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Home My WebLink About225-081David 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: 01/29/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU H-23 + PB1 PTD: 225-081 API: 50-029-23825-00-00 (MPU H-23) API: 50-029-23825-70-00 (MPU H-23PB1) FINAL LWD FORMATION EVALUATION LOGS (12/10/2025 to 12/28/2025) x Vision Resistivity in Real-Time and Recorded Mode (2” & 5” MD/TVD Color Logs) x Drilling Mechanics (Time and Depth) x Final Definitive Directional Survey x End Of Well (EOW) Letter SFTP Transfer – Main Folders: FINAL LWD Subfolders: T41295 T41296 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.29 09:35:39 -09'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT H-23 JBR 01/26/2026 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:0 4-1/2" & 5-1/2" joints. Sundry for rig change. Test Results TEST DATA Rig Rep:Davis/EnfieldOperator:Hilcorp Alaska, LLC Operator Rep:Lafleur/Amend Rig Owner/Rig No.:Nabors 273 PTD#:2250810 DATE:12/29/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM251231093214 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 1380 Sundry No: 325-712 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 P Lower Kelly 1 P Ball Type 3 P Inside BOP 2 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 3-1/2"x5-1/2"P #2 Rams 1 Blinds P #3 Rams 1 3-1/2"x5-1/2"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 2-1/16"/3-1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3025 Pressure After Closure P2000 200 PSI Attained P21 Full Pressure Attained P70 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2205 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 P23 #1 Rams P7 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1        Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.11.19 20:44:40 - 09'00' Sean McLaughlin (4311) 325-712 By Grace Christianson at 10:58 am, Nov 20, 2025 * All stated conditions of approval on original approved permit-to-drill still apply. TS 11/20/25 10-407 original completion DSR-11/21/25MGR21NOV25 11/21/25 Page 43 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 20.0 Parker 273 Diverter Schematic Page 44 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 21.0 Parker 273 BOP Schematic Page 54 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 28.0 Parker 273 Choke Manifold Schematic 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 Unit Field, Schrader Bluff Oil, MPU H-23 Hilcorp Alaska, LLC Permit to Drill Number: 225-081 Surface Location: 3279' FSL, 4036' FEL, Sec 34, T13N, R10E, UM, AK Bottomhole Location: 1967' FSL, 163 FWL, Sec 32, T13N, R10E, 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 5th day of September 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.05 09:44:30 -08'00' By Grace Christianson at 11:09 am, Jul 23, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.23 10:53:06 - 08'00' Sean McLaughlin (4311) TS 9/3/25 225-081 MGR11AUG2025 DSR-7/23/25 * BOPE test to 3000 psi. Annular to 2500 psi. 24 hour notice. * Email casing test and FIT immediately upon completing FIT. * Approved for 30 days of pre-production on reverse circulation jet pump. * MIT-IA to 3500 psi. 24 hour notice for AOGCC opportunity to witness prior to POP. * SSV system and trips as described for pre-production. 50-029-23825-00-00 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.05 09:44:42 -08'00' 09/05/25 09/05/25 RBDMS JSB 090825 32N-01N-01AN-01BG-02G-01G-04G-03G-03AJ-05J-07J-06J-09J-09AJ-08J-08AJ-10J-11J-12J-13H-05H-06I-05H-07H-07AL1G-09G-10G-11G-13G-12H-10H-14H-11H-09H-12H-08H-08AH-13H-13AI-08I-06J-21J-17J-20J-20AJ-18J-22J-15I-09I-10J-23J-24J-24L1I-13G-14G-14L1I-11I-11L1I-12I-12L11R-36S-21S-27S-27L1I-15I-15L1S-29S-20S-32S-34S-34L1S-34L2S-35G-16G-16L1G-17G-18G-18L1J-26J-26L1J-26L2J-25I-17I-17L1I-17L2I-14I-14L1I-14L2I-19I-19L1I-16H-18H-18L1H-18L2H-16H-16L1G-19H-15H-17H-19H-19L1I-18WSAK 25H-01H-02H-03H-04I-01I-02I-03I-04I-04AI-04AL1J-01J-01AJ-02J-03J-04G-05G-06G-07G-08G-08AI-07J-19J-19AJ-16J-23L1H-07APB1H-14PB1J-24L1PB1I-12PB1S-27PB1I-15PB1S-35PB1G-16PB1G-18PB1J-26PB1J-25PB1I-17L1PB1I-14PB1I-19PB1H-16PB1I-04PB1H-07AL1PB1J-24L1PB2S-35PB2G-16PB2J-26PB2I-14PB2I-19PB2H-16PB2I-04APB1H-07AL1PB2I-14L2PB1H-16PB3I-14L2PB2S-20LSG-17LSI-02LSG-17SSI-02SS02L18L1J-23AJ-24AJ-28J-27Ghost oThe RiverI-35I-363PB2I-21I-20I-36PB1I-36PB2I-38I-39I-40M-19PB1I-37PB1I-37I-38PB1I-38PB2I-28I-07AH-17PB1S-44S-45S-46PB1S-47S-48PB1I-28PB1I-07APB1I-27S-56PB1S-46S-47PB1S-48I-30I-29I-32I-31I-33I-25I-24I-23I-26I-22J-43J-42J-42PB1J-41J-41PB1J-44J-45J-44PB1J-40J-47J-3272829303433312345IJHGHILCORP ALASKA LLCMILNE POINT FIELDH-23 AORSchrader Bluff OBa InjectorFEET0 700 1,400POSTED WELL DATAWell NumberWELL SYMBOLSOilD&ALocationShut In OilINJ Well (Water Flood)P&A OilP&A Oil/GasAbandoned InjectorSWDJ&ATemporarily AbandonedPlug BackPilot WellInjector LocationProducer LocationInjector GasShut In INJWATER SOURCELEADREMARKSPosting all wells that penetrate the Schrader BluffFormation.Schrader Bluff Penetration Points labelled with wellsymbols at Top Na.Pink lines denote the open footage in the SchraderBluff OBaDashed gray circles and red outline illustrates the 1/4mile radii from proposed wellBy: K. CunhaJuly 3, 2025PETRA 7/3/2025 8:52:41 AMH-23 Proposed WellFuture H-22 ProducerH-23 Expected TopNb intersection pointH-23 expectedTD locationFuture H-21 InjectorH-23 AOR Map•All wells that penetrate the Schrader Bluff Formation labelled at top Na intersectionpoint (Shallower than top Oba, well names posted at this depth because some wellsnever reached the OBa but are still within the Schrader Bluff Formation)•Pink lines represent the footage completed in wells that are within the Schrader BluffOBa sand•Wells completed in other Schrader bluff sands (above target zone) are shown on mapbut not highlighted pink so map is less busy- all are included on AOR spreadsheet•Note: Future new drill well, H-22, shown in dark green PTD API WELLSTATUSTop of SBOBa (MD)Top of SBOBa (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader OBastatusZonal Isolation224-107 50-029-23798-00-00 MPU J-40SB Nb Horiz Producer- Active N/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 271 bbls 12ppg EconoCem lead followed by82 bbls 15.8ppg HalCem. Stage 2 cemented with 443 bbls 10.7 ArcticCemfollowed by 56 bbls 15.8 HalCem. Cement returns to surface.224-071 50-029-23791-00-00 MPU J-41SB Nb Horiz Injector- Active N/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 295 bbls 12ppg lead followed by 82 bbls15.8ppg tail. 30 bbls of cement returns at surface. Stage 2 cemented with421 bbls 10.7ppg followed by 56 bbls 15.8. 