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224-083
7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-100A Replace LTP w Ext LTP Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-083 50-029-22962-01-00 ADL 0028257, 0028258 15010 Conductor Surface Liner Liner 6794 4856 10226 1921 4947 14996 10-3/4" 7" 4-1/2" 3-1/2" x 3-1/4" x 2-7/8" 6794 27 - 4883 24 - 10250 10077 - 11998 10063 - 15010 2430 27 - 3377 24 - 6784 6681 - 6811 6672 - 6794 None 2480 5410 7500 10530 None 5210 7240 8430 10160 14075 - 14990 4-1/2" 12.6# 13cr80, L80 22 - 100916793 - 6793 Structural 79 20" 27 - 106 27 - 106 1490 470 4-1/2" HES TNT Packer 4-1/2" Baker S3 Packer 9889, 6567 10046, 6662 Date: Torin Roschinger Operations Manager Hunter Gates hunter.gates@hilcorp.com (907) 777-8326 PRUDHOE BAY 10/1/2025 Current Pools: AURORA OIL Proposed Pools: AURORA OIL Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:07 am, Sep 17, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.09.17 09:48:02 - 08'00' Torin Roschinger (4662) 325-567 SFD 9/22/2025JJL 9/22/25 DSR-9/24/25 10-404 Extended liner top assembly not to exceed 500'. Reestablish pressure containment after ext LTP assembly is RIH. Perform and document well control drill on each shift using attached standing orders. Ensure well is dead before breaking containment. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.24 15:28:19 -08'00'09/24/25 RBDMS JSB 092625 Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Well Name: S-100A Permit to Drill: 224-083 Current Status: Operable, Shut-In API Number: 50-029-22962-01 Estimated Start Date: 10/1/2025 Estimated Duration: 3 days Regulatory Contact: Abbie Barker Service Lines: CT/SL First Call Engineer: Hunter Gates (215) 498-7274 (M) (907) 777-8326 (O) Second Call Engineer: Tyson Shriver (406) 690-6385 (M) Current Bottom Hole Pressure: 2,700 psi KWF: 7.8 ppg Use 1% KCL Max Dev: 62 @ 2,926’ MD Min ID: 3.813” @ 2,105’ & Deployment Sleeve is 3” SIWHP ~200 psi Brief Well Summary: S-100A is a CTD ST well that was drilled in January 2025. There have been issues attempting to isolate the old, perforated interval behind our CTD liner with high water and sand production. The well is currently shut-in awaiting a liner top packer reset. The last liner top packer failed an MIT-T when set. After setting test plugs at 10,035’ MD (failed) and 9,926’ MD (pass), it was concluded that the S-3 packer is compromised and leaking through the overshot at 10,011’ MD causing our MIT’s to fail. Current Status: Shut-In – Operable Producer Pressure/Integrity History 8/31/2025 – MIT-T w/ plug at 9,926’ passed to 2000 psi and MIT-T w/ plug set at 10,035’. Procedure Coiled Tubing 1. Drift with PTSA LTP Drift assembly for 3” deployment sleeve to 10,063’ MD and tag deployment sleeve. 2. Record depths & POOH and stop ~100’-200’ above deployment sleeve and paint flag. Coiled Tubing – OH Deployment Notes: x Remote gas monitoring for H2S and LELs are required for Open Hole Deployment Operations x Due to the necessary open hole deployment of Extended Liner Top Packer job, 24-hour crew and WSS coverage is required. The well will be killed and monitored before making up the liner top packer. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. 1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH w/ running tools, ensure adequate lubricator length to cover running tools. 