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Home My WebLink About225-070Nolan 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: 10/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251016 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# END 2-36 50029220140000 190024 9/17/2025 BAKER SPN T40994 END 2-74 50029237850000 224024 9/22/2025 HALLIBURTON PATCH T40995 KU 12-17 50133205770000 208089 9/23/2025 YELLOWJACKET TEMP-CALIPER T40996 KU 24-7RD 50133203520100 205099 9/24/2025 YELLOWJACKET TEMP-CALIPER T40997 M-25 50733203910000 187086 8/31/2025 YELLOWJACKET CALIPER T40998 MPC-22A 50029224890100 195198 10/4/2025 READ CaliperSurvey T40999 MPF-61 50029225820000 195117 9/27/2025 READ CaliperSurvey T41000 MPU H-16 50029232270000 204190 10/6/2025 HALLIBURTON COILFLAG T41001 NIK SI17-SE2 50629235120000 214041 9/23/2025 HALLIBURTON IPROF T41002 NS-19 50029231220000 202207 9/8/2025 HALLIBURTON COILFLAG T41003 NS-19 50029231220000 202207 9/15/2025 HALLIBURTON COILFLAG T41003 ODSN-26 50703206420000 211121 10/7/2025 HALLIBURTON MFC24 T41004 PBU 01-25A 50029208740100 225056 9/13/2025 BAKER MRPM T41005 PBU 01-25A 50029208740100 225056 9/13/2025 HALLIBURTON RBT-COILFLAG T41005 PBU 01-31A 50029216260100 225070 9/22/2025 BAKER MRPM T41006 PBU 01-31A 50029216260100 225070 9/23/2025 HALLIBURTON RBT-COILFLAG T41006 PBU 05-09A 50029202540100 199014 9/18/2025 READ ArcherVIVID T41007 PBU 07-16A 50029208560100 201153 9/20/2025 HALLIBURTON RBT T41008 PBU 07-23C 50029216350300 225043 7/4/2025 BAKER MRPM T41009 PBU 13-24B 50029207390200 224087 9/18/2025 HALLIBURTON RBT T41010 PBU 15-11C 50029206530300 210163 9/6/2025 HALLIBURTON RBT T41011 PBU 15-49C 50029226510300 215129 9/10/2025 HALLIBURTON RBT T41012 PBU H-07B 50029202420200 225064 9/30/2025 HALLIBURTON RBT-COILFLAG T41013 PBU P19 L1 50029220946000 212056 10/3/2025 HALLIBURTON RBT T41014 PBU S-14A 50029208040100 204071 9/25/2025 HALLIBURTON RBT T41015 PBU V-105 50029230970000 202131 9/30/2025 HALLIBURTON RMT3D T41016 Please include current contact information if different from above. T41006PBU 01-31A 50029216260100 225070 9/22/2025 BAKER MRPM PBU 01-31A 50029216260100 225070 9/23/2025 HALLIBURTON RBT-COILFLAG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 13:17:06 -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: 09/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 01-31A PTD: 225-070 API: 50-029-21626-01-00 FINAL LWD FORMATION EVALUATION LOGS (09/09/2025 to 09/18/2025) 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. 225-070 T40917 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.23 08:15:47 -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 01-31A Hilcorp Alaska, LLC Permit to Drill Number: 225-070 Surface Location: 1194' FNL, 1544' FEL, Sec. 08, T10N, R15E, UM, AK Bottomhole Location: 1967' FSL, 1257' FEL, Sec. 08, 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 21 st day of August 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.21 13:20:56 -08'00' 9220, 9245, 9277, 9332,9455, 9493, 9503 By Grace Christianson at 2:22 pm, Jul 18, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.02 09:47:22 - 08'00' Sean McLaughlin (4311) A.Dewhurst 19AUG25 *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 50-029-21626-01-00225-070 *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. JJL 8/18/25 *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 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.21 13:21:11 -08'00' 08/21/25 08/21/25 RBDMS JSB 082625 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: July 2, 2025 Re:01-31A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 01-31 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 01-31A Producer: See A-06A Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock and caliper. 