246 bbls of cement returns atsurface.224-071 50-029-23791-70-00 MPU J-41PB1SB Nb Plugback N/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 295 bbls 12ppg lead followed by 82 bbls15.8ppg tail. 30 bbls of cement returns at surface. Stage 2 cemented with421 bbls 10.7ppg followed by 56 bbls 15.8. 246 bbls of cement returns atsurface.224-072 50-029-23792-00-00 MPU J-42SB Nb Horiz Producer- Active N/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 245 bbls 12ppg lead followed by 75 bbls15.8ppg tail. Stage 2 cemented with 443 bbls 10.7ppg followed by 56 bbls15.8. 272 bbls of cement returns at surface.224-072 50-029-23792-70-00 MPU J-42PB1SB Nb Plugback N/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 245 bbls 12ppg lead followed by 75 bbls15.8ppg tail. Stage 2 cemented with 443 bbls 10.7ppg followed by 56 bbls15.8. 272 bbls of cement returns at surface.190-090 50-029-22065-00-00 MPU I-01SB N Sand/Oa/OBa Producer - ShutIn / Currently in Process of P&A(Sundry #325-128) 5904 4074 3579 2681 Open7'' cemented with 84 bbls class G, Bumped plug with 1500 psi. 85 BblsCement pumped 10/2/2023, TOC at 3071', 86 Bbls Cement pumped4/21/2025, TOC at 743' SLM additional P&A to continue under sundry #325-128202-152 50-029-23106-00-00 MPU I-15SB N Sand/OBA Horiz Producer-Active 5136 4030 2678 2427 Open7" cemented with 189 sacks of 12ppg lead and 84 sacks of 15.8ppg tail.The job was pumped with full returns. Assuming 20% washout, thecalculated TOC is 2,678' MD.202-152 50-029-23106-70-00 MPU I-15PB1SB OBA Plugback 5136 4030 N/A N/A N/A Sidetracked below the NB.202-153 50-029-23106-60-00 MPU I-15L1SB OA Horiz Producer- Active N/A N/A 2678 2427 N/A7" cemented with 189 sacks of 12ppg lead and 84 sacks of 15.8ppg tail.The job was pumped with full returns. Assuming 20% washout, thecalculated TOC is 2,678' MD.195-120 50-029-22583-00-00 MPU I-05SB Injector- P&A'd 5210 4077 N/A N/A Closed P&A'd205-159 50-029-23284-00-00 MPU H-15SB N Sand/Oa/OBa Horiz Injector-Shut In 4601 4096 3307 3092 Open 7" top of cement logged at 3,307' MD via USIT in 2005.190-092 50-029-22067-00-00 MPU I-03SB N Sand/Oa/OBa Producer - ShutIn 4486 4018 3000 2701 Open7" planned to be cemented with 50 sacks of Permafrost E lead and 278sacks of Class G tail. Top job planned consisting of 273 sacks Permafrost Cfollowed by 60 bbls dead crude. Reported TOC was 3000' MD. Unable tolocate cementing records.204-190 50-029-23227-00-00 MPU H-16SB N Sand/OBA Horiz Producer-Active 6482 4059 4670 3388 Open7-5/8" cemented with 124 bbls 15.8ppg Class G. Plug bumpes and floatsheld. Assuming 20% washout, the calculated TOC is 4,670' MD.204-190 50-029-23227-70-00 MPU H-16PB1SB OBA Plugback 6482 4059 N/A N/A N/A OBa Sidetrack204-190 50-029-23227-71-00 MPU H-16PB2SB OBA Plugback 6482 4059 N/A N/A N/A OBa Sidetrack204-190 50-029-23227-72-00 MPU H-16PB3SB OBA Plugback 6482 4059 N/A N/A N/A OBa Sidetrack204-191 50-029-23227-60-00 MPU H-16L1SB Oa Horiz Producer- Active N/A N/A N/A N/A N/A Oa lateral (above OBa); see above cement detail195-151 50-029-22602-00-00 MPU I-07SB Producer- Sidetracked 3994 3970 N/A N/A Closed P&A'd221-010 50-029-22602-01-00 MPU I-07ASB N Sands/Oa/OBA Injector- Shut In 4112 3999 3550 3473 Open 7" cemented to 3,550' MD via 2 stage cement job.Area of Review MPU H-23 SB OBA09/05/ 221-010 50-029-22602-70-00 MPU I-07APB1SB Plugback 4125 4001 3608 3526 Closed Open hole plugged back with balanced plug. TOC tagged at 3,608' MD.204-158 50-029-23221-00-00 MPU I-16SB NB/Oa/OBa Injector- Shut in 4577 3977 3490 3087 Open7" cemented with 298 sacks Class 'G'. Full returns throughout job, plugbumped and floats held. TOC located with USIT log dated 9/21/2004211-148 50-029-23461-00-00 MPU I-18SB NB/Oa/OBa Injector- Active 6203 3964 4000 3012 Open 7" cemented with 72 bbls Class 'G'. USIT log shows top of cement at 4000'.204-098 50-029-23212-60-00 MPU I-17 NB Horiz Producer-Active5069 3953 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-60-00 MPU I-17L1 OBa Horiz Producer-Active5069 3953 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-70-00 MPU I-17L1PB1OBA Plugback 5068 3953 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-100 50-029-23212-61-00 MPU I-17L2 OA Horiz Producer- ActiveN/A N/A N/A N/A N/A9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.197-195 50-029-22822-00-00 MPU I-06SB Oa/OBa Producer- Shut in 8605 3909 Surface Surface Open9-5/8" stage 1 cemented with 220 bbls Permafrost E followed by 151 bbls13.1 ppg Premium. 40 bbls cement circulated off top of ES cementer. Stage2 cemented with 452 bbls Permaforst E followed by 33 bbls 15.6ppgPermafrost C. Full returns to surface.200-109 50-029-22966-00-00 MPU I-10SB Oa/OBA Injector- P&A'd 8042 3910 Surface Surface Closed Well fully P&Ad to surface.220-049 50-029-23679-00-00 MPU I-20 SB OBa Producer- Active4923 4013 Surface Surface N/A9-5/8" Cemented to surface via 2 stage cement jobs with 226 bbls returnedto surface.220-051 50-029-23681-00-00 MPU I-21 SB Horiz OBa Injector- Active5850 4004 Surface Surface Open9-5/8" stage 1 cemented with 213 bbls 12ppg followed by 83 bbls 15.8 ppgClass 'G'. Cement circulated off top of ES cementer. Stage 2 cemented with248 bbls 10.7ppg followed by 56 bbls 15.8ppg Class 'G'. Full returns tosurface.224-023 50-029-23784-00-00 MPU I-22 SB Horiz OBa Producer- Active5552 4006 Surface Surface Open9-5/8" stage 1 cemented with 183 bbls 12ppg followed by 77 bbls 15.8 ppgClass 'G'. 