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Home My WebLink About225-041Nolan 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: 08/26/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250826 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF T40803 BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist T40804 BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf T40804 BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf T40804 BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805 BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf T40805 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch T40806 KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf T40807 MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey T40808 NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf T40809 ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey T40810 PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG T40811 PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG T40812 PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT T40813 PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG T40814 PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG T40815 PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG T40816 PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf T40817 SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf T40818 WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer T40819 Please include current contact information if different from above. T40814PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.27 08:12:23 -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: 08/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250813 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 24-06RD 50133204990100 206013 4/2/2025 YELLOWJACKET GPT-PERF MPB-24 50029226420000 196009 7/9/2025 READ CaliperSurvey MPB-34 50029235690000 216139 7/7/2025 READ CaliperSurvey MPF-45 50029225560000 195058 7/30/2025 READ CaliperSurvey ODSK-41 50703205850000 208147 8/9/2025 READ CaliperSurvey ODSN-25 50703206560000 212030 6/22/2025 READ CaliperSurvey ODSN-31 50703205650000 208003 8/11/2025 READ CaliperSurvey PBU 06-11A 50029204280100 225042 7/13/2025 BAKER MRPM PBU 13-19 50029206900000 181180 6/4/2025 HALLIBURTON WFL-TMD3D PBU 14-18C 50029205510300 225040 6/24/2025 BAKER MRPM PBU 14-43A 50029222960100 225041 7/30/2025 BAKER MRPM PBU C-01B 50029201210200 212053 7/19/2025 BAKER MRPM SD-07 50133205940000 211050 7/27/2025 YELLOWJACKET SCBL SP 12-S3 50629235130000 214067 7/18/2025 YELLOWJACKET PERF Please include current contact information if different from above. T40771 T40772 T40773 T40774 T40775 T40776 T40777 T40778 T40779 T40780 T40781 T40782 T40783 T40784 PBU 14-43A 50029222960100 225041 7/30/2025 BAKER MRPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.15 10:11:56 -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: 08/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 14-43A PTD: 225-041 API: 50-029-22296-01-00 FINAL LWD FORMATION EVALUATION LOGS (07/10/2025 to 07/17/2025) 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. 225-041 T40786 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.18 09:53:10 -08'00' RUSH By Grace Christianson at 12:54 pm, Jul 22, 2025 Digitally signed by David Bjork (3888) DN: cn=David Bjork (3888) Date: 2025.07.22 11:53:03 - 08'00' David Bjork (3888) 325-431 *Wellbore schematic indicates 110' MD. SFD 10-407 included in original completion DSR-7/22/25 * SFD 7/22/2025 * MGR22JUL25JLC 7/23/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 11:01:54 -08'00'07/23/25 RBDMS JSB 072425 Page 1 of 5 Post CTD Well Operations Well: 14-43A PTD: 225-041 Well Name:14-43A API Number:50-029-22296-01 Current Status:Operable Producer PTD #225-041 Estimated Start Date:7/25/25 Rig:Coiled Tubing Reg.Approval Req’std?10-403, 10-407 Estimated Duration:5days Regulatory Contact:Joe Lastufka 907-227-8496 (M) First Call Engineer:Jerry Lau 907-360-6233 (M) Second Call Engineer:Brenden Swensen 907-748-8581 (M) Current Bottom Hole Pressure:3,200 psi @ 8,800’ TVD (Drillsite Average) Maximum Expected BHP:3,300 psi @ 8,800’ TVD (est.) 7.3ppg EMW Max. Anticipated Surface Pressure:2,420 psi Gas Column Gradient (0.1 psi/ft) History New CTD sidetrack. CDR2 was unable to pump primary liner cement job due to poor indication that the LNR had released. Service coil will now perform the entirety of the LNR cement job for this lateral. There is a known loss zone at around 9,582’ MD. Objective Perform 2 stage LNR cement job with service coil prior to post CTD logging and adperf scope. 