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Home My WebLink About224-134Nolan 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: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -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: 4/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#2025010 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 211-26 50283201280000 208112 1/27/2025 AK E-LINE PPROF T40287 END 1-41 50029217130000 187032 3/13/2025 HALLIBURTON MFC40 T40288 END 2-14 50029216390000 186149 3/12/2025 HALLIBURTON MFC40 T40289 END 3-33A 50029216680100 203215 3/23/2025 HALLIBURTON COILFLAG T40290 GP AN-17A 50733203110100 213049 12/29/2024 AK E-LINE Perf T40291 KALOTSA 3 50133206610000 217028 3/3/2025 AK E-LINE PPROF T40292 KU 12-17 50133205770000 208089 1/28/2025 AK E-LINE Perf T40293 MPI 2-14 50029216390000 186149 2/17/2025 AK E-LINE Plug/Cement T40294 NCIU A-21 50883201990000 224086 3/28/2025 AK E-LINE Plug-Perf T40295 ODSN-25 50703206560000 212030 3/7/2025 HALLIBURTON CORRELATION T40296 PBU 02-08B 50029201550200 198095 3/17/2025 HALLIBURTON RBT T40297 PBU D-08B 50029203720200 225007 3/22/2025 HALLIBURTON RBT T40298 PBU J-25B 50029217410200 224134 3/10/2025 HALLIBURTON RBT T40299 PBU K-12D 50029217590400 224099 3/18/2025 HALLIBURTON RBT T40300 PBU K-19B 50029225310200 215182 3/27/2025 HALLIBURTON RBT T40301 PBU L1-15A 50029219950100 203120 3/27/2025 HALLIBURTON PPROF T40302 PBU M-207 50029238070000 224141 3/18/2025 HALLIBURTON IPROF T40303 PBU P1-04 50029223660000 193063 3/28/2025 HALLIBURTON PPROF T40304 PBU W-220A 50029234320100 224161 3/11/2025 HALLIBURTON RBT T40305 Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40299PBU J-25B 50029217410200 224134 3/10/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.10 13:48:56 -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: 03/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU J-25B PTD: 224-134 API: 50-029-21741-02-00 FINAL LWD FORMATION EVALUATION LOGS (02/22/2025 to 03/02/2025) 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. 224-134 T40219 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 12:38:26 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-048 JBR 03/13/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Arrive at rig when requested. Rig was not ready to test BOPE having trouble getting a shell test. Start testing all H2s and LEL alarms while they trouble shoot. Found upper IBOP to be the issue. They requested to start testing and c/o IBOP at end of testing when other crew is on tower. Tested BOPE with 4 1/2" and 5" test joints with no failures. Tested PVT's while crew changed out upper IBOP. Tested upper and lower IBOP at end of test. Both Pass. Rig was exceptionally clean and organized. Long test due to c/o of UIBOP and crew change. Test Results TEST DATA Rig Rep:Sonny ClarkOperator:Oil Search (Alaska), LLC Operator Rep:Rob Oneal Rig Owner/Rig No.:Parker 272 PTD#:2241430 DATE:1/1/2025 Type Operation:DRILL Annular: 250/3600Type Test:BIWKLY Valves: 250/3600 Rams: 250/3600 Test Pressures:Inspection No:bopSTS250102073023 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 13 MASP: 1556 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 4-1/2"X7"Va P #2 Rams 1 Blind/Shear P #3 Rams 1 9 5/8"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 2-1/16",3-1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P2990 Pressure After Closure P2000 200 PSI Attained P17 Full Pressure Attained P68 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2150 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P23 #1 Rams P6 #2 Rams P5 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9999 9 9 9 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 Field, Prudhoe Pool, PBU J-25B Hilcorp Alaska, LLC Permit to Drill Number: 224-134 Surface Location: 800' FNL, 1881' FEL, Sec 09, T11N, R13E, UM, AK Bottomhole Location: 1135' FSL, 680' FWL, Sec 03, 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, Gregory C. Wilson Commissioner DATED this 26th day of December 2024. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.26 14:43:05 -09'00' 3-1/2"x3-1/4" Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.10.29 12:05:35 - 08'00' Sean McLaughlin (4311) February 1, 2025 By Grace Christianson at 4:07 pm, Oct 29, 2024 224-134 50-029-21741-02-00 Witnessed BOP Test to 3500 psi, Annular to 2500 psi. DSR-10/29/24A.Dewhurst 30OCT24MGR24DEC2024 * Variance request to 20 AAC 25.112 (i) is approved for alternate plug placement with all drilling within the PBU oil pool and abandonment to be completed with fully cemented liner in upcoming sidetrack. * Post rig service coil perforating gun length not to exceed 500' for open hole deployments. * Waiver request to 20 AAC 25.036 is denied. Pipe rams required per regulations. MEUIRUMOF Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.26 14:40:02 -09'00' 12/26/24 12/26/24 RBDMS JSB 123024 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: October 29, 2024 Re:J-25B Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well J-25A with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for J-25B Producer: See J-25A Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock and MIT. E-line will set a 4-1/2"x5-1/2" whipstock. Coil will mill window pre-rig. If unable to set the whipstock or milling the window, for scheduling reasons, 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 set whipstock pre-rig, the rig will set the whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Ivishak Zone 4 and lands in Ivishak Zone 1. The lateral will continue in Zone 1 to TD. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” L-80 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-25A 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"x5-1/2" whipstock 3. Service Coil : Mill 3.80" window (if window not possible, mill with rig). Give AOGCC 24hr notice prior to BOPE test. Test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 2,359 psi. 4.Valve Shop : Bleed production, flow and GL lines down to zero and blind flange. 5. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in February 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,359 psi). 2. Mill 3.80” Window (if not done pre-rig). 3. Drill build section: 4.25" OH, ~638' (18 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2,676' (12 deg DLS planned). Swap to KWF for liner. 5. Run 3-1/2” x 3-1/4” x 2-7/8” L-80 solid liner. 6. Pump primary cement job: 47 bbls, 15.3 ppg Class G 1.24 yield, 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 : SBHPS, set LTP* (if necessary). Set live GLVs. 3. Service Coil : RPM and Post rig perforate (~200’). 4. Testing : Portable test separator flowback. PTD 224-134 Sundry 324-618 Pipe rams sized for running liner. - mgr 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 (8,728’ MD -8,645' TVD) Pumps On Pumps O A Target BHP at Window (ppg)4,405 psi 4,405 psi 9.8 B - ECD 349 psi 0 psi 0.04 C 3,866 psi 3,866 psi 8.6 B+C Mud + ECD Combined 4,215 psi 3,866 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 190 psi 539 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 3,239 psi at 8,800 TVD. (7.1 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,359 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: 4.25" hole for the entirety of the production hole section. Liner Program: 3-1/2", 9.3#, 13Cr/Solid: 8,310' MD – 8,720' MD (410' liner) 3-1/4", 6.6#, 13Cr/Solid: 8,720' MD – 9,150' MD (430' liner) 2-7/8", 6.5#, 13Cr/Solid: 9,150' MD – 12,044' MD (2,894' 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. 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. 20 AAC 25.036 (c)(2)(A)(iv): Waiver Request . 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 of 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams). a. Blind/Shear rams are preferred over pipe rams in CTD jointed pipe operations, because liners and jointed pipe strings for CTD are only ~500-3500’ long and therefore are not suitable killstrings – having a circulation point of less than ~3500’ MD. The jointed pipe will also be pipe light and would be shut in below the flow cross. Thus, circulation would not be possible if shut in. There is not adequate room to add extra BOP rams for this well (see attached tree height diagram): b. Current Well Tree height is 167.5”. c. CDR2 max tree height, with six ram BOP, to fit over the well is 163”. d. CDR3 max tree height, with six ram BOP, to fit over the well is 172”. e. A six ram BOP stack (to accommodate two extra rams for CTD jointed pipe operations – 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams), is based off two triples. Mitigations: f. The well will be full of KWF prior to running liner or jointed pipe operations. g. The BHA will be circulated out of hole prior to laying down BHA for jointed pipe operations. h. The well will be flow checked after laying in KWF, before laying down BHA and before making jointed pipe. i. In addition, a X-over shall be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole. j. Primary