2. Bullhead 1.2x wellbore volume ~234 bbls 1% KCL/SW down tubing. Max tubing pressure 2500 psi. (This step can be performed any time prior to open-hole deployment of the extended liner top packer. Timing of the well kill is at the discretion of the WSS.) a. Wellbore volume to top perf including backside of liner to whipstock on S-100 = 195 bbls b. 4-1/2” tubing/liner – 11,998’ X 0.0152 bpf = 182 bbls c. 3-1/2” liner – 11,998’ – 12,222’ X .0079 bpf= 2 bbls Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 d. 3-3/16” liner – 12,222’ – 14,075’ (Top perf) X .0058 bpf = 11 bbls 3. At surface, prepare for deployment of the liner top packer. 4. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/KWF, 8.4 ppg 1% KCl or 8.5 ppg as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established. Fluids man- watch must be performed while deploying liner top packer to ensure the well remains killed and there is no excess flow. 5.*Perform drill by picking up safety joint with TIW valve and space out before MU liner top packer. Review standing orders with crew prior to breaking lubricator connection and commencing makeup of the liner top packer. 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. a.At the beginning of each job, the crossover/safety joint must be physically MU to the liner top packer one time to confirm the threads are compatible. 6.Break lubricator connection at QTS and begin makeup of liner top packer per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying liner top packer to ensure the well remains killed and there is no excess flow. Patch Assembly Patch Interval (tie-in depths)Patch Length Weight of assembly (lbs) Run #1 9,950’ – 10,063’113’~542 lbs (4.8 ppf) 7.RIH w/ extended liner top packer assembly with RSG plug in the PTSA utilizing hydraulic setting tool. 8. Stab into liner top and set LTP. 9. POOH with running tool. 10. Pressure Tubing to 1500 psi to confirm LTP is holding, communicate results to OE for plan forward. 11.If PT fails, depending on LLR it may be decided to attempt to pull & reset LTP or troubleshoot RSG with SL. Contingent pull & reset LTP with service coil if LLR suggests significant mis-set. If PT passes, RDMO CTU * End of sundried work. * Slickline 1. MIRU SL. 2. RIH and pull RSG from PTSA. 3. RDMO SL and turn well over to ops. Operations 1. POP well with target GL rate of 2.5 MMCFD. Attachments: x Procedure x Current Wellbore Schematic x Proposed Wellbore Schematic x Caliper x BOP Schematic/Standing Orders/Equipment Layout x Sundry Change Form Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Current Wellbore Schematic: Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Proposed Wellbore Schematic: Extended LTP Assembly ~9,950’-10,063’ MD Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Caliper: Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 BOP Schematic Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 Set Extended LTP Well: S-100A PTD: 224-083 API: 50-029-22962-01 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 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU S-100A Replace LTP Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-083 50-029-22962-01-00 15010 Conductor Surface Liner Liner 6794 4856 10226 1921 4947 14996 10-3/4" 7" 4-1/2" 3-1/2" x 3-1/4" x 2-7/8" 6794 27 - 4883 24 - 10250 10077 - 11998 10063 - 15010 27 - 3377 24 - 6784 6681 - 