: 36.6 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit S-53 SB Injector Drilling Program 2.0 Management of Change Information Page 4 Milne Point Unit S-53 SB Injector Drilling Program 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 13-1/2” 10-3/4” 9.950”9.794”11.75”45.5 L-80 TXP 5,210 2,470 1040 9-7/8 7-5/8” 6.875” 6.750” 8.500” 29.7 L-80 TXP 6,890 4,790 683 6-3/4” 4-1/2” 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Intermediate 5” 4.276” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560 Production 4” 3.34” 2.5625” 4.875” 14 S-135 XT39 18,500 22,200 403 4” 3.34” 2.5625 4.875 14 S-135 HT38 12,200 17,700 403 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit S-53 SB Injector Drilling Program 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6 am to 6 am x 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. x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp.com, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Completion Engineer Ryan Lewis Ryan.lewis@hilcorp.com Geologist Patrick Boyle 907.564.4649 Patrick.boyle@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 Adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit S-53 SB Injector Drilling Program 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit S-53 SB Injector Drilling Program 7.0 Drilling / Completion Summary MPU S-53 is a grassroots producer planned to be drilled in the Schrader Bluff NB sand. S-53 is part of a multi well program targeting the Schrader Bluff sand on S-pad The directional plan is 13-1/2” surface hole with 10-3/4” surface casing set in the lower SV’s. The 9-7/8” intermediate hole will use 7-5/8” intermediate casing set in the top of the Schrader Bluff NB sand. A 6-3/4” lateral section will be drilled and completed with a 4-1/2” liner. The well will be completed with injection tubing. Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately February 10th, 2025, pending rig schedule. Surface casing will be run to 5,437’ MD / 2,312’ TVD and cemented to surface. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will be discussed with AOGCC authorities. Intermediate casing will be run to 8,150’ MD / 3,957’ TVD and cemented to 500’ MD above the hydrocarbon bearing Schrader Bluff formation. TOC will be verified with a CBL. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 13-1/2” hole to TD of surface hole section. 4. Run and cement 10-3/4” surface casing 5. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 6. Drill 9-7/8” intermediate to TD. 7. Run and cement 7-5/8” intermediate casing. 8. Run e-line conveyed CBL to confirm TOC. 9. Drill 6-3/4” lateral to well TD 10. Run 4-1/2” injection liner 11. Run Upper Completion 12. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res 2. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 3. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Injector-DSR 1/22/25 Page 8 Milne Point Unit S-53 SB Injector Drilling Program 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU S-53. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x 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 x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x None Page 9 Milne Point Unit S-53 SB Injector Drilling Program Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 9-7/8” & 6-3/4” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit S-53 SB Injector Drilling Program 9.0 R/U and Preparatory Work 9.1 S-53 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 Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 13-1/2” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 Milne Point Unit S-53 SB Injector Drilling Program 10.0 N/U Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit S-53 SB Injector Drilling Program 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit S-53 SB Injector Drilling Program 11.0 Drill 13-1/2” Hole Section 11.1 PU 13-1/2” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Use GWD until MWD surveys clean up and then swap to MWD. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 13-1/2” hole section to section TD in the SV1 shale. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 500-750 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x If the hole shows signs of being dirty, perform clean up cycles or reduce ROP (if packoff’s, increase in pump pressure, or changes in hookload are seen). x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x Adjust MW and viscosity as necessary to maintain hole stability. x Be prepared for gas hydrates. In MPU they have been encountered between 2,100’-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x 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 Page 14 Milne Point Unit S-53 SB Injector Drilling Program zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x 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. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 13-1/2” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface –Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: 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. x Rheology:MI Gel and CF Desco II should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: MI PAC UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of SCREENKLEEN 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 Busan 1060 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 15 Milne Point Unit S-53 SB Injector Drilling Program System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENKLEEN 55 gal dm 0.5 11.5 At TD, PU 2-3 stands off bottom to avoid washing out the hole. CBU, pump tandem sweeps, and drop viscosity. 11.6 RIH to bottom and begin BROOH to HWDP x Pump at full drill rate and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit S-53 SB Injector Drilling Program 12.0 Run 10-3/4” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 10-3/4” casing running equipment (CRT & Tongs) x Ensure 10-3/4” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 10-3/4” Float Shoe 1 joint – 10-3/4” TXP, 2 Centralizers 10’ from each end w/ stop ring 1 joint –10-3/4” TXP, 1 Centralizer mid joint w/ stop ring 1 joint – 10-3/4” TXP, 1 Centralizer mid joint w/ stop ring 10-3/4” Float Collar 12.5 Continue running 10-3/4” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x 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. 10-3/4” 45.5# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 10-3/4”20,370 ft-lbs 22,630 ft-lbs 24,890 ft-lbs Page 17 Milne Point Unit S-53 SB Injector Drilling Program Page 18 Milne Point Unit S-53 SB Injector Drilling Program 12.6 Continue running 10-3/4” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 12.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.8 Slow in and out of slips. 12.9 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. 12.10 Lower casing to setting depth. Confirm measurements. 12.11 Have slips staged in cellar, along with necessary equipment for the operation. 12.12 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 19 Milne Point Unit S-53 SB Injector Drilling Program 13.0 Cement 10-3/4” 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x 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 10.0 ppg tuned spacer. 13.7 Drop bottom plug. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached.Drop another bottom plug between the lead and tail slurries. 13.8 Cement volume based on annular volume + 30% open hole excess below the permafrost and 200% excess in the permafrost. Job will consist of lead & tail, TOC brought to stage tool. Estimated Cement Volume: surface -See attached emails. A.Dewhurst 22JAN25 Page 20 Milne Point Unit S-53 SB Injector Drilling Program Cement Slurry Design 13.9 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. 13.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. 13.12 Displacement calculation is in step 13.8 above. 13.13 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. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume before consulting with Drilling Engineer. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 13.16 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. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.86 ft3/sk 1.17 ft3/sk Mix Water 22.02 gal/sk 5.08 gal/sk Page 21 Milne Point Unit S-53 SB Injector Drilling Program 13.17 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. 13.18 Bump plug. Check floats. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips. 13.19 Make initial cut on 10-3/4” final joint. L/D cut joint. Make final cut on 10-3/4”. Dress off stump. Install 10-3/4” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 22 Milne Point Unit S-53 SB Injector Drilling Program 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x 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 x Double gate ram should be dressed with 7-5/8” FBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 Run 5” BOP test plug 14.4 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test FBR rams with 7-5/8” test joint x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 RD BOP test equipment 14.6 Set wearbushing in wellhead. 14.7 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.8 Ensure 5” liners in mud pumps. Page 23 Milne Point Unit S-53 SB Injector Drilling Program 15.0 Drill 9-7/8” Hole Section 15.1 P/U 9-7/8” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the intermediate hole section. 15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,210 / 2 = ~2,605 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. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 11.0 ppg FIT is the minimum required to drill ahead. x 11.0 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swab kick at 9.2ppg BHP). 15.7 Drill 9-7/8” hole section to section TD in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Well control procedures x Flow rates, hole cleaning, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500-620 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Perform clean up cycles as needed. Reduce ROP if packoffs, increase in pump pressure, or changes in hookload are seen. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x Intermediate Hole AC: x There are no wells with a clearance factor of <1.0 * Email digital data for casing test and FIT to AOGCC upon completion of FIT. - mgr Page 24 Milne Point Unit S-53 SB Injector Drilling Program 15.8 9-7/8” hole mud program summary: x The base plan is to use an LSND mud system for the intermediate. x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. Depth Interval MW (ppg) SV1 - TD 8.8+ x PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x Rheology: MI GEL 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. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. x Wellbore and mud stability:Additions of SCREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. 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. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg LSND Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F 15.9 At TD, PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. Page 25 Milne Point Unit S-53 SB Injector Drilling Program 15.10 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 15.11 TOOH and LD BHA 15.12 No open hole logging program planned. Page 26 Milne Point Unit S-53 SB Injector Drilling Program 16.0 Run 7-5/8” Intermediate Casing 16.1 R/U and pull wearbushing. 16.2 R/U 7-5/8” casing running equipment x Ensure 7-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Plan to land the 7-5/8” casing on a mandrel hanger. 16.3 P/U shoe joint and visually verify no debris inside joint. 16.4 Continue M/U & thread locking 80’ shoe track assembly consisting of: 7-5/8” Float Shoe 1 joint – 7-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –7-5/8” TXP, 1 Centralizer mid joint with stop ring 7-5/8” Float Collar 16.5 Continue running 7-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 500’ MD above Schrader Bluff x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. 7-5/8” 29.7# L-80 563 Make-Up Torques: Casing OD Minimum Optimum Maximum 7-5/8”8,600 ft-lbs 10,300 ft-lbs 15,100 ft-lbs Page 27 Milne Point Unit S-53 SB Injector Drilling Program Page 28 Milne Point Unit S-53 SB Injector Drilling Program 16.6 Continue running 7-5/8” casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 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. 16.10 Lower casing to setting depth. Confirm measurements. 16.11 Have emergency slips staged along with necessary equipment for the operation. 16.12 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 29 Milne Point Unit S-53 SB Injector Drilling Program 17.0 Cement 7-5/8” Surface Casing 17.1 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. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 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. 17.4 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. 17.5 Fill surface lines with water and pressure test. 17.6 Pump remaining 60 bbls 11 ppg tuned spacer. 17.7 Mix and pump cmt per below recipe. 17.8 Cement volume based on annular volume + open hole excess (40%). Job will consist of tail, TOC brought to 500’ above the Schrader Bluff (top of Schrader NA is 7,760’ MD). Estimated Total Cement Volume: Cement Slurry Design (2nd stage cement job): 17.9 After pumping cement, drop top plug and displace cement with mud out of mud pits. 17.10 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.17 ft3/sk Mixed Water 5.08 gal/sk Intermediate - mgr Page 30 Milne Point Unit S-53 SB Injector Drilling Program 17.11 Land top plug on stage collar and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 17.12 Lay down any remaining 5” DP. Swap handling equipment over to 4”. 17.13 Rig up e-line to run a CBL. Include a tractor and a temperature log. a. Contact OE to confirm the tractor provider. b. Do not begin logging with the CBL until cement has reached 500 psi compressive strength. c. Sent the results to the drilling engineer and operations engineer immediately upon receiving them. Page 31 Milne Point Unit S-53 SB Injector Drilling Program 18.0 Drill 6-3/4” Hole Section Note: After the intermediate cement has developed 500 psi compressive strength, bullhead freeze protect fluids into the 10-3/4” x 7-5/8” annulus to 100’ TVD below the permafrost. DO NOT PUMP MORE THAN 1.1X THE ANNULUS VOLUME (calculated from the 10-3/4” shoe). 18.1 PU 6-3/4” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 4” 14.0# S-135 HT38 or XT39. x Run a ported float in the production hole section. 18.2 TIH w/ 6-3/4” BHA to shoetrack. Note depth TOC tagged on AM report. 18.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 6,890 / 2 = ~3,445 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. 18.4 Drill out shoe track and 20’ of new formation. 18.5 CBU and condition mud for FIT. 18.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.7 ppg FIT is the minimum required to drill ahead x 9.7 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swab kick at 9.2ppg BHP) 18.7 POOH and LD cleanout BHA 18.8 6-3/4” hole section mud program summary: x 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. Drill string will be 4” 14.0# S-135 HT38 or XT39 * Email digital data for casing test and FIT to AOGCC upon completion of FIT. - mgr Page 32 Milne Point Unit S-53 SB Injector Drilling Program x 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. x Rheology: Keep viscosifier additions to an absolute minimum. Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 6.75 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole as this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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:8.8 – 9.8 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.8-9.8 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 18.9 TIH with 6-3/4” directional assembly to bottom 18.10 Install MPD RCD Page 33 Milne Point Unit S-53 SB Injector Drilling Program 18.11 Displace wellbore to 8.8 ppg FloPro drilling fluid 18.12 Begin drilling 6-3/4” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 18.13 Drill 6-3/4” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 200-300 GPM, target min. AV’s 200 ft/min, 250 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Check for holes in screens on every connection. x Take MWD surveys every stand. Surveys can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor torque and drag with pumps on every stand (confirm frequency with co-man) x Monitor ECD, pump pressure & hookload trends for indications of poor hole cleaning x Good drilling and tripping practices are vital to avoid differential sticking. Make every effort to minimize static periods. x Use ADR to stay in section. Reservoir plan is to stay in NB sand. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff NB Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 6-3/4” Lateral A/C: x MPU S-08 has a 0.055 CF. S-08 is a Schrader jet pump producer that will be shut- in. There is no HSE risk. 18.14 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 18.15 At TD, CBU 4 times (minimum) at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary Page 34 Milne Point Unit S-53 SB Injector Drilling Program 18.16 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. 18.17 Displace 1.5 OH + liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg (note: adjust density based on B-36 learnings) Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 18.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 18.18 BROOH with the drilling assembly to the 7-5/8” casing shoe x Circulate at full drill rate (less if losses are seen). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 18.19 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 18.20 CBU minimum two times at 7-5/8” shoe and clean casing with high vis sweeps. Continue circulated as long as needed to clean up the casing.Expect to have cuttings beds in the high angle portions of the intermediate casing! Page 35 Milne Point Unit S-53 SB Injector Drilling Program 18.21 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise. x If necessary, increase MW at shoe for any higher than expected pressure seen. x Ensure fluid coming out of hole has passed a PST at the possum belly. 18.22 POOH and LD BHA. 18.23 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, 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 36 Milne Point Unit S-53 SB Injector Drilling Program 19.0 Run 4-1/2” Injection Liner 19.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” liner, the following well control response procedure will be followed: x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. 19.2 Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high. 19.3 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.4 Run 4-1/2” injection liner x Injection liner will be a combination of slotted and solid joints. Every third joint in the open hole is to be a slotted joint. Confirm with OE. x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2” 13.5# L-80 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs * Conduct and document well control drills utilizing safety joint for running slotted liner. - mgr Page 37 Milne Point Unit S-53 SB Injector Drilling Program Page 38 Milne Point Unit S-53 SB Injector Drilling Program 19.6. Ensure to run enough liner to provide for approx 150’ overlap inside 7-5/8” casing. Ensure hanger/pkr will not be set in a 7-5/8” connection. x 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 10-3/4” connection. 19.7. Before picking up Baker liner hanger / packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.8. M/U Baker liner top packer assembly to 4-1/2” liner. 19.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 19.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 4” DP/HWDP has been drifted 19.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 19.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 19.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 19.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 19.15. Rig up to pump down the work string with the rig pumps. 19.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 19.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 19.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 39 Milne Point Unit S-53 SB Injector Drilling Program 19.19. Continue pressuring up to 2,700 psi to set the liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the liner hanger/packer to ensure the setting tool is in compression for release from the liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 19.20. Bleed DP pressure to 0 psi. 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. 19.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.22. Bleed off pressure and open BOPE. Pickup to verify that the 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. 19.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 19.