34 bbls lost during job. Stage 2 cemented with 327 bbls 10.7ppgfollowed by 56 bbls 15.8ppg Class 'G'. Full returns to surface. May bemissing cement from ES cementer @ 1982' to calculated cement top of2264'.224-012 50-029-23780-00-00 MPU I-23 SB Horiz OBa Injector- Active6828 4006 Surface Surface Open9-5/8" stage 1 cemented with 276 bbls 12ppg followed by 82 bbls 15.8 ppgClass 'G'. Cement circulated off top of ES cementer. Stage 2 cemented with360 bbls 10.7ppg followed by 56 bbls 15.8ppg Class 'G'. Full returns tosurface.224-001 50-029-23778-00-00 MPU I-24 SB Horiz OBa Producer- Active6392 4009 5686 3886 Open9-5/8" stage 1 cemented with 444 bbls 12ppg followed by 90 bbls 15.8 ppgClass 'G'. Stage 2 cemented with 350 bbls 10.7ppg followed by 56 bbls15.8ppg Class 'G'. Full returns to surface. CBL identified top of stage 1 job at5686'. 50 bbl remedial cement squeeze pumped into perforations at 5190'.223-119 50-029-23776-00-00 MPU I-25 SB Horiz OBa Injector- Active6872 4008 Surface Surface Open9-5/8" stage 1 cemented with 265 bbls 12ppg followed by 82 bbls 15.8 ppgClass 'G'. Stage 2 cemented with 359 bbls 10.7ppg followed by 56 bbls15.8ppg Class 'G'. Full returns to surface.221-013 50-029-23692-00-00 MPU I-27 SB Horiz OA Producer- ActiveN/A N/A Surface Surface N/A9-5/8" Cemented to surface via 2 stage cement jobs with 255 bbls returnedto surface.220-077 50-029-23691-00-00 MPU I-28 SB Horiz OA Injector- ActiveN/A N/A Surface Surface N/A9-5/8" stage 1 cemented with 171 bbls 12ppg followed by 82 bbls 15.8 ppgClass 'G'. Stage 2 cemented with 213 bbls 10.7ppg followed by 56 bbls15.8ppg Class 'G'. Full returns to surface.222-006 50-029-23708-00-00 MPU I-29OA Horiz Producer- ActiveN/A N/A N/A N/A N/ANot Open in OBA222-023 50-029-23708-00-00 MPU I-30OA Horiz Injector-ActiveN/A N/A N/A N/A N/ANot Open in OBA223-066 50-029-23710-00-00 MPU I-31OA Horiz Producer-ActiveN/A N/A N/A N/A N/ANot Open in OBA223-054 50-029-237-59-00-00 MPU I-32 OA Horiz Injector-Active N/A N/A N/A N/A N/ANot OpenTBDTBD MPU H-22Future OBa Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yet Milne Point Unit MPU H-23 Drilling Program Final 07/23/2025 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 ........................................................................................................ 11 10.0 N/U 21-1/4” 2M Diverter System ................................................................................................ 12 11.0 Drill 12-1/4” Hole Section ............................................................................................................ 14 12.0 Run 9-5/8” Surface Casing .......................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing .................................................................................................... 23 14.0 BOP N/U and Test........................................................................................................................ 28 15.0 Drill 8-1/2” Hole Section .............................................................................................................. 29 16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ........................................................ 34 17.0 Run 3-1/2” Tubing (Upper Completion) .................................................................................... 39 18.0 RDMO ........................................................................................................................................... 40 19.0 Post-Rig Work .............................................................................................................................. 41 20.0 D14 Diverter Schematic ............................................................................................................... 43 21.0 D14 BOP Schematic ..................................................................................................................... 44 22.0 Wellhead Schematic ..................................................................................................................... 45 23.0 Days Vs Depth .............................................................................................................................. 46 24.0 Formation Tops & Information .................................................................................................. 47 25.0 Anticipated Drilling Hazards ...................................................................................................... 48 26.0 D14 Layout ................................................................................................................................... 52 27.0 FIT Procedure .............................................................................................................................. 53 28.0 D14 Choke Manifold Schematic ................................................................................................. 54 29.0 Casing Design ............................................................................................................................... 55 30.0 8-1/2” Hole Section MASP .......................................................................................................... 56 31.0 Spider Plot (NAD 27) (Governmental Sections) ........................................................................ 57 32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................... 58 Page 2 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 1.0 Well Summary Well MPU H-23 Pad Milne Point "H" Pad Planned Completion Type Injection Tubing Target Reservoir(s)Schrader Bluff OBa Sand Planned Well TD, MD / TVD 15,599' MD / 3,932' TVD PBTD, MD / TVD 15,599' MD / 3,932' TVD Surface Location (Governmental) 3279’ FSL, 4036’ FEL, Sec 34, T13N, R10E, UM, AK Surface Location (NAD 27) X= 556605 Y= 6010431 Top of Productive Horizon (Governmental)1706' FSL, 13' FEL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 555364 Y= 6008849 BHL (Governmental) 1967' FSL, 163' FWL, Sec 32, T13N, R10E, UM, AK BHL (NAD 27) X= 544978 Y= 6009039 AFE Drilling Days 18 days AFE Completion Days 3 days Maximum Anticipated Pressure (Surface) 1380 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1786 psig Work String 5" 19.5# S-135 NC50 KB Elevation above MSL: 35.6 ft + 36.5 ft = 72.10 ft GL Elevation above MSL: 35.6 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 3 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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-52 Weld 12-1/4”9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 9-5/8” 8.835” 8.679” 10.625” 40 L-80 TXP 5,750 3,090 916 8-1/2”5-1/2” 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397 4-1/2” 3.960” 3.795” 4.714” 13.5 L-80 H625 9020 8540 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 & Prod 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 25,600 30,700 560 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am 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 Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 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 workday to Sean.Mclaughlin@hilcorp.com, Brad.Gorham@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 Brad.Gorham@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, Brad.Gorham@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Sean McLaughlin 907.223.6784 907.223.6784 Sean.Mclaughlin@hilcorp.com Drilling Engineer Brad Gorham 907.263.3917 907.250.3209 Brad.Gorham@hilcorp.com Completion Engineer Erik Nelson 907.564.5277 907.903.7407 Erik.nelson@hilcorp.com Geologist Katie Cunha 907.564.4786 907.802.0078 katharine.cunha@hilcorp.com Reservoir Engineer Almas Aitkulov 907.564.4250 979.739.3133 aaitkulov@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 907.891.0640 Adrian.Kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 joseph.lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: AT 07/23/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU H-23 Last Completed: TBD PTD: TBD 5-1/2” x 4-1/2” SLOTTED LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-52 / Weld N/A Surface 80’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,500’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 2,500’ 5,272’ 0.0758 5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 5,122’ 6,099’ 0.0232 4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 6,099’ 15,599 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 5,122’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” 16 yds Concrete 12-1/4"Stg 1 –Lead 307 sx / Tail 395 sx Stg 2 –Lead 561 sx / Tail 268 sx 8-1/2” Uncemented Slotted Liner TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” x 3-1/2” Tubing Hanger, 3-1/2” TCII GENERAL WELL INFO API#:TBD Completion Date: TBD WELL INCLINATION DETAIL KOP @ 360’ 90° Hole Angle = 5,400’ MD TD =15,599’ (MD) / TD =3,932’ (TVD) 3 20” Orig. KB Elev.:72.10 / GL Elev.:35.6’ 3-1/2” 7 2 9-5/8” 1 4/5 See Slotted Liner Detail PBTD =15,599’(MD) / PBTD =3,932’(TVD) 9-5/8” Fidelis Cementer @ ~2,500’ 4-1/2” 5-1/2” x 4-1/2” 6 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ~4,640’ Sliding Sleeve 2.813” X Profile (Down to Open) 2.810” 2 ~4,700’TBD DH Gauge 2.992” 3 ~4,750’ XN Nipple, 2.813”, 2.75” No-Go 2.750” 4 ~5,119’ Locater Sub, 8.25” No Go (bottom of locator spaced out 3.52’) 6.261” 5 ~5,120’ Bullet Seals (Length of Seals TBD per TFM)–TXP Top Box Up x Mule Shoe (Bottom @ ~5,130’) 6.261” Lower Completion 6 5,122’ Baker SLZXP and Liner Hanger 6.300” 7 15,599 Shoe Page 7 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU H-23 is a grassroots Oba Injector planned to be drilled in the Schrader Bluff OBa Sand. MPU H-23 is part of a multi well re-development program targeting the Schrader Bluff sand on Milne Point "H" Pad. MPU H-23 will be pre-produced for 30 days. The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top of the Schrader Bluff OBa Sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the open hole section. The D14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately September 15th, 2025, pending rig schedule. Surface casing will be run to 6,235’ MD / 4,059’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU D14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser 5. Drill 8-1/2” lateral to well TD. 6. Run 4-1/2” injection liner. 7. Run 3-1/2” tubing. 8. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) 6,235’ MD / 4,059’ TVD Page 8 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 H-23. 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)”. Page 9 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure AOGCC Regulation Variance Requests: 1) None.None Page 10 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 8-1/2” 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 (BOP’s 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 PTD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@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 11 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 MPU H-23 will utilize a newly set 20” conductor on I-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 D14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 6” liners in mud pumps. x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 529 gpm @ 120 spm @ 90% mechanical efficiency. Page 12 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). 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 13 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” 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 Use GWD until MWD surveys are clean. 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. Hydraulics calculations and recommended TFA is attached below. 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 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. 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 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, 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, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when MWD surveys clean up. x Gas hydrates have not been seen on I-Pad. However, be prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be prepared for hydrates: Page 15 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 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 A/C: x There are no anti-collision concerns with the planned directional profile. All wells have a clearance factor >1. 12-1/4” hole mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ MW can be cut once ~500’ below hydrate zone PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the Page 16 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point 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 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.5 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute. 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. 11.6 TOOH and LD BHA Page 17 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” 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 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 to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” 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. 12.2 P/U shoe joint, visually verify no debris inside joint. 12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor 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 18 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 12.4 Float equipment and Stage tool equipment drawings: Page 19 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 12.5 Continue running 9-5/8” 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 (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist 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. 12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost. x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damage to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs Page 20 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure Page 21 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 12.7 Continue running 9-5/8” 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. x Centralization: o 1 centralizer every 2 joints to base of conductor Page 22 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface x Ensure drifted to 8.525” 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar along with all necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 23 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. 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) – stage tool 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 24 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 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 (shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, stage tool Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.12 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 13.13 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, ±4.5 bbls before consulting with Drilling Section Calculation Vol (bbl) Vol (ft3) Sacks 12-1/4" OH x 9-5/8" Csg (5272' - 1000' - 2500') x 0.0558 bpf X 1.3 = 128.5 720.9 Total Lead 128.5 720.9 307 12-1/4" OH x 9-5/8" Csg (1000') x 0.0558 bpf X 1.3 = 72.5 406.8 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 81.6 457.8 395 Displacement 2500' x 0.0732 bpf + (5272' - 1000' - 2500') x 0.0558 bpf X 1.3 =384.1Tail Lead 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 120'.0758279 Page 25 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to open circulating ports in stage collar. Verify opening pressure with stage tool rep prior to pumping the first stage of cement. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 26 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 13.19 Stage tool representative to witness the loading of the closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement is in the Stage 2 table in step 13.22. Section Calculation Vol (bbl) Vol (ft3) Sacks 20# Conductor x 9-5/8" Csg 80' x 0.23 bpf = 20.0 112.1 12-1/4" OH x 9-5/8" Csg (2000' - 80') x 0.0558 bpf X 2.5 = 267.8 1502.6 Total Lead 287.8 1614.7 561.1 12-1/4" OH x 9-5/8" Csg (2500' - 2000') x 0.0558 bpf X 2 = 55.8 312.9 Total Tail 55.8 312.9 268 Displacement 2500' x 0.0732 bpf =183.0Tail Lead 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 Page 27 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 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 13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following in 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 brad.gorham@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 14.0 BOP N/U and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool. 14.2 N/U 13-5/8” x 5M BOP as follows: 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 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x N/U 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 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. 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 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6” liners in mud pumps. Page 29 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 M/U 8.5” cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 Work through stage tool a couple times without rotation to ensure clean pass through. 15.4 POOH and LD cleanout BHA. 15.5 P/U 8-1/2” RSS directional BHA. 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 Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is below. x Drill string will be 5” 19.5# S-135 NC50. x Run a ported float in the production hole section. 15.6 TIH w/ 8-1/2” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.7 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.8 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.9 Drill out shoe track and 20’ of new formation. 15.10 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.11 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.5 ppg FIT is the minimum required to drill ahead x 9.5 ppg provides >25 bbls based on 9.5 ppg MW, 8.4ppg PP (swabbed kick at 9.5 ppg BHP) Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 30 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 15.12 8-1/2” 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. 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 (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, 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:8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 31 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 15.13 TIH with 8-1/2” directional assembly to bottom 15.14 Displace wellbore to 8.9 ppg FloPro drilling fluid 15.15 Begin drilling 8-1/2” 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 P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, 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 hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. Page 32 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream connections x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x 8-1/2” Lateral A/C: x H-16, H-16PB2 & H-16PB3 – all have a CF of <1. H-16 is a dual-lat well that will be cemented prior to drilling H-23. x H-33 wp07 has a CF of 0.761. The is a proposed wellplan so there is no risk. x I-10 has a CF of 0.196. I-10 was P&A’d in 2013. x Schrader Bluff OA Concretions: 4-6% Historically 15.15 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 sidetrack low and right 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. 