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225-055
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/14/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251114 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# PBU 01-10A 50029201690200 225055 8/29/2025 BAKER MRPM BRU 224-34T 50283202050000 225044 8/9/2025 AK E-LINE CBL MGS ST 17595 30 50733204560000 193120 8/13/2025 AK E-LINE CBL MPU H-11 50029228020000 197163 8/17/2025 AK E-LINE JetCut PCU D-10 50283202080000 225082 10/6/2025 AK E-LINE CBL Please include current contact information if different from above. T41100 T41101 T41102 T41103 T41104 PBU 01-10A 50029201690200 225055 8/29/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.14 12:58:13 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084 PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -09'00' David Douglas Hilcorp North Slope, 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: Hilcorp North Slope, LLC Date: 09/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 01-10A PTD: 225-055 API: 50-029-20169-02-00 FINAL LWD FORMATION EVALUATION LOGS (08/16/2025 to 08/23/2025) Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs) Pressure While Drilling (PWD) Final Definitive Directional Surveys SFTP Transfer - Data Main Folders: SFTP Transfer - Data Sub-Folders: Please include current contact information if different from above. 225-055 T40915 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 14:27:12 -08'00' 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: Prudhoe Bay Unit Field, Prudhoe Oil, PBU 01-10A Hilcorp Alaska, LLC Permit to Drill Number: 225-055 Surface Location: 1429' FNL, 1588' FWL, Sec 08, T10N, R15E, UM, AK Bottomhole Location: 1965' FNL, 1276' FWL, Sec 08, T10N, R15E, UM, AK DearMr. McLaughlin: Enclosed is the approved application for the permit to drill the abovereferenced well. PerStatute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, compositecurves 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 AOGCCreserves 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 AOGCCspecifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or anAOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Greg Wilson Commissioner DATED this23rdday of July 2025. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:57:18 -08'00' 3-1/2"x3-1/4" By Grace Christianson at 2:18 pm, May 21, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.05.21 13:55:40 - 08'00' Sean McLaughlin (4311) SFD 7/23/2025JJL 6/16/25 DSR-6/3/25 *AOGCC Witnessed BOP Test to 3500 psi, Annular 2500 psi minimum. *Post rig service coil perforating approved for max gun length of 500'. *Window milling approved on service coil 50-029-20169-02-00 *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement on parent well contingent upon fully cemented liner on upcoming sidetrack. *Variance to 20 AAC 25.036 (c)(2)(A)(iv) with documented well control drills performed by all crews deploying tubulars <2.375" OD without properly sized pipe rams. Provide AOGCC opportunity to witness. 225-055 JLC 7/23/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:53:56 -08'00' 07/23/25 07/23/25 RBDMS JSB 072525 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: May 21, 2025 Re:01-10A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 01-10 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 01-10A Producer: See 01-10 Sundry request for complete pre-rig details - Prior to drilling activities, E-line will set a 4-1/2" wedge. If unable to set the whipstock pre-rig, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 or CDR3 rig. The rig will move in, test BOPE and kill the well. If unable to pre-rig, the rig will set the 4-1/2" wedge and mill a dual string 3.80" window + 10' of formation. The well will kick off drilling in the Ivishak Zone 4. The lateral will continue in Zone 4 and 3 to TD. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will completely isolate and abandon the parent Prudhoe Pool perfs. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: x Reference 01-10 Sundry submitted in concert with this request for full details. 1. Fullbore : MIT-IA and/or MIT-T to 2,500 psi 2. E-Line : Set 4-1/2" wedge at 9364’ MD at 180 degrees ROHS 3. Valve Shop : Pre-CTD Tree Work 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in August 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,396 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” dual string window (4-1/2"x9-5/8") 3. Drill build section: 4.25" OH, ~319' (35 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2250' (12 deg DLS planned). Swap to KWF for liner. 5. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr solid liner (swap to VBRs and test prior to running liner) 6. Pump primary cement job: 31 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL*. 7. Only if not able to do with service coil extended perf post rig – Perforate Liner 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : Set LTP* (if necessary). Set live GLVs. 3. Service Coil : Post rig RPM and perforate (~30’) - see extended perf procedure attached. Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will be accomplished utilizing 3”/3-1/8” (big hole) & 2-3/8” (slim hole) pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (9364' MD -8,777' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,473 psi 4,473 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 562 psi 0 psi 0.06 C DƵĚ,LJĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,925 psi 3,925 psi 8.6 B+C Mud + ECD Combined 4,487 psi 3,925 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -14 psi 548 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,276 psi at 8,800 TVD. (7.2 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,396 psi (from estimated reservoir pressure). Mud Program: x Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. x Fluids >1% hydrocarbons or flammables must go to GNI. x Fluids >15% solids by volume must go to GNI. x Fluids with solids that will not pass through 1/4” screen must go to GNI. x Fluids with PH >11 must go to GNI. Hole Size: x 4.25 hole for the entirety of the production hole section. Liner Program: x 3-1/2", 9.3#, 13Cr Solid: 8,940' MD – 9,354' MD (414' liner) x 3-1/4", 6.6#, 13Cr Solid: 9,354' MD – 9,800' MD (446' liner) x 2-7/8", 6.5#, 13Cr Solid: 9,800' MD – 11,614' MD (1,814' liner) x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary. x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: x BOP diagram is attached. MPD and pressure deployment is planned. x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. x The annular preventer will be tested to 250 psi and 2,500 psi. x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. x Solid 2-7/8” Liner Running Ram Change: Change out 3”/3-1/8” pipe/slip rams (for drilling) to 2-3/8” x 3- 1/2” VBR rams for liner run. Test VBR rams to 250 psi and 3,500 psi. x A X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole. x 2-3/8” safety joint will be utilized while running solid or slotted liner. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre-installed TIW valve). When closing on a 2-3/8” safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. x Request variance to 20 AC 25.036(c)(2)(A)(iv) to deploy tubulars < 2.375” OD without properly sized pipe rams. x 2-3/8” safety joint will be utilized while running 1” / 1-1/4” CS hydril. x Blind/Shear rams will be utilized in place of pipe rams sized for CTD jointed pipe operations as a worst- case shut-in scenario (in place 1” / 1-1/4” CS hydril pipe rams). x The well will be full of KWF prior to running liner or jointed pipe operations. x The BHA will be circulated out of hole prior to laying down BHA for jointed pipe operations. x The well will be flow checked after laying in KWF, before laying down BHA and before making up jointed pipe. x Crew will perform documented well control drills before deploying 1” / 1-1/4” CS hydril pipe. Directional: x Directional plan attached. Maximum planned hole angle is 106°. Inclination at kick off point is 17°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 20,700 ft x Distance to nearest well within pool – 1350 ft Logging: x MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. Perforating: x 30' perforated post rig – See attached extended perforating procedure. x 2" Perf Guns at 6 spf x If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or post rig under this PTD. x The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Prudhoe Pool. x Formations: Top of Prudhoe Pool: 9218’ MD in the parent Anti-Collision Failures: x No Anti-collision failures with the 01-10A WP02 wellpath Hazards: x DS/Pad is an H2S pad. The last H2S reading on 01-10: 22 ppm on 3/8/2025. x Max H2S recorded on DS/Pad: 375 ppm.. x 0 fault crossings expected. x Medium lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) DS/Pad is an H2S pad. Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. x Note: The well will be killed and monitored before making up the initial perfs guns. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. MU nozzle drift BHA (include SCMT and/or RPM log as needed). 3. RIH to PBTD. a. Displace well with weighted brine while RIH (minimum 8.4 ppg to be overbalanced). 4. POOH (and RPM log if needed) and lay down BHA. 5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 6. There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl per previous steps. Re-load well at WSS discretion. 7. At surface, prepare for deployment of TCP guns. 8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed (minimum 8.4 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. 10. Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. a. Perforation details i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Ivishak pool. ii.Perf Length:500’ iii.Gun Length:500’ iv.Weight of Guns (lbs):2300lbs (4.6ppf) 11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation intervals (TBD). POOH. a. Note any tubing pressure change in WSR. 12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface. 13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full. 14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 15. Freeze protect well to 2,000’ TVD. 16. RDMO CTU. Coiled Tubing BOPs Standing Orders for Open Hole Well Control during Perf Gun Deployment Equipment Layout Diagram 8750880088508900895090009050True Vertical Depth (100 usft/in)-3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600 800 Vertical Section at 5.00° (400 usft/in)01-1001-10A wp02Top of Window - 9364'MDEnd 35dls - 9683'MDTD - 11614'MD01-10A wp0201-10A wp02-3000-2500-2000-1500-1000-500South(-)/North(+) (1000 usft/in)-2500 -2000 -1500 -1000 -500 0 500 1000 1500 West(-)/East(+) (1000 usft/in)40004400480052005600600064006800720076008000840088009200938301-108800898201-10A wp02Top of Window - 9364'MDEnd 35dls - 9683'MDTD - 11614'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9364.00 17.23 209.00 8777.67 -2539.79 -458.85 0.00 0.00 -2570.122 9384.00 15.43 209.00 8796.86 -2544.71 -461.57 9.00 180.00 -2575.253 9414.00 4.93 209.00 8826.35 -2549.34 -464.14 35.00 180.00 -2580.094 9444.00 6.70 337.61 8856.27 -2548.85 -465.43 35.00 150.00 -2579.715 9683.15 90.00 357.48 9001.91 -2386.55 -478.38 35.00 20.00 -2419.166 9825.30 106.00 3.47 8982.17 -2246.31 -477.36 12.00 20.00 -2279.377 9966.00 106.00 21.03 8943.39 -2114.66 -448.76 12.00 90.00 -2145.738 10216.00 106.00 349.83 8874.48 -1878.37 -426.29 12.00 -90.00 -1908.389 10426.00 106.00 16.04 8816.60 -1678.52 -416.03 12.00 90.00 -1708.4010 10554.00 106.00 0.07 8781.32 -1557.09 -398.85 12.00 -90.00 -1585.9311 10695.41 90.00 5.80 8761.68 -1417.76 -391.57 12.00 160.00 -1446.4912 10828.64 75.00 0.20 8779.04 -1286.28 -384.58 12.00 -160.00 -1314.9113 10964.00 75.00 17.01 8814.07 -1157.47 -365.08 12.00 90.00 -1184.8914 11144.00 75.00 354.66 8860.66 -985.60 -347.52 12.00 -90.00 -1012.1415 11324.00 75.00 17.01 8907.24 -813.73 -329.96 12.00 90.00 -839.3916 11504.00 75.00 354.66 8953.83 -641.86 -312.41 12.00 -90.00 -666.6417 11614.00 75.00 8.32 8982.30 -535.89 -309.66 12.00 90.00 -560.84Depth From Depth To Survey/Plan Tool173.00 2617.00 1 : Camera based mag multi sho (01-10)3_CB-Film-MMS2945.00 9364.00 Survey #2 (01-10) 3_CB-Film-MSS19364.00 11614.00 01-10A wp02 (01-10A) 3_MWDSECTION DETAILSSURVEY PROGRAMProject: Prudhoe BaySite: 01Well: 01-10Wellbore: 01-10APlan: 01-10A wp02REFERENCE INFORMATIONCoordinate(N/E) Reference: Well 01-10, True NorthVertical (TVD) Reference: KB @ 72.00usft (18 : 10 9/2/1975 00:00)Measured Depth Reference: KB @ 72.00usft (18 : 10 9/2/1975 00:00)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureParent Wellbore: 01-10Top of Window: 9364.00Northing: 5939499.90Easting: 698939.82Lattitude: 70° 14' 19.5506 NLongitude: 148° 23' 36.3909 WNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04REFERENCE INFORMATIONWELLBORE DETAILSWELL DETAILSHilcorp Alaska, LLCPROJECT DETAILS ! 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ell Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2-3/8" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 3.0" Pipe / Slip 9.54 ft CL 2-3/8" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3"or 3-1/8" Pipe / Slip Well Date Quick Test Sub to Otis Top of 7" Otis Top of Annular C L Annular Bottom Annular CL Blind/Shears CL 2-3/8" Pipe / Slips B6 B5 B8 B7 Choke Line Kill Line CL 3" Pipe / Slip CL 2-3/8" Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR3-AC BOP Schematic CDR3 Rig's Drip Pan Fill Line Normally Disconnected 2" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3" Pipe / Slip neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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. 225-055 PBU 01-10A PRUDHOE BAY, PRUDHOE OILPRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 01-10AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250550Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes Entire Well lies within ADL0028329.2 Lease number appropriateYes Yes: Two previous applications for 01-10A were submitted. 194-070 was canceled and 213-010 expired.3 Unique well name and numberYes These undrilled wells have been renamed 01-10AXX in AOGCC's databases.4 Well located in a defined poolYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes See Property Plat on p. 11.8 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 waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes *Variance as per 20 AAC 25.112(i): Approved with fully cemented liner.25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes *Variance to 20 AAC 25.036 (c)(2)(A)(iv)for tubulars < 2.375".29 BOPEs, do they meet regulationYes30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes DS/Pad is an H2S pad. The last H2S reading on 01-10: 22 ppm on 3/8/2025.33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No Measures required. This drillsite is an H2S pad.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.374 psi/ft (7.2 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/23/2025ApprJJLDate6/16/2025ApprSFDDate7/23/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 7/23/2025