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 40 Milne Point Unit S-53 SB Injector Drilling Program 20.0 Run 3-1/2” Tubing (Upper Completion) 20.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 20.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD (Set below 70 degrees) x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” SGM-FS XDPG Gauge at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down 20.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. Page 41 Milne Point Unit S-53 SB Injector Drilling Program 20.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. 20.5 Makeup the tubing hanger and landing joint. 20.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 20.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 20.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel. 20.9 Land hanger. RILDs and test hanger. 20.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes. i.Provide proper notification to the AOGCC for the right to witness the test. ii. Complete form 10-426 and submit to the required recipients. Copy nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail. 20.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.12 Pull BPV. Set TWC. Test tree to 5000 psi. 20.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 20.14 Secure the tree and cellar. Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes. Page 42 Milne Point Unit S-53 SB Injector Drilling Program 21.0 Doyon 14 Diverter Schematic Page 43 Milne Point Unit S-53 SB Injector Drilling Program 22.0 Doyon 14 BOP Schematic 7-5/8” FBR 2-7/8” x 5” VBRs 10-3/4" Casing - mgr Page 44 Milne Point Unit S-53 SB Injector Drilling Program 23.0 Wellhead Schematic 3 3 20" Conductor -mgr Page 45 Milne Point Unit S-53 SB Injector Drilling Program 24.0 Days Vs Depth Page 49 Milne Point Unit S-53 SB Injector Drilling Program 25.0 Formation Tops & Information Formations TVD (ft) MD (ft) Formation Pressure (psi) EMW (ppg) BPRF 1578 2141 694 8.46 SV1 2252 5346 991 8.46 UG4A 2577 5788 1134 8.46 UG_MB 3702 7205 1629 8.46 SCHRADER NB 3955 8130 1740 8.46 Page 46 Milne Point Unit S-53 SB Injector Drilling Program 25.0 Formation Tops & Information Formations TVD (ft) MD (ft) Formation Pressure (psi) EMW (ppg) BPRF 1578 1750 694 8.46 SV1 2252 2182 991 8.46 UG4A 2577 2507 1134 8.46 UG_MB 3702 3632 1629 8.46 SCHRADER NB 3955 3885 1740 8.46 Superseded by corrected Formation Tops table. -A.Dewhurst 22JAN25 Page 47 Milne Point Unit S-53 SB Injector Drilling Program S-pad Data Sheet Formation Description Page 48 Milne Point Unit S-53 SB Injector Drilling Program 26.0 Anticipated Drilling Hazards 13-1/2” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates are generally not seen on S-pad. Remember that hydrate gas behaves 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. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 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. Page 49 Milne Point Unit S-53 SB Injector Drilling Program H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 50 Milne Point Unit S-53 SB Injector Drilling Program 9-7/8” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 51 Milne Point Unit S-53 SB Injector Drilling Program 6-3/4” 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 are multiple planned fault crossings for S-53. The maximum expected throw for a fault is 50’ on the fault crossed mid-lateral. H2S: Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S. Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9 ppm measured in 2012. S-39 had 2 ppm measured in 2014. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: x MPU S-08 has a 0.055 CF. S-08 is a Schrader jet pump producer that will be shut-in. There is no HSE risk.Have a reservoir plug. per email 07JAN2024 1118 am. - mgr Page 52 Milne Point Unit S-53 SB Injector Drilling Program 27.0 Doyon 14 Rig Layout Page 53 Milne Point Unit S-53 SB Injector Drilling Program 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. 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. Page54Milne Point UnitS-53 SB InjectorDrilling Program29.0 Doyon 14 Rig Choke Manifold Schematic Page 55 Milne Point Unit S-53 SB Injector Drilling Program 30.0 Casing Design Page 56 Milne Point Unit S-53 SB Injector Drilling Program 31.0 9-7/8” Hole Section MASP Page 57 Milne Point Unit S-53 SB Injector Drilling Program 32.0 6-3/4” Hole Section MASP Page 58 Milne Point Unit S-53 SB Injector Drilling Program 33.0 Spider Plot (NAD 27) (Governmental Sections) Page 59 Milne Point Unit S-53 SB Injector Drilling Program 34.0 Surface Plat (As-Staked) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 'HFHPEHU 3ODQ0386ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 3ODQ0386 0386 -7500750150022503000375045005250True Vertical Depth (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000Vertical Section at 18.86° (1500 usft/in)MPS-53 wp07 tgt4MPS-53 wp07 tgt2MPS-53 wp07 tgt8MPS-53 wp07 tgt7MPS-53 wp07 tgt3MPS-53 wp10 tgt1MPS-53 wp07 tgt6MPS-53 wp07 tgt510-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Casing500100015002 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 550060006500700075008000850090009500100001 050 01100011500120001250013000135001400014500150001550016000165001700 0 1 7 5 0 0 1 8 0 7 6MPU S-53 wp11Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4.5º/100' : 450' MD, 449.63'TVDEnd Dir : 2123.58' MD, 1575.44' TVDStart Dir 5º/100' : 4610.01' MD, 1951.74'TVDEnd Dir : 7896.14' MD, 3934.8' TVDBegin GeosteeringTotal Depth : 18075.85' MD, 4061.3' TVDSV6SV4PermafrostSV1UG4ALA3MBMDNBNBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU S-5336.60+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.005999869.18565420.79 70° 24' 36.3385 N 149° 28' 2.2894 WSURVEY PROGRAMDate: 2024-11-25T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU S-53 wp11 (MPU S-53) GYD_Quest GWD1500.00 5437.