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. The rig will set the 4-1/2"x9-5/8" whipstock and mill a single string 3.80" window + 10' of formation. The well will kick off drilling in the Shublik and land in Ivishak Zone 2. The lateral will continue in Zone 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 01-31 Sundry submitted in concert with this request for full details. 1. Slickline : Dummy WS drift and Caliper 2. Valve Shop : Pre-CTD Tree Work 3. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in September 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. Set 4-1/2" x 9-5/8" HEW. TOWS at 9108' @ 0 deg RHOS 3. Mill 3.80” Window. 4. Drill build section: 4.25" OH, ~285' (28 deg DLS planned). 5. Drill production lateral: 4.25" OH, ~2216' (12 deg DLS planned). Swap to KWF for liner. 6. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr solid liner (swap to VBRs and test prior to running liner) 7. Pump primary cement job: 33 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL*. 8. Only if not able to do with service coil extended perf post rig – Perforate Liner 9. Freeze protect well to a min 2,200' TVD. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : SBHPS, set LTP* (if necessary). Set live GLVs. 3. Service Coil : Post rig RPM, CBL and perforate (~30’) 41 bbls of cement, see attached email correspondence - JJL 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 (9115' MD -8,637' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,401 psi 4,401 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ-;ƉƐŝͬŌͿ 546 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,862 psi 3,862 psi 8.6 B+C Mud + ECD Combined 4,409 psi 3,862 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -8 psi 539 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 3-1/4", 6.6#, 13Cr Solid: 8,750' MD – 9,600' MD (850' liner) x 2-7/8", 6.5#, 13Cr Solid: 9,600' MD – 11,616' MD (2,016' 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 107°. Inclination at kick off point is 23°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 22900 ft x Distance to nearest well within pool – 1090 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 2.5" 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 MD in the parent: 9036’ MD Anti-Collision Failures: o The 01-01 (Abandoned) has a 15’ center to center distance from 01-31A WP01 at 9185’ MD (01-31A depth) o Current Active wellbore is 01-01C which sidetracked from the parent bore at 5373’ MD. Hazards: x DS/Pad is an H2S pad. The last H2S reading on 01-31: 14 ppm on 10/1/24. x Max H2S recorded on DS/Pad: 100 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 Prudhoe 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 8500860087008800890090009100True Vertical Depth (200 usft/in)-200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 Vertical Section at 175.00° (400 usft/in)01-3101-31A wp01Top of Window - 9115'MDEnd 28dls - 9400'MDTD - 11616'MD01-31A wp01-2500-2000-1500-1000-5000South(-)/North(+) (1000 usft/in)500 1000 1500 2000 2500 3000 3500 4000 4500 West(-)/East(+) (1000 usft/in)4800 5200 56 00 6000 6400 6800 7200 76008000840088009200921701-318800897001-31A wp01Top of Window - 9115'MDEnd 28dls - 9400'MDTD - 11616'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9115.00 23.58 102.01 8637.65 80.90 2135.85 0.00 0.00 105.562 9135.00 25.38 102.01 8655.85 79.18 2143.96 9.00 0.00 107.983 9205.00 44.98 102.01 8712.78 70.83 2183.22 28.00 0.00 119.724 9400.38 69.00 162.57 8825.59 -39.03 2286.01 28.00 85.00 238.125 9526.00 69.00 178.72 8870.61 -154.36 2305.01 12.00 90.00 354.676 9751.00 69.00 149.80 8951.24 -354.40 2361.39 12.00 -90.00 558.867 9936.16 90.00 157.24 8984.84 -516.51 2441.69 12.00 20.00 727.368 10087.23 107.00 163.62 8962.57 -656.63 2491.70 12.00 20.00 871.309 10208.00 107.00 178.78 8927.26 -770.44 2509.32 12.00 90.00 986.2110 10328.00 107.00 163.72 8892.18 -883.53 2526.72 12.00 -90.00 1100.3911 10560.00 107.00 192.84 8824.35 -1102.91 2533.31 12.00 90.00 1319.5112 10670.00 107.00 179.03 8792.19 -1207.29 2522.46 12.00 -90.00 1422.5413 10820.19 90.00 185.11 8770.05 -1355.11 2516.95 12.00 160.00 1569.3214 10962.33 74.00 179.12 8789.79 -1495.25 2511.64 12.00 -160.00 1708.4615 11073.00 74.00 192.93 8820.29 -1600.79 2500.51 12.00 90.00 1812.6316 11253.00 74.00 170.46 8869.91 -1772.63 2495.42 12.00 -90.00 1983.3817 11433.00 74.00 192.93 8919.52 -1944.48 2490.34 12.00 90.00 2154.1318 11616.00 74.00 170.09 8969.96 -2119.17 2485.74 12.00 -90.00 2327.75Depth From Depth To Survey/Plan Tool100.08 4300.51 Survey #2 (01-31) 3_Gyro-CT_Drill pipe4400.00 9115.00 1 : Sperry-Sun BOSS gyro multi (01-31)3_Gyro-SR-GMS19115.00 11616.00 01-31A wp01 (01-31A) 3_MWDSECTION DETAILSSURVEY PROGRAMProject: Prudhoe BaySite: 01Well: 01-31Wellbore: 01-31APlan: 01-31A wp01REFERENCE INFORMATIONCoordinate(N/E) Reference: Well 01-31, True NorthVertical (TVD) Reference: Kelly Bushing / Rotary Table @ 70.00usft )Measured Depth Reference: Kelly Bushing / Rotary Table @ 70.00usft )Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureParent Wellbore: 01-31Top of Window: 9115.00Northing: 5939734.50Easting: 698889.50Lattitude: 70° 14' 21.8702 NLongitude: 148° 23' 37.6732 WNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04REFERENCE INFORMATIONWELLBORE DETAILSWELL DETAILSHilcorp Alaska, LLCPROJECT DETAILS01-31A wp01 ! 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" # $ %& . - / 7 ' 1 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 1 Christianson, Grace K (OGC) From:Ryan Ciolkosz <ryan.ciolkosz@hilcorp.com> Sent:Wednesday, July 23, 2025 11:04 AM To:Lau, Jack J (OGC) Cc:Joseph Lastufka Subject:RE: [EXTERNAL] PBU 01-31A PTD Jack, Looks like I missed the 4-1/2” x 3-1/4” annulus cement volume in my calcs. I am getting 41 bbls of cement now. Thanks, Ryan Ciolkosz Drilling Engineer | C: 907.244.4357 3800 Centerpoint Dr. Suite 1400 | Anchorage, Alaska 99503 44.4357 | O: 907.564.4413 H From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, July 18, 2025 3:43 PM To: Ryan Ciolkosz <ryan.ciolkosz@hilcorp.com> Subject: [EXTERNAL] PBU 01-31A PTD Ryan, Would you mind checking your cement calcs for PBU 01-31A PTD? Your calcs were a little shy compared to mine to TOL. Were you planning to pump excess? Have a great weekend. Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 OƯice (907) 227-2760 Cell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. 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Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PRUDHOE OIL PRUDHOE BAY PBU 01-31A 225-070 WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 01-31AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250700Field & 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): Approved for alternate abandonment plug with fully cemented liner25If a re-drill, has a 10-403 for abandonment been approvedYesThe 01-01 (Abandoned) has a 15’ center to center distance from 01-31A WP01 at 9185’ MD (01-31A26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYesVariance to 20 AAC 25.036 (c)(2)(A)(iv) approved w/ WC Drills for <2.375" OD tubulars29BOPEs, do they meet regulationYes5K30BOPE 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 01-31: 14 ppm on 10/1/24. Max H2S recorded on DS/Pad: 100 ppm.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]ApprADDDate19-Aug-25ApprJJLDate18-Aug-25ApprADDDate19-Aug-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/21/2025