6811 6672 - 6794 None 2480 5410 7500 10530 None 5210 7240 8430 10160 14075 - 14990 4-1/2" 12.6# 13cr80, L80 22 - 10091 6793 - 6793 Structural 79 20" 27 - 106 27 - 106 1490 470 4-1/2" HES TNT Packer 10046, 6662 9889, 10046 6567, 6662 Torin Roschinger Operations Manager Hunter Gates hunter.gates@hilcorp.com 907-777-8326 PRUDHOE BAY, AURORA OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028257, 0028258 22 - 6689 N/A N/A 83 361 3215 1132 800 231 200 N/A 13b. Pools active after work:AURORA OIL 4-1/2" Baker S3 Packer 9889, 6567 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations No SSSV Installed By Grace Christianson at 8:33 am, Sep 16, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.09.15 16:54:32 - 08'00' Torin Roschinger (4662) J.Lau 11/6/25 RBDMS JSB 091925 ACTIVITY DATE SUMMARY 6/7/2025 ***WELL FLOWING ON ARRIVAL*** RAN 2.25" CENT, 2-7/8" BRUSH & BULLNOSE TO 2.31" X-NIPPLE AT 10,064' MD SET 2-7/8" XX-PLUG AT 10,064' MD FLOW WELL TO TEST PLUG LTP NOT HOLDING ATTEMPTED TO EQUALIZE XX-PLUG AT 10,064' MD (sat down high) RAN 10' x 2" PUMP BAILER (flapper stuck open - no recovery) 3 x RAN 10' x 2" PUMP BAILER BALL BOTTOM (recovered ~1 gal sand) ***CONTINUE ON 6/8/25 WSR*** 6/8/2025 T/I/O 1880/1850/50 (TFS unit 1 assist S-Line) Pumped XX bbls of Crude to assist S- Line getting unstuck. ***********WSR Continued on 6-9-2025********** 6/8/2025 ***CONTINUED FROM 6/7/25 WSR*** RAN 10' x 2" PUMP BAILER TO 10,064' MD (~2 tbsp sand) ATTEMPTED TO EQUALIZE XX-PLUG AT 10,064' MD (no pressure change or marks on prong) 5 x RAN 10' x 2.25" PUMP BAILER W/ SNORKEL BOTTOM TO 10,064' MD (recovered small amount of sand & a few pebbles) MADE MULTIPLE ATTEMPTS TO EQUALIZE 2.31" XX-PLUG AT 10,064' MD RAN 2-7/8" GR TO 2.31" XX-PLUG AT 10,064' MD & GET STUCK ***CONTINUE ON 6/9/25 WSR*** 6/9/2025 ***CONTINUED FROM 6/8/25 WSR*** DROPPED CUTTER BAR & RECOVERED ALL WIRE PULLED CUTTER BAR AT 9,997' SLM JARRED ON TOOLSTRING AT 10,003' SLM FOR 4 HRS ***CONTINUE ON 6/10/25 WSR*** 6/9/2025 ******WSR Continued from 6-8-2025******** (TFS unit 1 Assit S-Line stuck in hole) Pumped 79 bbls of Crude down the TBG to assist S-Line in becoming unstuck. S- Line was unable to pull out of hole. Final WHPS 300/1750/50 6/10/2025 T/I/O = 459/1817/62. Assist Slickline (PRESSURE TEST(RES SURV)) Pumped 82 bbls Crude into TBG to assist SL down hole. SL in control of well upon departure. Pad op notified upon completion. FWHPs = 300/1800/63 6/10/2025 ***CONTINUED FROM 6/9/25 WSR*** JARRED ON STUCK TOOLSTRING FOR 1 HOUR, NO MOVEMENT(5 hrs total) RAN 4 1/2" X SELECTIVE TEST TOOL(Tagged toolstring @ 10,004' slm, unable to locate nipple @ 10,035' md) **TOOLSTRING LIH 1.5" RLR(1.80" Whls)=RS,QC,5',5',QC,KJ,5',QC,OJ,QC,KJ,LSS,QC,2 1/2" GR(32'-9" oal, 34'-8" w/ xx plug)** ***WELL S/I ON DEPARTURE*** 6/12/2025 ***WELL S/I ON ARRIVAL*** JARRED ON FISH @ 10,003' SLM: 2500 - 3000# OJ LICKS 1 HOUR W/ NO MOVEMENT. ***CONTINUED ON 6-13-25*** Daily Report of Well Operations PBU S-100A Daily Report of Well Operations PBU S-100A 6/13/2025 ***CONTINUED FROM 6-12-25*** R/D FOR UNIT REPAIRS, WILL RETURN ***WELL S/I ON DEPARTURE*** 6/14/2025 ***WELL S/I ON ARRIVAL*** R/U .160 ***CONTINUED ON 6-15-25*** 6/15/2025 ***CONTINUED FROM 6-14-25*** LATCHED FISH @ 10,001' SLM. UNABLE TO GET 2.125" OJ's TO FUNCTION PROPERLY. JOB SUSPENDED DUE TO BRIDGES GOING OUT. ***WELL S/I ON