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag5437.00 8150.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag8150.00 18075.85 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+SagREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-53, True NorthVertical (TVD) Reference:MPU S-53 as staked @ 70.30usftMeasured Depth Reference:MPU S-53 as staked @ 70.30usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt S PadWell:Plan: MPU S-53Wellbore:MPU S-53Design:MPU S-53 wp11CASING DETAILSTVD TVDSS MD Size Name2312.25 2241.95 5437.00 10-3/4 10-3/4" Surface Casing3956.72 3886.42 8150.00 7-5/8 7-5/8" Intermediate Casing4061.30 3991.00 18075.85 4-1/2 4-1/2" Production CasingSECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 450.00 6.00 170.00 449.63 -10.30 1.82 3.00 170.00 -9.16 Start Dir 4.5º/100' : 450' MD, 449.63'TVD4 2123.58 81.30 174.12 1575.44 -1077.51 119.13 4.50 4.21 -981.12 End Dir : 2123.58' MD, 1575.44' TVD5 4610.01 81.30 174.12 1951.74 -3522.37 370.89 0.00 0.00 -3213.27 Start Dir 5º/100' : 4610.01' MD, 1951.74'TVD6 7896.14 85.00 1.79 3934.80 -3419.05 1471.52 5.00 -150.56 -2759.64 End Dir : 7896.14' MD, 3934.8' TVD7 8125.61 85.00 1.79 3954.80 -3190.56 1478.66 0.00 0.00 -2541.12 MPS-53 wp10 tgt18 8155.65 86.20 1.79 3957.10 -3160.63 1479.60 4.00 -0.08 -2512.499 8491.91 86.20 1.79 3979.38 -2825.26 1490.07 0.00 0.00 -2191.7510 8559.63 88.91 1.79 3982.27 -2757.65 1492.18 4.00 0.04 -2127.0911 10259.63 88.91 1.79 4014.61 -1058.79 1545.27 0.00 0.00 -502.30 MPS-53 wp07 tgt212 10459.59 92.75 0.67 4011.71 -858.93 1549.57 2.00 -16.19 -311.7913 10801.59 92.75 0.67 3995.30 -517.35 1553.60 0.00 0.00 12.75 MPS-53 wp07 tgt314 10985.14 89.10 0.31 3992.34 -333.87 1555.18 2.00 -174.32 186.8815 13713.62 89.10 0.31 4035.30 2394.24 1570.01 0.00 0.00 2773.26 MPS-53 wp07 tgt416 13860.23 88.70 357.41 4038.11 2540.78 1567.09 2.00 -97.75 2910.9817 14360.08 88.70 357.41 4049.42 3039.99 1544.47 0.00 0.00 3376.0718 14394.42 88.36 358.00 4050.30 3074.29 1543.09 2.00 120.05 3408.08 MPS-53 wp07 tgt519 14488.51 89.30 359.63 4052.22 3168.34 1541.15 2.00 60.17 3496.4520 14806.18 89.30 359.63 4056.12 3485.97 1539.11 0.00 0.00 3796.3721 14978.67 86.60 3.00 4062.30 3658.26 1543.07 2.50 128.76 3960.68 MPS-53 wp07 tgt622 15324.19 86.62 11.65 4082.77 4000.04 1587.01 2.50 90.13 4298.3123 16589.85 86.62 11.65 4157.40 5237.45 1842.22 0.00 0.00 5551.7724 16723.49 86.60 15.00 4165.30 5367.25 1872.96 2.50 90.44 5684.54 MPS-53 wp07 tgt725 17102.13 95.69 17.66 4157.76 5730.13 1979.28 2.50 16.32 6062.3126 18075.85 95.69 17.66 4061.30 6653.39 2273.26 0.00 0.00 7031.02 MPS-53 wp07 tgt8 Total Depth : 18075.85' MD, 4061.3' TVDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation853.05 782.75 870.45 SV61578.03 1507.73 2140.69 SV41820.30 1750.00 3741.50 Permafrost2252.11 2181.81 5345.87 SV12577.11 2506.81 5787.95 UG4A3451.41 3381.11 6827.06 LA33702.31 3632.01 7204.99 MB3762.21 3691.91 7317.71 MD3955.21 3884.91 8130.41 NB4078.19 4007.89 15246.63 NB -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 South(-)/North(+) (1200 usft/in)-3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 West(-)/East(+) (1200 usft/in) MPS-53 wp07 tgt5 MPS-53 wp07 tgt6 MPS-53 wp10 tgt1 MPS-53 wp07 tgt3 MPS-53 wp07 tgt7 MPS-53 wp07 tgt8 MPS-53 wp07 tgt2 MPS-53 wp07 tgt4 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Casing 7 5 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 27503 2 5 0 3500 3750 4000 4061 MPU S-53 wp11 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4.5º/100' : 450' MD, 449.63'TVD End Dir : 2123.58' MD, 1575.44' TVD Start Dir 5º/100' : 4610.01' MD, 1951.74'TVD End Dir : 7896.14' MD, 3934.8' TVD Begin Geosteering Total Depth : 18075.85' MD, 4061.3' TVD CASING DETAILS TVD TVDSS MD Size Name 2312.25 2241.95 5437.00 10-3/4 10-3/4" Surface Casing 3956.72 3886.42 8150.00 7-5/8 7-5/8" Intermediate Casing 4061.30 3991.00 18075.85 4-1/2 4-1/2" Production Casing Project: Milne Point Site: M Pt S Pad Well: Plan: MPU S-53 Wellbore: MPU S-53 Plan: MPU S-53 wp11 WELL DETAILS: Plan: MPU S-53 36.60 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 5999869.18 565420.79 70° 24' 36.3385 N 149° 28' 2.2894 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU S-53, True North Vertical (TVD) Reference: MPU S-53 as staked @ 70.30usft Measured Depth Reference:MPU S-53 as staked @ 70.30usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 0LOQH3RLQW 03W63DG 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ0386 0386 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH 0386DVVWDNHG#XVIW 'HVLJQ0386ZS 'DWDEDVH$ODVND 0'5HIHUHQFH0386DVVWDNHG#XVIW 1RUWK5HIHUHQFH :HOO3ODQ0386 7UXH 0DS6\VWHP *HR'DWXP 3URMHFW 0DS=RQH 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ILOWHULQJFULWHULD6FDQ7\SH6FDQ7\SH 0.001.002.003.004.00Separation Factor0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)MPU S-45MPU S-44iNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-53 NAD 1927 (NADCON CONUS)Alaska Zone 0436.60+N/-S+E/-W Northing EastingLatittudeLongitude0.000.005999869.18 565420.7970° 24' 36.3385 N149° 28' 2.2894 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-53, True NorthVertical (TVD) Reference: MPU S-53 as staked @ 70.30usftMeasured Depth Reference:MPU S-53 as staked @ 70.