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225-052
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: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250912 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24 NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey Please include current contact information if different from above. T40874 T40875 T40875 T40875 T40875 T40876 T40877 T40878 T40879 T40879 T40880 T40881 T40882 T40883 T40884 T40885 T40886 T40887 T40888 T40889 T40890 T40891 T40892 T40893 PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 14:33:03 -08'00' 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: 09/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250910 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 213-26T 50283202040000 225038 6/14/2025 AK E-LINE CBL MPU C-21 50029207530000 182081 7/8/2025 AK E-LINE Caliper MPU M-62 50029237440000 223006 6/23/2025 READ Caliper Survey PBU 01-13A 50029202700100 225052 8/17/2025 BAKER MRPM PBU 01-30A 50029216060100 225050 8/7/2025 BAKER MRPM PBU 07-24A 50029209450100 225045 8/3/2025 BAKER MRPM PBU N-12 50029205570000 181014 8/5/2025 BAKER SPN PBU PSI-09 50029230950000 202124 7/17/2025 HALLIBURTON WFL-TMD3D Please include current contact information if different from above. T40860 T40861 T40862 T40863 194-080 T40864 T40865 T40866 T40867 PBU 01-13A 50029202700100 225052 8/17/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.10 11:27:53 -08'00' 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: 09/04/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 01-13A PTD: 225-052 API: 50-029-20270-01-00 FINAL LWD FORMATION EVALUATION LOGS (08/05/2025 to 08/13/2025) 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. 225-052 T40851 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.04 14:36:46 -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 North Slope, LLC 3800 Centerpoint, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay, Prudhoe Oil, PBU 01-13A Hilcorp North Slope, LLC Permit to Drill Number: 225-052 Surface Location: 662’ FNL, 733’ FWL, Sec. 08, T10N, R15E, UM, AK Bottomhole Location: 1797’ FNL, 1211’ FEL, Sec. 07, T10N, R15E, 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 16th day of July, 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.16 09:07:10 -08'00' Joe Engel for Sean McLaughlin By Grace Christianson at 1:45 pm, May 13, 2025 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 225-052 *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) approved with documented well control drills performed by all crews deploying tubulars <2.375" OD without properly sized pipe rams. Provide AOGCC opportunity to witness drills. JJL 6/16/25 A.Dewhurst 15JUL25 50-029-20270-01-00 *&: 7/16/2025 7/16/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.16 09:07:23 -08'00' RBDMS JSB 071825 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: May 8, 2025 Re:01-13A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 01-13 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 01-13A Producer: See 01-13 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock and MIT. E-line or coil will mill the XN-nipple. E-line will set a 4-1/2" whipstock. 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" whipstock and mill a single string 3.80" window + 10' of formation. The well will kick off drilling in the Shublik and lands in Ivishak Zone 2. The lateral will continue in Zone 4, 3 and 2 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 01-13 Sundry submitted in concert with this request for full details. 1.Slickline : Dummy WS drift, DMY GLVs 2.E-Line : Set 4-1/2" NS Whipstock at 9895’ MD at 180 degrees ROHS 3. Fullbore : MIT-IA and/or MIT-T to 2500 psi 4. Coil : Mill XN nipple (at 9685' MD) 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in July 18th, 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2396 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Dual String Window (4-1/2"x9-5/8") @ 180 deg ROHS 3. Drill build section: 4.25" OH, ~440' (35 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2055' (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: 33 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. 4. Testing : Portable test separator flowback. 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 (9895' MD -8,706' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,437 psi 4,437 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 594 psi 0 psi 0.09 C DƵĚ,LJĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,893 psi 3,893 psi 8.6 B+C Mud + ECD Combined 4,487 psi 3,893 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -50 psi 543 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 2396 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 3-1/4", 6.6#, 13Cr Solid: 9,600' MD – 10,400' MD (900' liner) x 2-7/8", 6.5#, 13Cr Solid: 10,400' MD – 12,390' MD (1,990' 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 102°. Inclination at kick off point is 30°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 19,560 ft x Distance to nearest well within pool – 1300 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: 9855’ MD in the parent Anti-Collision Failures: x No collision risks with 01-13A WP02 Hazards: x DS/Pad is an H2S pad. The last H2S reading on 01-13: 50 ppm on 2/18/24. 