DEPARTURE*** 7/3/2025 ***WELL S/I ON ARRIVAL*** R/U .160 ***CONTINUED ON 7-4-25*** 7/4/2025 ***CONTINUED FROM 7-3-25*** JARRED ON FISH @ 10,003' SLM 7 1/2 HOURS W/ NO MOVEMENT. ***CONTINUED ON 7-5-25*** 7/5/2025 ***CONTINUED FROM 7-4-25*** LATCHED FISH @ 9994' SLM (9' HIGHER THAN ALL PREVIOUS RUNS). HIT 3000# OJ LICKS 1 HR 30 MINS W/ NO ADDITIONAL MOVEMENT OBSERVED. ***WELL S/I ON DEPARTURE*** 7/15/2025 ***WELL S/I ON ARRIVAL*** R/U .160 ***CONTINUED ON 7-16-25*** 7/16/2025 ***CONTINUED FROM 7-15-25*** JARRED ON FISH @ 10,003' SLM FOR 3 HRS @ 3,000-3,200# JARRED DOWN ON FISH FOR 45 MINS DISPLACE FLUID W/ IA GAS TO 5,300' TBG PRESSURE 1,450# JARRED ON FISH FOR 1 HR @ 3,100-3,200# W/ NO MOVEMENT ***WELL S/I ON DEPARTURE*** 8/19/2025 ***WELL S/I ON ARRIVAL*** SET OVERSHOT @ 10,009' SLM JAR ON OVERSHOT @ 10,005 SLM FOR 30 MIN TO MAKE SURE ITS SET ***WELL LEFT S/I ON DEPARTURE*** 8/23/2025 LRS CTU #2 - 1.75" Long String Job Objective: Fish Slickline BHA, Pull LTP MIRU CTU, M/U YJ Fishing BHA with 4" GS, Latch fish @10036' CTM, Attempt to pull fish. ....Job in Progress.... Daily Report of Well Operations PBU S-100A 8/24/2025 LRS CTU #2 - 1.75" Long String Job Objective: Fish Slickline BHA, Pull LTP Cont Jarring up and down @10033' CTM on W/L tool string. Unable to retrieve after 50 jar licks up and down. POOH for pipe management, Trim Coil. Make up fishing BHA #2 and Remove FRT vibratory tool and add additional weight bar. RIH and latch fish at 10033' CTMD and begin jarring up only and stepping up weight. Pull free after jar lick #8. Attempt to RI and set down high at 9981' CTMD, Pump off fish and POOH to shorten BHA. MAke up retrieval BHA with just disco and 4" hydraulic GS. RIH and set down to latch fish at 9981'. POOH and recover 24.9' of fish as the slickline BHA parted at the lower knuckle joint. The slickline toolstring is 2.9' inside the LTP. Make up fishing BHA #3 with 11.3' of weight bar and 4" hydraulic GS to recover LTP. RIH and set down latch LTP @10055' CTM, P/U Jar on LTP packer. POOH and inspect BHA. OOH W/L tool string and LTP was Recovered. Lay down BHA. ***Job In Progress*** Cont 8/25/25 WNS 8/25/2025 LRS CTU #2 - 1.75" Long String Job Objective: Fish Slickline BHA, Pull LTP Cont R/D, FP well 40bbls of Deisel ***Job Complete******** 8/27/2025 ***WELL S/I ON ARRIVAL*** BEGIN HOT DIESEL B&F W/ LRS ***CONTINUE 8/28/25*** 8/27/2025 Assist Slickline (PRESSURE TEST (RES SURV)) Pumped 55 bbls 180* DSL down Tbg while SL brushed. ***Job Cont to 8-28-2025 WSR*** 8/28/2025 ***CONTINUE FROM 8/27/25*** BRUSHED 4-1/2" TUBING & DEPLOYMENT SLEEVE @ 10,063' MD WHILE LRS PUMPED 131 BBLS OF HOT DIESEL RAN 45 KB PACKER & PTSA DRIFT TO DEPLOYMENT SLEEVE @ 10,063' MD. GOOD MARKS ON NO-GO RAN 10' x 2-1/4" BAILER TO 10,150' SLM RAN READ 24 ARM CALIPER. 2 PASSES FROM 10,150' SLM TO 9,700' SLM. GOOD DATA RERAN 45 KB PACKER & PTSA DRIFT TO 10,063' MD. GOOD MARKS ON NO- GO. ATTEMPTED TO RUN 45 FLOWGARD LTP; S/D @ 1717' SLM, AND UNABLE TO WORK DEEPER. ***CONTINUED ON 8-29-25*** 8/28/2025 ***Job Cont from 8-27-2025 WSR** Assist Slickline (PRESSURE TEST (RES SURV)) Pumped 75 bbls (131 bbls total) 180* DSL down Tbg while SL brushed. Pumped 3 bbls DSL in attempt to pump SL down. ***Job Cont to 8-29-2025 WSR*** Daily Report of Well Operations PBU S-100A 8/29/2025 ***CONTINUED FROM 8-28-25*** BRUSHED & HOT FLUSHED TBG 3.79" TO 10,063' MD. DRIFTED CLEANLY W/ 45 KB PACKER DRIFT, 10' x 2 7/8" SPACER, AND PTSA TO 10,063' MD. ATTEMPTED TO SET 45 FLOGARD LINER TOP PACKER. ISSUES @ 1,680'- 1,730' SLM. POOH. SET 45 FLOGARD LTP W/ 10' x 2 7/8" SPACER, AND NSAK PTSA W/ 2.31" RSG PLUG IN DEP SLEEVE @ 10,063' MD. ATTEMPT TO PT TBG 2000 PSI; UNABLE TO CATCH PRESSURE. PULLED 2.31" RSG PLUG FROM LTP. ***CONTINUED ON 8-30-25*** 8/29/2025 ***Job Cont from 8-28-2025 WSR*** Assist Slickline (PRESSURE TEST (RES SURV)) Pumped 150 bbls 180* DSL down Tbg while SL brushed. Pumped 52 bbls DSL down Tbg while pumping SL downhole. ***Job Cont to 8-30-2025 WSR*** 8/30/2025 ***CONTINUED FROM 8-29-25*** JARRED ON LTP FOR 2 HOURS AND 15 MINUTES PULLED LTP @ 10.063MD. MISSING 1/2 ELEMENT RAN 4 1/2" BRUSH AND 3.68" WIRE GRAB TO 10,038' SLM. NO RECOVERY. RAN 3 1/2" BRUSH, 2.68" CENT, AND 1.875" WIRE GRAB TO DEVIATION @ 10,373' SLM. NO RECOVERY. SET 3.81" PX PLUG BODY @ 10,035' MD. ATTEMPTED TO SET PRONG IN PX PLUG BODY; ISSUES GETTING JD TO SHEAR. ***CONTINUED ON 8-31-25*** 8/30/2025 ***Job Cont from 8-29-2025 WSR** Assist Slickline (PRESSURE TEST (RES SURV)) Vac and PT lubricator while SL pulls and resets LTP. Pumped 11.3 bbls 50* DSL down Tbg to attempt to pressure up on plug. Tbg psi fell by half in less than an minute. ***Job Cont to 8-31-2025 WSR*** 8/31/2025 ***Job Cont from 8-30-2025 WSR*** Assist Slickine (PRESSURE TEST (RES SURV)) Pumped 3.5 bbls DSL down Tbg in attempt to pressure up on plug. Tbg fell off 500 psi in under a minute. Pumped 14 bbls on LLR. Got a LLR of 1 bpm at ~1060 psi. S/L set plug higher. Pressure test TBG to 2000 psi PASSED at 2092 psi (2214 psi max applied) TBG lost 91 psi during the first 15 minutes and 31 psi during the second 15 minutes. TBG lost 122 psi during the 30 minute test. Pumped 1.7 bbls of 59*F diesel to achieve test pressure. SL in control of well per LRS departure, IA,OA=OTG 8/31/2025 ***CONTINUED FROM 8-30-25*** PULLED PRONG FROM 10,008' SLM. HEAVY SCARRING ON PRONG. RE-SET PRONG IN PX PLUG BODY @ 10,015' SLM. ATTEMPT TO PT TBG; FAIL. ESTABLISH LLR OF 1 BBL/MIN @ 1060 PSI. PULLED PX PLUG BODY & PRONG @ 10,035' MD. SET PX PLUG BODY & PRONG @ 9,926' MD. LRS PERFORMS 2000 PSI PT ON TBG: PASS. PULLED PX PLUG FROM 9926' MD. ***CONTINUED ON 9-1-25*** 9/1/2025 ***CONTINUED FROM 8-31-25*** R/D SLICKLINE. ***WELL S/I ON DEPARTURE*** 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: 6/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250618 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN 07RD2 50733200120200 195113 6/1/2025 AK E-LINE LDL AN 24RD 50733202850100 207170 6/1/2025 AK E-LINE LDL BRU 221-24 50283202020000 225027 5/29/2025 AK E-LINE CBL KALOTSA 10 50133207320000 224147 5/21/2025 AK E-LINE Perf KALOTSA 2 50133206590000 216155 5/25/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/27/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/26/2025 AK E-LINE Perf PBU 06-12C 50029204560300 225022 5/17/2025 HALLIBURTON RBT-COILFLAG PBU 15-32C 50029224620300 217104 5/27/2025 HALLIBURTON RBT PBU D-01B 50029200540200 224155 5/18/2025 BAKER MRPM PBU D-01B 50029200540200 224155 5/18/2025 HALLIBURTON RBT-COILFLAG PBU H-18A 50029208800100 224011 5/14/2025 BAKER MRPM PBU H-18A 50029208800100 224011 5/14/2025 HALLIBURTON RBT-COILFLAG PBU L-109 50029230460000 201201 5/24/2025 HALLIBURTON IPROF PBU L-115 50029230350000 201140 5/19/2025 