shut-in standing orders will be to use a safety joint while running 2-3/8” or 3-1/2”x3-1/4”x2- 7/8” solid or slotted liner, 1” or 1-1/4” CS Hydril jointed pipe, and perf guns.The desire is to keep the same standing orders for all jointed pipe operations and not change shut in techniques in the middle of jointed pipe operations or from well to well (run safety joint with pre-installed TIW valve). When closing on a safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: Directional plan attached. Maximum planned hole angle is 108°. Inclination at kick off point is 42°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line – 20,300 ft Distance to nearest well within pool – 750 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: 200' 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 in the parent is 8,464’ MD. * Waiver request to 20 AAC 25.036 is denied. * Refer to 20 AAC 25.540. Hearing for a waiver request. - mgr DENIED Anti-Collision Failures: J-01A (close approach at 9,136’ MD) – P&A’d with J-01B sidetrack at 8,618’ MD J-01PB1(close approach at 8,751’ MD) – P&A’d with J-01B sidetrack at 8,618’ MD Hazards: J-Pad is not an H2S pad. The last H2S reading on J-25A: 10 ppm on 3/5/2022. Max H2S recorded on J-Pad: 36 ppm on J-07 (8/17/2020). 2 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 Prudoe 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 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 3-1/8" 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 CDR2 or CDR3 BOP and Well Tree Height Hydril 7 1/16" Annular Blind/Shear 2" or 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2" or 2-3/8" Pipe/Slips 2-3/8" or 3.0" or 3-1/8" Pipe / Slip Blind/Shear 2" or 2-3/8" Pipe/Slips 2" or 2-3/8" Pipe/Slips 1" or 1-1/4" Pipe/Slips 2-3/8" x3-1/2" VBRs 2-3/8" or 3.0" or 3-1/8" Pipe / Slip CDR2 Maximum Tree Height with 6 ram BOP: 163" Current Well Tree Height: 167.5" CDR3 Maximum Tree Height with 6 ram BOP: 172" Rig Floor Cellar Top/Ground Level Top of Tree (top swab flange) Well: J-25B 6 ram BOP height based off two triples. 9,150'9,150' 8,310'8,310' 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. PBU J-25B 224-134 PRUDHOE OIL PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT J-25BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241340PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes ADL0282812 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 boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 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)Yes This well is an in zone CTD sidetrack from an existing wellbore with pressure integrity.18 Conductor string providedYes All drilling on this sidetrack will below existing surface casing shoe.19 Surface casing protects all known USDWsYes This well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.20 CMT vol adequate to circulate on conductor & surf csgYes This well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented production liner. Parent well isolates the reservoir.22 CMT will cover all known productive horizonsYes This well is a in zone CTD sidetrack from an existing well. Full integrity above sidetrack.23 Casing designs adequate for C, T, B & permafrostYes CDR rig(s) has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Sundry 324-61825 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows manageable collision risk.26 Adequate wellbore separation proposedYes All drilling below the surface casing shoe. No diverter required.27 If diverter required, does it meet regulationsYes MPD but reservoir pressure below water gradient.28 Drilling fluid program schematic & equip list adequateYes CT Packoff, flow cross, annular, blind shear, CT pipe slips, flow cross, BHA pipe slips, CT29 BOPEs, do they meet regulationYes 7-1/16" 5000 psi stack pressure tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Flanged choke and kill lines between dual combi's w remote choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo PBU J-pad is an not an H2S pad >100 ppm. Monitoring will still be required.33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No Measures required. H2S recorded on J-Pad: 36 ppm on J-07 (8/17/2020).35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is 7.1 ppg EMW. MPD to be employed.36 Data presented on potential overpressure zonesNA Two fault crossings expected.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/30/2024ApprMGRDate12/24/2024ApprADDDate10/30/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate