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Home My WebLink About225-104Alaska 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 Field, Aurora Oil, PBU J-03A Hilcorp Alaska, LLC Permit to Drill Number: 225-104 Surface Location: 860' FNL, 1245' FEL, Sec 09, T11N, R13E, UM, AK Bottomhole Location: 1346' FSL, 1580' FEL, Sec 04, T11N, R13E, 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 3rd day of November 2025. 9952, 10032, 10150, 10220 By Grace Christianson at 12:55 pm, Oct 03, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.10.03 12:19:10 - 08'00' Sean McLaughlin (4311) 225-104 J.Lau 11/3/25 TS 10/30/25 *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. 50-029-20025-01-00 DSR-10/15/25 *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. *Waiver to 20 AAC 25.036 (c)(2)(A)(iv) with compliance to rules in CO 823. 11/03/25 11/03/25 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: October 3, 2025 Re:J-03A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well J-03 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for J-03A Producer: See J-03 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock and MIT. Coil will cement the 4-1/2"x9-5/8" tubing tail annulus (for dual string exit). E-line will set a 4-1/2" packer 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 and test BOPE. If unable to pre-rig, the rig will set the 4-1/2" packer whipstock and mill a 4-1/2"x9-5/8" dual string 3.80" window + 10' of formation. The well will kick off drilling in the Ivishak Zone 4 and lands in 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: Reference J-03 Sundry submitted in concert with this request for full details. 1. Slickline : Dummy WS drift 2. Coil : Set cement retainer at ~9,800' MD. Squeeze 4-1/2" x 9-5/8" IA at KOP (below production packer), by pumping ~40 bbls of 15.8ppg cement tubing tail in place in preparation for dual string exit. Target TOC 9,250' MD. 3. E-Line : Set 4-1/2" Packer Whipstock at 9,760 MD at 180 degrees ROHS 4. Fullbore : MIT-IA and/or MIT-T to 2,500 psi (min) 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in December 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,378 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80 Dual String 4-1/2"x9-5/8" Window 3. Drill build section: 4.25" OH, ~454' (25 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~1,960' (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 6. Pump primary cement job*: 35 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL. Set LTP. If high losses are encountered during cement job and it is deemed necessary, a cement down squeeze from TOL to loss zone will be performed with the rig or service coil (if performed by service coil see future sundry). 7. Only if not able to do with service coil extended perf post rig Perforate Liner with 1-1/4" CS Hydril 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. 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 (9,760' MD -8,742' TVD) Pumps On Pumps O A Target BHP at Window (ppg)4,455 psi 4,455 psi 9.8 B -586 psi 0 psi 0.06 C 3,909 psi 3,909 psi 8.6 B+C Mud + ECD Combined 4,495 psi 3,909 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 0 psi 546 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 3,258 psi at 8,800 TVD. (7.1 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,378 psi (from estimated reservoir pressure). Mud Program: Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. Disposal: All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. Fluids >1% hydrocarbons or flammables must go to GNI. Fluids >15% solids by volume must go to GNI. Fluids with solids that will not pass through 1/4 screen must go to GNI. Fluids with PH >11 must go to GNI. Hole Size: 3.8 to 4.25 hole for the entirety of the production hole section. Liner Program: 3-1/2", 9.3#, 13Cr/Solid: 9,060' MD 9,090' MD (30' liner) 3-1/4", 6.6#, 13Cr/Solid: 9,090' MD 10,350' MD (1,260' liner) 2-7/8", 6.5#, 13Cr/Solid: 10,350' MD 12,174' MD (1,824' liner) The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary. A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Jointed Pipe Work String Program: 1-1/4" CS Hydril, 3.02#, P-110: up to 4,000' MD Used for contingency CTD liner cleanout/logging runs, deployment of perforation guns (if performed by rig), inner string 2-3/8 liner cement jobs and contingency inner string 2-7/8 liner cement jobs. Well Control: BOP diagram is attached. MPD and pressure deployment is planned. Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. The annular preventer will be tested to 250 psi and 2,500 psi. 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. A X-over shall be available to be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole. 2 3/8" safety joint will be utilized while running solid/slotted liner, perforation guns and CS Hydril jointed pipe. 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. CO823 Hilcorp CTD Qualification Blind-Shear Test: CDR2 test on 09/04/2025 (see Hilcorp Alaska CTD CO823 Qualification report previously sent to AOGCC for more information). CO823 Safety Joint Drills: Provide AOGCC opportunity to witness once per well that a CTD liner is ran. Directional: Directional plan attached. Maximum planned hole angle is 100°. Inclination at kick off point is 31°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line 16,975 ft Distance to nearest well within pool 800 ft Logging: MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section. Real time bore pressure to aid in MPD and ECD management. Perforating: 30' perforated post rig See attached extended perforating procedure. 2" Perf Guns at 6 spf 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. The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Prudhoe Pool. Formations: Top of Prudhoe Pool is 9,586 MD in the parent Anti-Collision Failures: All Wells Pass AC scan Hazards: DS/Pad is not an H2S pad. The last H2S reading on J-03: 12 ppm on 9/11/2021. Max H2S recorded on DS/Pad: 36 ppm. 0 fault crossings expected. Medium lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka (907-223-3087) Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. 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 doesnt 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 TOC ~9,250' Map Date: 8/11/2025 True Vertical Depth (100 usft/in)-4200 -4000 -3800 -3600 -3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 South(-)/North(+) (800 usft/in)-2800 -2400 -2000 -1600 -1200 -800 -400 0 400 Well Date Quick Test Sub to Otis - Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular CL Annular Bottom Annular CL Blind/Shears CL Coiled Tubing Pipe / Slips Kill Line Choke Line CL BHA Pipe / Slip CL Coiled Tubing Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR#-AC BOP Schematic CDR Rig's Drip Pan Fill Line Normally Disconnected HP hose to Micromotion LP hose open ended to Flowline (optional) Hydril 7 1/16" Annular Blind/Shear CT Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross CT Pipe/Slips BHA Pipe / Slips nneeeeeceeeeeeeeeeeeeeeeeeeeeeeeeeeee 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 225-104 PRUDHOE BAY PBU J-03A WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name: PRUDHOE BAY UNIT J-03AInitial Class/TypeDEV / 1-OILGeoArea890Unit11650On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2251040Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes Entire Well lies within ADL028281.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 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 waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)No16 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 pitNo *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug w/ 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 *Waiver to 20 AAC 25.036 (c)(2)(A)(iv) with compliance to rules in CO 823.29 BOPEs, do they meet regulationYes 5K.30 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 shutdownYes33 Is presence of H2S gas probableNA The last H2S reading on J-03: 12 ppm on 9/11/2021.34 Mechanical condition of wells within AOR verified (For service well only)No J-Pad wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is 0.369 psi/ft (7.1 ppg EMW)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]ApprTCSDate10/30/2025ApprJJLDate11/3/2025ApprTCSDate10/30/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 11/3/2025