HALLIBURTON IPROF PBU L-117 50029230390000 201167 5/30/2025 HALLIBURTON IPROF PBU N-07B 50029201370200 223122 6/7/2025 HALLIBURTON RBT PBU S-100A 50029229620100 224083 5/26/2025 HALLIBURTON PPROF-LDL PBU Z-34 50029234690000 212061 5/17/2025 HALLIBURTON IPROF-LDL Please include current contact information if different from above. T40566 T40567 T40568 T40569 T40570 T40571 T40571 T40572 T40573 T40574 T40574 T40575 T40575 T40576 T40577 T40578 T40579 T40580 T40581 PBU S-100A 50029229620100 224083 5/26/2025 HALLIBURTON PPROF-LDL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.18 12:03:53 -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: 6/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250613 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-17A 50733203110100 213049 4/14/2025 AK E-LINE GPT T40549 AN-17A 50733203110100 213049 4/16/2025 AK E-LINE Perf T40549 BRU 244-27 50283201850000 222038 5/15/2025 AK E-LINE Perf T40550 IRU 241-01 50283201840000 221076 5/16/2025 AK E-LINE Perf T40551 KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP T40552 KU 13-06A 50133207160000 223112 5/9/2025 AK E-LINE Perf T40552 KU 33-08 50133207180000 224008 5/30/2025 AK E-LINE Perf T40553 MPU K-33 50029227290000 196202 5/2/2025 AK E-LINE Caliper T40554 Aurora S-100A 50029229620100 224083 5/8/2025 BAKER MRPM Borax #2 T40555 PBU 06-12C 50029204560300 225022 5/15/2025 BAKER MRPM T40556 PBU B-30B 50029215420200 225009 4/9/2025 BAKER MRPM T40557 PBU D-03B 50029200570300 225008 5/2/2025 BAKER MRPM T40558 PBU H-29B 50029218130200 225005 5/7/2025 BAKER MRPM T40559 END 1-25A 50029217220100 197075 5/4/2025 HALLIBURTON MFC40 T40560 END 3-03 50029223060000 192121 5/18/2025 HALLIBURTON PPROF T40561 NS-33A 50029233250100 208189 5/13/2025 HALLIBURTON MFC24 T40562 PBU D-03B 50029200570300 225008 5/2/2025 HALLIBURTON RBT T40558 PBU H-29B 50029218130200 225005 5/7/2025 HALLIBURTON RBT T40559 PBU L-108 50029230900000 202109 5/16/2025 HALLIBURTON IPROF T40563 Please include current contact information if different from above. Aurora S-100A 50029229620100 224083 5/8/2025 BAKER MRPM Borax #2 T40555 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.17 11:38:14 -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: 5/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250515 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf T40412 END 2-72 50029237810000 224016 4/4/2025 READ CoilFlag T40413 IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf T40414 IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf T40414 KU 33-08 50133207180000 224008 4/22/2025 AK E-LINE PPROF T40415 MRU D-16RD 50733201830100 180110 4/21/2025 AK E-LINE Cement/Perf T40416 NSU NS-06 50029230880000 202101 4/21/2025 AK E-LINE PPROF T40417 NSU NS-19 50029231220000 202207 4/27/2025 AK E-LINE Perf T40418 NSU NS-20 50029231180000 202188 4/24/2025 AK E-LINE Perf T40419 NSU NS-23 50029231460000 203050 4/23/2024 AK E-LINE Packer T40420 PBU 02-10B 50029201630200 200064 3/21/2025 BAKER SPN T40421 PBU 06-19B 50029207910200 224095 3/1/2025 BAKER MRPM Borax T40422 PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax T40423 PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile T40424 SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf T40425 Revision Explanation: Processing report added Please include current contact information if different from above. T40423PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.16 08:15:21 -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: 02/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: - REVISON WELL: PBU S-100APB1 PTD: 224-083 API: 50-029-22962-70-00 FINAL LWD FORMATION EVALUATION LOGS (12/15/2024 to 01/04/2025) x Multiple Propagation and Azimuthal Resistivity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Surveys SFTP Transfer – Main Folder: PBU S-100APB1 Subfolders: Please include current contact information if different from above. 224-083 T40070 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.10 15:06:01 -09'00' 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: 02/05/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: PBU S-100A +PB1 PTD: 224-083 API: 50-029-22962-10-00 (S-100A) 50-029-22962-70-00 (S-100APB1) FINAL LWD FORMATION EVALUATION LOGS (12/15/2024 to 01/04/2025) x Multiple Propagation and Azimuthal Resistivity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Surveys SFTP Transfer – Main Folders: PBU S-100A +PB1 Subfolders: Please include current contact information if different from above. T40048 T40049 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.05 14:55:04 -09'00' 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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU S-100A Hilcorp Alaska, LLC Permit to Drill Number: 224-083 Surface Location: 4437' FSL, 4499' FEL, Sec. 35, T12N, R12E, UM, AK Bottomhole Location: 1165' FSL, 2410' FEL, Sec. 28, T12N, R12E, UM, AK Dear Mr. Myers: 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 17th day of September 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.17 09:28:08 -08'00' 3-1/2"x3-1/4" Drilling Manager 06/10/24 Monty M Myers By Grace Christianson at 3:49 pm, Jun 10, 2024 * BOPE test to 3500 psi. * Variance to 20 AAC 25.112 (i) Approved for alternate plug placement on parent well with fully cemented liner. * Approved for post rig perforating with service coil. Length of perforating BHA not to exceed 500' per run. * Rams sized to casing diameter for running casing lengths greater than 500' 98 MGR24JUNE2024 DSR-6/13/24 50-029-22962-01-00224-083 A.Dewhurst 12SEP24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.17 09:28:22 -08'00'09/17/24 09/17/24 RBDMS JSB 091724 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: June 10, 2024 Re:PBU S-100A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well PBU S-100 with the Nabors CDR2 Coiled Tubing Drilling. Proposed plan for PBU S-100A Producer: See S-100 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift/caliper for whipstock and MIT. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. The rig will set the 4-1/2" whipstock and mill a single string 3.80" window + 10' of formation out of the 4-1/2" liner. The well will kick off drilling in the Kuparuk and continue in the Kuparuk 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 Kuparuk 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 PBU S-100 Sundry submitted in concert with this request for full details. 1. Coil : Drift for whipstock and caliper 2. FullBore : MITxIA 3. Valve Shop : Pre-CTD Tree Work 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in October 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,083 psi). 2. Set 4-1/2" Whipstock – Set at 12,000’ MD at 270 deg ROHS 3. Mill 3.80” Window. 