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-11-25T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU S-53 wp11 (MPU S-53) GYD_Quest GWD1500.00 5437.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag5437.00 8150.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag8150.00 18075.85 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)MPU S-46iMPS-41MPU S-45MPU S-44iMPS-43MPU S-56PB1MPU S-47MPS-39NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 18075.85Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-53Wellbore: MPU S-53Plan: MPU S-53 wp11Ladder / S.F. 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(OOLSVH6HSDUDWLRQ 3DVV0386L03863%03863% &HQWUH'LVWDQFH 3DVV0386L03863%03863% (OOLSVH6HSDUDWLRQ 3DVV0386L03863%03863% &OHDUDQFH)DFWRU 3DVV038603860386 &HQWUH'LVWDQFH 3DVV038603860386 (OOLSVH6HSDUDWLRQ 3DVV038603860386 &OHDUDQFH)DFWRU 3DVV3ODQ038603860386ZS &HQWUH'LVWDQFH 3DVV3ODQ038603860386ZS (OOLSVH6HSDUDWLRQ 3DVV3ODQ038603860386ZS &OHDUDQFH)DFWRU 3DVV3ODQ038603860386ZS (OOLSVH6HSDUDWLRQ 3DVV3ODQ038603860386ZS &OHDUDQFH)DFWRU 3DVV3ODQ038603860386ZS (OOLSVH6HSDUDWLRQ 3DVV3ODQ038603860386ZS &OHDUDQFH)DFWRU 3DVV'HFHPEHU &203$663DJHRI 0LOQH3RLQW+LOFRUS$ODVND//&$QWLFROOLVLRQ5HSRUWIRU3ODQ03860386ZS6XUYH\WRROSURJUDP)URPXVIW7RXVIW6XUYH\3ODQ 6XUYH\7RRO 0386ZS *<'B4XHVW*:' 0386ZS B0:',)5066DJ 0386ZS B0:',)5066DJ 0386ZS B0:',)5066DJ(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG'HFHPEHU &203$663DJHRI 0.001.002.003.004.00Separation Factor8400 8925 9450 9975 10500 11025 11550 12075 12600 13125 13650 14175 14700 15225 15750 16275 16800 17325 17850Measured Depth (1050 usft/in)MPU E-39MPU E-39L1MPE-24AMPE-24AL1MPS-41MPS-37MPS-08MPS-08PB1MPS-12L1MPS-12MPS-12PB1MPS-19MPS-05L1MPS-05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-53 NAD 1927 (NADCON CONUS)Alaska Zone 0436.60+N/-S+E/-W Northing EastingLatittudeLongitude0.000.005999869.18 565420.7970° 24' 36.3385 N149° 28' 2.2894 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-53, True NorthVertical (TVD) Reference: MPU S-53 as staked @ 70.30usftMeasured Depth Reference:MPU S-53 as staked @ 70.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-11-25T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU S-53 wp11 (MPU S-53) GYD_Quest GWD1500.00 5437.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag5437.00 8150.00 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag8150.00 18075.85 MPU S-53 wp11 (MPU S-53) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8400 8925 9450 9975 10500 11025 11550 12075 12600 13125 13650 14175 14700 15225 15750 16275 16800 17325 17850Measured Depth (1050 usft/in)MPS-08MPS-08PB1MPS-05L1NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 18075.85Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-53Wellbore: MPU S-53Plan: MPU S-53 wp11Ladder / S.F. Plots2 of 2CASING DETAILSTVD MD Name Size2312.25 5437.00 10-3/4" Surface Casing 10-3/43956.72 8150.00 7-5/8" Intermediate Casing 7-5/84061.30 18075.85 4-1/2" Production Casing 4-1/2 1 Dewhurst, Andrew D (OGC) From:Michael Schoetz <mschoetz@hilcorp.com> Sent:Monday, 27 January, 2025 16:17 To:Dewhurst, Andrew D (OGC) Cc:Jamie Wilson Subject:MPU S-53 PTD (224-159) Andy, Per our discussion this afternoon, Hilcorp North Slope, LLC is aware of the proposed operations for the MPU S-53 Well and their proximity to the Prudhoe Bay Unit. HNS has had an open dialogue with HAK regarding the operations and does not have any objections thereto. Thank you, Michael W. Schoetz, CPL Hilcorp North Slope, LLC Division Landman Main: (907) 777-8300 Office: (907) 777-8414 Mobile: (281) 685-0902 Email: mschoetz@hilcorp.com 3800 Centerpoint Dr., Suite 1400 | Anchorage, Alaska 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. You don't often get email from mschoetz@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Friday, 24 January, 2025 16:19 To:Nathan Sperry Cc:Roby, David S (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Rixse, Melvin G (OGC); Lau, Jack J (OGC); Wallace, Chris D (OGC); Michael Schoetz Subject:RE: MPU S-53 PTD (224-159): Questions Nate, As the planned injection is 5’ from the unit boundary, we request a letter from Hilcorp North Slope, LLC acknowledging and agreeing to the planned injection into the PBU from MPU S-53. We will be able to complete the PTD review process once this letter has been received. Andy From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Wednesday, 22 January, 2025 13:42 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Michael Schoetz <mschoetz@hilcorp.com> Subject: RE: [EXTERNAL] MPU S-53 PTD (224-159): Questions Andy, See the attached formation tops. Regarding the LNO, please contact Division Landman, Michael W. Schoetz (cc’d on this communication) with your concerns. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, January 22, 2025 12:50 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] MPU S-53 PTD (224-159): Questions CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Nate, Thank you for the answers below. Would you please provide a copy of the Letter of Non-Objection for our reference? And yes, please send an updated PDF page for the geo prog; I will update the PTD with it. Thanks, Andy From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Wednesday, 22 January, 2025 09:56 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] MPU S-53 PTD (224-159): Questions Andy, x Are you planning to pre-produce this well? No, we are not. x Has Hilcorp Alaska, LLC had any communication with the working interest owners of the Prudhoe Bay Unit regarding injection so close to the unit boundary? Since there will be no production within 500’ of the unit boundary, we are not required to obtain Prudhoe Bay Unit (“PBU”) approval. We do want to note we have submitted a Wellbore Easement application (ADL 422472) with DNR allowing us to traverse the PBU and the application included a Letter of Non-Objection from Hilcorp North Slope, LLC, as operator of PBU, so they are aware of our S-Pad drill wells. We expect to receive the executed Entry Authorization from DNR this week. x Is the stage tool mentioned in section 13.8 a typo? Yes, that is a typo. x Would you please double-check the depths provided on the geo prog. The MD/TVD relationships do not appear to match the directional plan. My apologies. Would you like me to send you an updated page to insert into the PTD application? Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, January 21, 2025 5:58 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] MPU S-53 PTD (224-159): Questions Nathan, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CCAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 I am completing my review of the MPU S-53 PTD and have a few questions: x Are you planning to pre-produce this well? x Has Hilcorp Alaska, LLC had any communication with the working interest owners of the Prudhoe Bay Unit regarding injection so close to the unit boundary? x Is the stage tool mentioned in section 13.8 a typo? x Would you please double-check the depths provided on the geo prog. The MD/TVD relationships do not appear to match the directional plan. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any d issemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements 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 the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. SCHRADER BLUFF OIL 224-159 MILNE POINT MPU S-53 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT S-53Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241590MILNE POINT, SCHRADER BLFF OIL - 525140NA1Permit fee attachedYesADL380109 , ADL025637, ADL047446 , and ADL3801102Lease number appropriateYes3Unique well name and numberYesMILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitYesArea Injection Order No. 10-C14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)No16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes20" 129.5# X-52 driven to 173'18Conductor string providedYes10-3/4" L-80 45.5# to 2312' TVD, Shoe to be placed in the SV1 shale19Surface casing protects all known USDWsYes10-3/4" fully cemented from SV1 to surface. Two stage cement job through ported collar20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYes7-5/8" L-80 29.7# to SB reservoir, landed horizontally, 9-5/8" L-80 40 to SB reservoir. Land shoe horizontal22CMT will cover all known productive horizonsYes7-5/8" cemented from reservoir to 500' above the SB. Top of SB.23Casing designs adequate for C, T, B & permafrostYesDoyon 14 rig has adequate tankage and good trucking support24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows no close approaches with HSE risk. Offset well S-08 to be abandoned before.26Adequate wellbore separation proposedYes16" Diverter ~300' in length w two 22.5° bends27If diverter required, does it meet regulationsYesAll fluids overbalanced to expected pore pressure.28Drilling fluid program schematic & equip list adequateYes1 annular, 3 ram stack tested to 3000 psi.29BOPEs, do they meet regulationYes13-5/8" , 5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)YesDoyon 14 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesMPU R pad has no H2S history. Monitoring will be required.33Is presence of H2S gas probableYes34Mechanical condition of wells within AOR verified (For service well only)NoH2S measures required. S-08 had 50 ppm measured in 201235Permit can be issued w/o hydrogen sulfide measuresYesAnticipating normal (8.46 ppg EMW) pressure gradient36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate27-Jan-25ApprMGRDate15-Jan-25ApprADDDate15-Jan-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateInjection is planned 5' from the MPU/PBU boundary. See attached emails for a statement from Hilcorp NS.*&:JLC 1/28/2025