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) 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 % Prudhoe Bay Unit ADL028330 ADL028329 Sec. 8 Sec. 17 Sec. 5 Sec. 7 (612) Sec. 18 (615) Sec. 6 (609) U010N015E DS1 01-13A_SHL 01-13A_TPH 01-13A_BHL 01-13A Legend 01-13A_BHL 01-13A_SHL %01-13A_TPH Other Surface Holes (SHL) Other Bottom Holes (BHL) Other Well Paths Pad Footprint Oil and Gas Unit Boundary AIO_4G CO_341J Map Date: 5/7/2025 0 330 660 Feet Document Path: O:\AWS\GIS\Dropbox\Julieanna Potter\Project_Handoff\Project_Handoff.aprxNAD 1927 StatePlane Alaska 4 FIPS 5004 Prudhoe Bay Unit 1-13A Well wp02_v2 u 1:10,000 8600870088008900900091009200True Vertical Depth (200 usft/in)-3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 Vertical Section at 0.00° (400 usft/in)01-1301-13A wp02Top of Window - 9895'MDEnd 35dls - 10248'MDTD - 12390'MD01-13A wp0201-13A wp02-3500-3000-2500-2000-1500-1000-500South(-)/North(+) (1000 usft/in)-3500 -3000 -2500 -2000 -1500 -1000 -500 0 West(-)/East(+) (1000 usft/in)44004 80 05 2 00 56 0 0 60 0 0640 0 680 0 7 2 0 0 7 6 0 0 8 0 0 0 84 0 0 01-07 48 00 5 2 0 0 5 6 0 0 6 000 6 4 0 0 6 80 0 01 -24 8 0 0 0 8 4 00 8800 9200927501-02880001-30A wp03520056006000640068007200760080008 4 0 0 8 80 0 92 00 9 25 401-3 0400044004800 5 20 0560 0 6 00 0 640 068 0 0 72 00 7 60 0 8 0 00 84 0 0 880 0 92 00 9 2 8 101-2 5400044004800 52005600600001-185200560060006400680072007 6 0 0 8 0 0 0 8400 01-18A4400480052005600600064006800720076008000840088009200945001-136 800 72 00 7600 8000 840001-148800 01-25A wp038800915001-13A wp02Top of Window - 9895'MDEnd 35dls - 10248'MDTD - 12390'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9895.00 30.20 219.90 8706.62 -3285.98 -1824.39 0.00 0.00 -3285.982 9915.00 28.40 219.90 8724.06 -3293.49 -1830.66 9.00 180.00 -3293.493 9980.00 5.65 219.90 8785.81 -3307.99 -1842.79 35.00 180.00 -3307.994 10080.00 31.63 342.99 8881.12 -3286.01 -1853.97 35.00 130.00 -3286.015 10247.89 90.00 351.53 8959.60 -3148.62 -1881.70 35.00 10.00 -3148.626 10335.39 96.00 0.16 8955.01 -3061.60 -1888.04 12.00 55.00 -3061.607 10455.00 96.00 345.72 8942.51 -2943.85 -1902.62 12.00 -90.00 -2943.858 10675.00 96.00 12.28 8919.51 -2727.05 -1906.41 12.00 90.00 -2727.059 10870.00 96.00 348.74 8899.13 -2534.48 -1904.71 12.00 -90.00 -2534.4810 10945.28 101.50 355.99 8887.67 -2460.82 -1914.61 12.00 52.00 -2460.8211 11066.00 101.50 10.78 8863.60 -2343.06 -1907.64 12.00 90.00 -2343.0612 11276.00 101.50 345.06 8821.73 -2139.14 -1915.06 12.00 -90.00 -2139.1413 11444.00 101.50 5.64 8788.24 -1975.93 -1928.34 12.00 90.00 -1975.9314 11545.81 90.00 1.49 8778.05 -1875.02 -1922.10 12.00 -160.00 -1875.0215 11822.77 59.00 348.85 8851.45 -1612.73 -1942.02 12.00 -160.00 -1612.7316 12003.00 59.00 14.09 8944.27 -1459.53 -1938.09 12.00 90.00 -1459.5317 12203.00 57.92 345.87 9050.44 -1291.76 -1937.91 12.00 -100.00 -1291.7618 12340.00 57.92 5.27 9123.19 -1176.58 -1946.82 12.00 90.00 -1176.5819 12390.00 57.92 12.35 9149.75 -1134.74 -1940.34 12.00 90.00 -1134.74Depth From Depth To Survey/Plan Tool100.00 9895.00 1 : Camera based gyro multisho (01-13)3_CB-Film-GMS29895.00 12390.00 01-13A wp02 (01-13A) 3_MWDSECTION DETAILSSURVEY PROGRAMProject: Prudhoe BaySite: 01Well: 01-13Wellbore: 01-13APlan: 01-13A wp02REFERENCE INFORMATIONCoordinate(N/E) Reference: Well 01-13, True NorthVertical (TVD) Reference: KB @ 73.00usft (01-13 OKB)Measured Depth Reference: KB @ 73.00usft (01-13 OKB)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureParent Wellbore: 01-13Top of Window: 9895.00Northing: 5940243.77Easting: 698062.97Lattitude: 70° 14' 27.0915 NLongitude: 148° 24' 1.3022 WNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04REFERENCE INFORMATIONWELLBORE DETAILSWELL DETAILSHilcorp Alaska, LLCPROJECT DETAILS ! 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Well 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 neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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. 225-052 PRUDHOE OIL PBU 01-13A PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 01-13AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250520Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL0283292Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYes21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitYesVariance as per 20 AAC 25.112(i) with fully cemented liner25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYesVariance to 20 AAC 25.036 (c)(2)(A)(iv) for tubulars <2.375" OD approved with documented well control drills29BOPEs, do they meet regulationYes30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesThe last H2S reading on 01-13: 50 ppm on 2/18/24.33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)NoDS 01 wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYesExpected reservoir pressure gradient is 7.2 ppg EMW. MPD to maintain an ECD of 9.8 ppg EMW.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate15-Jul-25ApprJJLDate16-Jun-25ApprADDDate15-Jul-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 7/16/2025