1 st stage will be thru a retainer from the toe taking returns into the loss zone. 2nd stage will be a top job down the backside of LNR into the loss zone. Procedure Coiled Tubing: Primary Liner Cement Job 1. RIH w/ drift and flag pipe ~100’ above latch collar at 11770’ MD 2. Swap wellbore over to diesel down to TOL at 8839’ MD 3. RIH and set 2-7/8” one-trip retainer mid joint at ~11750’ MD 4. Mix and bullhead 37 bbl of 15.3 ppg Class G cement into loss zone at 9582’ MD. Pump schedule: a. 5 bbl Freshwater b. 37 bbl of 15.3 ppg class G c. 3 bbl of freshwater d. Displace with powervis and slick KCL e. Unsting, lay in last 1-2 bbls of CMT atop retainer 5. Contaminate and cleanout cement down to top of retainer, POOH. Secondary Liner Cement Downsqueeze 6. RIH w/ drift to 8975’ and flag pipe at 8950’ – No need for a log. a. If nozzle drift tags prior to 8975’, pick up motor and 2.73” mill, and mill down to 8975’. 7. Set NS CBP (2.500” OD) at ~ 8950’. POOH. 8. RIH with ~2” cementing nozzle BHA (WSS discretion). 9. Bullhead well down to TOL with diesel. 10. Park coil at 8800’ and establish injectivity rates with 1% KCL down the coil. Page 2 of 5 Post CTD Well Operations Well: 14-43A PTD: 225-041 11. Mix and pump ~20 bbl of 15.3 ppg Class G cement. Pump schedule: a. 5 bbl Freshwater b. ~20 bbl of 15.3 ppg class G c. 3 bbl of freshwater d. Displace with diesel. 12. Pump until either a 500 psi bump is achieved or only 5 bbls remain in coil. a. At 500 psi bump or when only 5 bbl remain in coil, lay in 1:1 and begin hesitation squeeze. Increase pressure in 250-500psi increments, each held for 10 minutes. b. Target 1500psi squeeze pressure held for 30 minutes. 13. Once squeeze is achieved, contaminate/clean out with powervis down to the CBP, reciprocating across all jewelry. 14. If squeeze pressure is not achieved and thickening time has run out, displace TOC down to deployment sleeve and POOH pumping pipe displacement. 15. Once cement has reached 1500psi compressive strength PT wellbore to 1350 psi. a. Relay results to OE and potentially pump a second squeeze. 16. Pick up 2.73” Mill and mill CBP. Push debris to the XO at 9423’ MD. 17. Make 2.300” milling assembly and mill/push CBP to CMT retainer PBTD at 11750’ MD. 18. Continue non 10-403 work to perform RPM, CBL, and adperfs. Attachments x Current Schematic prior to LNR Cement Job x Proposed Wellbore Schematic post LNR Cement Job x Sundry Change Form Page 3 of 5 Post CTD Well Operations Well: 14-43A PTD: 225-041 Page 4 of 5 Post CTD Well Operations Well: 14-43A PTD: 225-041 Page 5 of 5 Post CTD Well Operations Well: 14-43A PTD: 225-041 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date 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 14-43A Hilcorp Alaska, LLC Permit to Drill Number: 225-041 Surface Location: 19' FNL, 1280' FEL, Sec. 09, T10N, R14E, UM, AK Bottomhole Location: 2366' FNL, 1469' FWL, Sec. 04, T10N, R14E, 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 25th day of April 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.25 16:51:05 -08'00' 3-1/2"x3-1/4" Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.23 09:40:58 - 08'00' Sean McLaughlin (4311) Ryan Ciolkosz ryan.ciolkosz@hilcorp.com 907-244-4357 By Grace Christianson at 10:16 am, Apr 23, 2025 SFD 4/24/2025 225-041 *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 *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 JJL4/25/25 50-029-22296-01-00 DSR-4/25/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.25 16:51:21 -08'00' 04/25/25 04/25/25 RBDMS JSB 042825 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: April 23, 2025 Re:14-43A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 14-43 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 14-43A Producer: See 14-43 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock. 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 pre-rig, the rig will set the 4-1/2"x5-1/2" 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 3 and continue drilling Zone 4/3 to TD. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will completely isolate and abandon the parent Prudhoe Pool perfs. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: Reference 14-43 Sundry submitted in concert with this request for full details. 1. Slickline : Set DGLVs 2. E-Line : Set 4-1/2" x 5-1/2" Whipstock at 9,100’ MD at 0 deg ROHS 3. Coil : Mill Window 4. Valve Shop : Pre-CTD Tree Work 5. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in June 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2387 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window (if not done pre-rig). 3. Drill build section: 4.25" OH, ~152' (35 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2440' (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: 35 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 : Liner lap test. Set LTP if necessary. Set live GLVs 3. Service Coil : Post rig RPM, CBL, and perforate 30' 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 (9100' MD -8,685' TVD) Pumps On Pumps O A Target BHP at Window (ppg)4,426 psi 4,426 psi 9.8 B -546 psi 0 psi 0.06 C 3,884 psi 3,884 psi 8.6 B+C Mud + ECD Combined 4,430 psi 3,884 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -4 psi 542 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 3,267 psi at 8,800 TVD. (7.1 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2387 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: 8,882' MD – 9,090' MD (208' liner) 3-1/4", 6.6#, 13Cr Solid: 9,090' MD – 9,400' MD (310' liner) 2-7/8", 6.5#, 13Cr Solid: 9,400' MD – 11,692' MD (2,292' 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. 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. A X-over shall 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 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. Request variance to 20 AC 25.036(c)(2)(A)(iv) to deploy tubulars < 2.375” OD without properly sized pipe rams. 2-3/8” safety joint will be utilized while running 1” / 1-1/4” CS hydril. 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). The well will be full of KWF prior to running liner or jointed pipe operations. The BHA will be circulated out of hole prior to laying down BHA for jointed pipe operations. The well will be flow checked after laying in KWF, before laying down BHA and before making jointed pipe. Directional: Directional plan attached. Maximum planned hole angle is 102°. Inclination at kick off point is 26°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line – ~ 17,000 ft Distance to nearest well within pool – 224’. X-04A Crosses directly over the top of the 14-43A wellpath in the Sag river. 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: ~15-30'' 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: 9037’ MD in the parent Anti-Collision Failures: All wells pass anti-collision risk rules with the 14-43A WP01 wellpath. Hazards: DS/Pad is an H2S pad. The last H2S reading on 14-43: 58 ppm on 04/13/2023. Max H2S recorded on DS/Pad: 146 ppm.. 1 fault crossings expected. High lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) Top of Prudhoe Pool: 9037’ MD DS/Pad is an H2S pad. Pre-Rig – Service Coil – Window Milling The approved sundry and permit to drill will be posted in the Operations Cabin of the unit during the entire window milling operation. Notes for window milling: Window milling with service CTU operations will fully comply with 20 AAC 25.286(d)(3), including the use of pressure control equipment, all BHAs fully lubricated and at no point will any BHA be open-hole deployed. Window Milling Procedure: 1. Kill well with 1% KCL if necessary. Well may already be killed from previous operations. 2. MU and RIH with window milling assembly – Window mill followed by string reamer. NOTE: Confirm milling BHA configuration prior to job execution due to variations in different service provider’s window milling BHAs. 3. RIH & TAG whipstock pinch point, calculate distance till string reamer is out of the window, paint coil flag and note in WSR. 4. Mill window per vendor procedure. – Make note of any WHP changes while milling window in the WSR. 5. Make multiple reciprocating passes through the kickoff point to dress liner exit and eliminate all burs. Perform gel sweeps as necessary to keep window clean. Maximum approved distance to reciprocate beyond the window is 15 ft to ensure confidence the window is prepared for the sidetrack.DO NOT RECIPROCATE DEEPER than 15 ft. 6. Confirm exited liner & string reamer dressed entire window with coil flag and note bottom of window and total milled depth in WSR. 7. FP well to 2,500’ TVD with 60/40 MeOH while POOH. 8. Once on surface inspect BHA, measure OD of mill and string reamer & document in WSR. 9. RDMO 10. Communicate to Operations to tag wing valve “Do Not POP”. Pre-Rig – Service Coil – Window Milling – BOP Diagram 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 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 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 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 PBU 14-43A 225-041 Prudhoe WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 14-43AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250410Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesEntire Well lies within ADL0028312.2Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J.4Well 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) (For sNA15All 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 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) approved with WC 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 shutdownYeslast H2S reading on 14-43: 58 ppm on 04/13/2023.33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)NoH2S Mesures Required. This is an H2S pad.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure is 0.369 tpsi/ft (7.1 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNAPotential for lost circulation. One fault crossing expected.38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate4/24/2025ApprJJLDate4/25/2025ApprSFDDate4/24/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 4/25/2025