15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. 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 Page 33 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required. x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses) x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. 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 15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud weight if necessary 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 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 34 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” injection liner with slotted liner, the following well control response procedure will be followed: x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” 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 5-1/2” liner. 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. 16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high. 16.3. R/U 5-1/2” and 4-1/2” liner running equipment. x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV. x Ensure the liner 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. 16.4. Run 5-1/2” x 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 Uppermost 3,000’ will be 5-1/2”. 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 If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt outside of the surface shoe. This is to mitigate sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 35 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 5-1/2” 17# L-80 JFE Bear Casing OD Minimum Optimum Maximum Operating Torque 5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs Page 36 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 4-1/2” 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 09/05/7 Page 37 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner. 16.9. 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. 16.10. 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 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. 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. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. 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 prior to job. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. Page 38 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 16.18. 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. 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.20. 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. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. 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 39 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 17.2 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 Spot and RU TEC wire spooler x Keep hole covered while R/U tubular handling equipment. 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 profile (2.813-in / 2.750-in No-Go) set at XXXX-ft MD (Set 73 degrees inclination) w/ x 1 joint 3-½” 9.3#/ft, L-80 EUE 8rd tubing x 3-½” TBD DH Gauge o Affix cross-coupling clamps to secure TEC wire (every jt on 1st 15 jts then every other jt to surface) and testing continuity every ±2000-ft x 3-½” 9.3#/ft, L-80 EUE 8rd tubing x 3-½" Sliding Sleeve w/ X nipple profile (2.813) and EUE 8rd BxP handling pups o Run Sliding Sleeve in Closed position x XXX joints 3-½” 9.3#/ft, L-80 EUE 8rd tubing Page 40 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 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 X-over 3-½", 12.6# AB TC-II Box x 3-½", 9.3# EUE 8rd Pin x Tubing hanger with x 3-½" AB TC-II, 12.6# pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. 17.5 Makeup the tubing hanger and landing joint. Install TEC wire through wellhead penetrator. 17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and 1% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to ~3000’ MD with diesel. 17.9 Land hanger. RILDs and test hanger. 17.10 Continue pressurizing the annulus to 3750 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO D14 Page 41 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 19.0 Post-Rig Work OperationsϙϱϙConvert well on surface with hard line to a jet pump producer. 19.1 MU surface lines from power fluid header to the IA. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram. x Pressure test lines at existing power fluid header pressure (3,500 psi) 19.2 MU surface lines from production header to tubing. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram. x Pressure test to 3,500 psi. x SSV Pilot Settings: o Production SSV low pressure trip will be set to 25% of FTP or 50% of inlet separator pressure. o Production SSV high pressure trip will be set at 1100 psig. o Power fluid XV low pressure trip will be set to 50% of header pressure. o Power Fluid XV to be actuated if vertical run tubing SSV is actuated (within 2 minutes). x AOGCC will be notified for opportunity to witness before production begins. x Visual leak check by pad operator performed at least once per tower (i.e. ~ every 12 hours). x SCADA screen available in control room for pressure and flow sensors on injection line and well’s flow line. x Pilot trip pressures, both high and low, documented in permitting documents for Hilcorp pad operators and AOGCC inspectors. 19.3 MIRU SL. i. Contingency (if SL is unable to reach depth via pump down): RU and use coil tubing to perform same runs as outlined below. 19.4 Shift Sliding sleeve open 19.5 Install Jet Pump 19.6 RDMO SL/FB- After 30 days of production 19.7 MIRU SL. 19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2,000’ on IA i. i. Contingency (if SL was unsuccessful in reaching depth): RU and use coil tubing to perform same runs as outlined below. 19.9 Pull Jet Pump 19.10 Shift sliding sleeve closed Page 42 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 19.11 MIT-IA test to 2,000 psi 19.12 POI 19.13 After 5 days of stabilized injection MIT-IA to 2,000 psi (Charted and state witnessed) Page 43 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 20.0 D14 Diverter Schematic Page 44 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 21.0 D14 BOP Schematic Page 45 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 22.0 Wellhead Schematic Page 46 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 23.0 Days Vs Depth Page 47 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 24.0 Formation Tops & Information MPU H-23 Formations TVD (ft) TVDss (ft) MD (ft) Formation Pressure (psi) EMW (ppg) SV6 908 836 918 399 8.46 Base Permafrost 1937 1865 2052 852 8.46 SV1 2157 2085 2295 949 8.46 UG_LA3 3428 3356 3712 1508 8.46 UG_MB 3711 3639 4084 1633 8.46 SB_NA 3924 3852 4445 1726 8.46 OBA 4112 4040 5200 1809 8.46 H-pad Data Sheet Formation Description Page 48 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 25.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: 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 There are no anti-collision concerns with the planned directional profile. All wells have a clearance factor >1. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. I-04A had 36ppm H2S (2012). Page 49 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 50 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (5) faults that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well specific AC: 8-1/2” Lateral A/C x H-16, H-16PB2 & H-16PB3 – all have a CF of <1. H-16 is a dual-lat well that will be cemented prior to drilling H-23. x H-33 wp07 has a CF of 0.761. The is a proposed wellplan so there is no risk. Page 51 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure x I-10 has a CF of 0.196. I-10 was P&A’d in 2013 Page 52 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 26.0 D14 Layout Page 53 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. 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 Unit MPU H-23 SB OBaInjectorDrilling Procedure28.0 D14 Choke Manifold Schematic Page 55 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 29.0 Casing Design Page 56 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 30.0 8-1/2” Hole Section MASP % Milne Point Unit Kuparuk River Unit ADL025517 ADL025516 ADL025515 ADL380109 ADL315848 ADL025906 ADL025628 ADL025627 Sec. 20 Sec. 29 Sec. 33 Sec. 22Sec. 21 Sec. 2Sec. 5 Sec. 34 Sec. 8 Sec. 3 Sec. 10 Sec. 28 Sec. 11 Sec. 32 Sec. 27 Sec. 4 Sec. 9 Sec. 30 (636) Sec. 31 (639) Sec. 19 (633) U012N010E U013N010E MPU J MPU I MPU G MPU H MPU H-23_SHL MPU H-23_TPHMPU H-23_BHL MPU H-23 Legend MPU H-23_BHL MPU H-23_SHL %MPU H-23_TPH Other Surface Holes (SHL) Other Bottom Holes (BHL) Other Well Paths Pad Footprint Oil and Gas Unit Boundary Map Date: 6/25/2025 0 1,000 2,000 Feet Document Path: O:\AWS\GIS\Dropbox\Julieanna Potter\Project_Handoff\Project_Handoff.aprxNAD 1927 StatePlane Alaska 4 FIPS 5004 Milne Point Unit H-23 Well wp05 u 1:30,000 Page 58 Milne Point Unit MPU H-23 SB OBa Injector Drilling Procedure 32.0 Surface Plat (As-Built) (NAD 27) !!" 0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 263.61° (1500 usft/in)H-23 wp05 tgt2H-23 wp02 tgt4H-23 wp02 tgt5H-23 wp02 tgt3H-23 wp05 tgt1H-23 wp02 tgt6H-23 wp02 tgt10H-23 wp02 tgt7H-23 wp02 tgt9H-23 wp02 tgt119-5/8" x 12-1/4"4-1/2" x 8-1/2"5001000150020002500300035004000450050005500 6000 65 00 70 00 7500 8000 8500 9000 95 00 10000 10500 11000 11500 12000 12500 13000 13 50 0 14000 14500 15000 1550015599MPU H-23 wp05Start Dir 3º/100' : 350' MD, 350'TVDStart Dir 4º/100' : 700' MD, 698.04'TVDEnd Dir : 1291.27' MD, 1246.74' TVDStart Dir 4.5º/100' : 3127.34' MD, 2912.26'TVDEnd Dir : 5072.04' MD, 4103.15' TVDBegin GeosteeringTotal Depth : 15598.8' MD, 3932.1' TVDSV6Base PermafrostSV1UG_LA3UG_MBSB_NASB_OBAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU H-2335.60+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006010430.56556605.2770° 26' 20.9230 N 149° 32' 18.3417 WSURVEY PROGRAMDate: 2025-04-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool36.50 1800.00 MPU H-23 wp05 (MPU H-23) GYD_Quest GWD1800.00 5272.00 MPU H-23 wp05 (MPU H-23) 3_MWD+IFR2+MS+Sag5272.00 15598.80 MPU H-23 wp05 (MPU H-23) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation908.10 836.00 917.52 SV61937.10 1865.00 2052.33 Base Permafrost2157.10 2085.00 2294.86 SV13428.10 3356.00 3711.92 UG_LA33711.10 3639.00 4084.02 UG_MB3924.10 3852.00 4444.72 SB_NA4112.10 4040.00 5200.36 SB_OBAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU H-23, True NorthVertical (TVD) Reference:H-23 as built rkb @ 72.10usftMeasured Depth Reference:H-23 as built rkb @ 72.10usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt H PadWell:Plan: MPU H-23Wellbore:MPU H-23Design:MPU H-23 wp05CASING DETAILSTVD TVDSS MD SizeName4117.10 4045.00 5272.00 9-5/8 9-5/8" x 12-1/4"3932.10 3860.00 15598.80 4-1/2 4-1/2" x 8-1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 36.50 0.00 0.00 36.50 0.00 0.00 0.00 0.00 0.002 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD3 700.00 10.50 185.00 698.04 -31.86 -2.79 3.00 185.00 6.31 Start Dir 4º/100' : 700' MD, 698.04'TVD4 1150.00 28.50 185.00 1120.49 -180.89 -15.83 4.00 0.00 35.855 1291.27 24.89 175.29 1246.74 -244.14 -16.32 4.00 -133.87 43.39 End Dir : 1291.27' MD, 1246.74' TVD6 3127.34 24.89 175.29 2912.26 -1014.34 47.14 0.00 0.00 66.02 Start Dir 4.5º/100' : 3127.34' MD, 2912.26'TVD7 5072.04 86.00 268.00 4103.15 -1568.17 -1126.12 4.50 94.14 1293.62 End Dir : 5072.04' MD, 4103.15' TVD8 5272.04 86.00 268.00 4117.10 -1575.14 -1325.51 0.00 0.00 1492.55 H-23 wp05 tgt1 Begin Geosteering9 5417.90 91.36 270.31 4120.46 -1577.28 -1471.25 4.00 23.36 1637.6210 6108.33 91.36 270.31 4104.10 -1573.54 -2161.48 0.00 0.00 2323.15 H-23 wp05 tgt211 6164.69 92.45 270.59 4102.23 -1573.10 -2217.81 2.00 14.18 2379.0712 6986.20 92.45 270.59 4067.10 -1564.69 -3038.53 0.00 0.00 3193.76 H-23 wp02 tgt313 7008.29 92.02 270.48 4066.24 -1564.49 -3060.60 2.00 -165.88 3215.6714 8259.12 92.02 270.48 4022.10 -1554.04 -4310.61 0.00 0.00 4456.75 H-23 wp02 tgt415 8338.59 90.43 270.44 4020.40 -1553.40 -4390.05 2.00 -178.66 4535.6316 9039.03 90.43 270.44 4015.10 -1547.99 -5090.45 0.00 0.00 5231.08 H-23 wp02 tgt517 9121.79 92.09 270.39 4013.28 -1547.39 -5173.18 2.00 -1.72 5313.2418 9565.91 92.09 270.39 3997.10 -1544.35 -5617.00 0.00 0.00 5753.96 H-23 wp02 tgt619 9646.42 90.99 271.57 3994.94 -1542.98 -5697.46 2.00 133.11 5833.7720 10682.10 90.99 271.57 3977.10 -1514.65 -6732.61 0.00 0.00 6859.34 H-23 wp02 tgt721 10991.29 90.20 277.70 3973.90 -1489.68 -7040.61 2.00 97.30 7162.6522 11732.89 90.20 277.70 3971.34 -1390.30 -7775.52 0.00 0.00 7881.9423 12037.95 90.17 271.60 3970.36 -1365.58 -8079.43 2.00 -90.25 8181.2124 13137.95 90.17 271.60 3967.10 -1334.86 -9179.00 0.00 0.00 9270.53 H-23 wp02 tgt925 13329.76 93.89 270.67 3960.30 -1331.06 -9370.62 2.00 -13.97 9460.5426 13580.61 93.89 270.67 3943.27 -1328.12 -9620.87 0.00 0.00 9708.9127 13725.25 91.00 270.70 3937.10 -1326.39 -9765.35 2.00 179.45 9852.30 H-23 wp02 tgt1028 13768.10 90.14 270.71 3936.67 -1325.87 -9808.19 2.00 179.23 9894.8229 15598.80 90.14 270.71 3932.10 -1303.13 -11638.75 0.00 0.00 11711.48 H-23 wp02 tgt11 Total Depth : 15598.8' MD, 3932.1' TVD -4500-3750-3000-2250-1500-75007501500225030003750South(-)/North(+) (1500 usft/in)-11250 -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250West(-)/East(+) (1500 usft/in)H-23 wp02 tgt11H-23 wp02 tgt9H-23 wp02 tgt7H-23 wp02 tgt10H-23 wp02 tgt6H-23 wp05 tgt1H-23 wp02 tgt3H-23 wp02 tgt5H-23 wp02 tgt4H-23 wp05 tgt29-5/8" x 12-1/4"4-1/2" x 8-1/2"250500750100012501500175020002250250027503000325035003 7 5 0 4 0 0 0 3932MPU H-23 wp05Start Dir 3º/100' : 350' MD, 350'TVDStart Dir 4º/100' : 700' MD, 698.04'TVDEnd Dir : 1291.27' MD, 1246.74' TVDStart Dir 4.5º/100' : 3127.34' MD, 2912.26'TVDEnd Dir : 5072.04' MD, 4103.15' TVDBegin GeosteeringTotal Depth : 15598.8' MD, 3932.1' TVDCASING DETAILSTVDTVDSS MDSize Name4117.10 4045.00 5272.00 9-5/8 9-5/8" x 12-1/4"3932.10 3860.00 15598.80 4-1/2 4-1/2" x 8-1/2"Project: Milne PointSite: M Pt H PadWell: Plan: MPU H-23Wellbore: MPU H-23Plan: MPU H-23 wp05WELL DETAILS: Plan: MPU H-2335.60+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.006010430.56 556605.27 70° 26' 20.9230 N 149° 32' 18.3417 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU H-23, True NorthVertical (TVD) Reference: H-23 as built rkb @ 72.10usftMeasured Depth Reference:H-23 as built rkb @ 72.10usftCalculation Method:Minimum CurvatureMilne Point 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!"#,1!,91!%&: %'* $+ %* $+3 * $+: %' $= 0= $$ 0(3 .0 $ 1 &0.6808 $0 %'0 '"%( )%*&'$+$%&! !"! !"! !"# %'* $+ < ,&'26)-)'26)-")'26)-"-11&"- -./1&-- -"1&,% ".*++&% ,&*%-./1&--0 )'26)-)'26)-")'26)-"-11&+% -."& -",&% ".*+& /&1"+-."& )'26)-)'26)-")'26)-"%&*- -.& -/&/* ".*"*&* /&/*%-.&0 ) =* $+>* $+ )@ )>*/&% ".1& '2()*% 7894:".1& %.,& '2()*% *8':!!' ! ;%.,& "%.%+1&1 '2()*% 7894: 5 4 <=)& 4 >&0 4 4 $ &0 ? $#@ $) A& ; >> & 4 4;'54504 < 4 5& 0.001.002.003.004.00Separation Factor0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Measured Depth (1600 usft/in)MPI-17L1PB1MPI-17L2MPI-15L1MPI-06MPI-05MPI-18MPI-10MPU H-22 wp05MPH-14PB1MPU H-32 wp03MPU H-42 wp03MPU H-34 wp03MPH-15MPH-19MPH-19L1MPU H-33 wp07MPH-16PB3MPH-18MPH-18L1MPH-16L1MPH-16PB2MPH-16MPH-04MPU H-43 wp04MPU J-41PB1MPU J-41MPU J-40No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU H-23 NAD 1927 (NADCON CONUS)Alaska Zone 0435.60+N/-S +E/-W Northing EastingLatittudeLongitude0.000.006010430.56 556605.27 70° 26' 20.9230 N 149° 32' 18.3417 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU H-23, True NorthVertical (TVD) Reference: H-23 as built rkb @ 72.10usftMeasured Depth Reference:H-23 as built rkb @ 72.10usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-04-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool36.50 1800.00 MPU H-23 wp05 (MPU H-23)GYD_Quest GWD1800.00 5272.00 MPU H-23 wp05 (MPU H-23)3_MWD+IFR2+MS+Sag5272.00 15598.80 MPU H-23 wp05 (MPU H-23) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Measured Depth (1600 usft/in)MPI-15L1MPI-10MPU H-22 wp05MPH-06MPH-14MPU H-34 wp03MPH-11MPH-03MPU H-26 wp01MPU H-21 wp04 - adjusted RKBMPH-12MPH-15MPH-19MPH-19L1MPU H-33 wp07MPH-18MPH-18L1MPH-18L2MPH-05MPU H-27 wp01MPU H-25 wp01MPH-16L1MPH-16MPH-04MPH-13AMPH-13MPU J-41PB1MPU J-41GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference36.50 To 15598.80Project: Milne PointSite: M Pt H PadWell: Plan: MPU H-23Wellbore: MPU H-23Plan: MPU H-23 wp05CASING DETAILSTVD TVDSS MD Size Name4117.10 4045.00 5272.00 9-5/8 9-5/8" x 12-1/4"3932.10 3860.00 15598.80 4-1/2 4-1/2" x 8-1/2" 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 225-081 MILNE POINT UNIT H-23 MILNE POINT WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT H-23Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250810Field & Pool:MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes ADL025906 and ADL0255172 Lease number appropriateYes3 Unique well name and numberYes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477B4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes AIO 10-D14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)Yes16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)No17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 grouted to 80'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgNA21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 16" Diverter w/ clearance of 75' from ignition sources27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateNo 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Doyon 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.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo Monitoring required33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required35 Permit can be issued w/o hydrogen sulfide measuresYes Reservoir expected to be nomally pressured (8.46 EMW). MPD planned. Mulitple faults expected.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate9/2/2025ApprMGRDate9/4/2025ApprTCSDate8/28/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 9/5/2025