4. Drill production lateral: 4.25" OH, ~2,892' (10 deg DLS planned). 5. Run 3-1/2” x 3-1/4” x 2-7/8” L-80 liner 6. Pump primary cement job: 44 bbls, 15.3 ppg Class G, TOC at TOL*. 7. 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 : Set LTP* (if necessary). 3. Service Coil : Post rig perforate (~1500’) and CBL. 4. Slickline : SBHPS & Set live GLVs. 5. Testing : Portable test separator flowback. 24 hour notice to AOGCC. PTD 224-083Install casing rams. - mgr Sundry 324-338 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” (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 (12,000' MD -6,811' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,179 psi 4,179 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 720 psi 0 psi 0.09 C DƵĚ,LJĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,046 psi 3,046 psi 8.6 B+C Mud + ECD Combined 3,766 psi 3,046 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 413 psi 1,133 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 2,753 psi at 6,700’ TVDSS. (7.9 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,083 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 3-1/2", 9.3#, L80/Solid: 10,060' MD – 11,990' MD (1,930' liner) x 3-1/4", 6.6#, L80/Solid: 11,990' MD – 12,200' MD (210' liner) x 2-7/8", 6.5#, L80/Solid: 12,200' MD – 14,892' MD (2,692' 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” 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. Directional: x Directional plan attached. Maximum planned hole angle is 93°. Inclination at kick off point is 90°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 6100 ft x Distance to nearest well within pool – 800 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 1500' perforated post rig – See attached extended perforating procedure. x 2.0" 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 Kuparuk pool. x Formations: Top of Kuparuk is 10,235' MD in the parent Anti-Collision Failures: x Anti-Collision Summary – WP06 – all wells pass AC Hazards: x S Pad is an H2S pad. The last H2S reading on PBU S-100: 80 ppm in 2023. x Max H2S recorded on S Pad: 500 ppm on S-201 in 2005. x 3 fault crossings expected. x 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: 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 Kuparuk 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 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" 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 3.0" Pipe / Slip HF nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 14,892' MD $) $) $)$) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $)$) $) $) $) $) $) $) $)$) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $)$) $) $) $) $) $) $) $) $) $) $) $) $) $)$) $) $)$)$) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) $) ! !!!!!!!!!!!!!!!!!!!!!!!!!! !!!!!!! !!!!!!!!!! !!!! !!!!!! !!!! !!!!!! ! !!!! !! ! !!! ! !! !!!! !! !! !!!! !!!!!!! ! !!! !!!! !! !! !!!!!!!!! !!! !! !!! !!! !!!!! !! ! !!!!!! ! ! !! !!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! ! !!!! ! !!!!!!!!!!!!!! ! ! ! ! D $) NKUPST S-01 S-01A S-01B S-01C S-02 S-02A S-03 S-04 S-06 S-08 S-08A S-08B S-09 S-09A S-10 S-100 S-101 S-102 S-103 S-104 S-105 S-105A S-106 S-108 S-10A S-113 S-113A S-113B S-114 S-114A S-115 S-116 S-116A S-117 S-118 S-120 S-121 S-122 S-125 S-126 S-128 S-129 S-129A S-134 S-135 S-13A S-16 S-17 S-17A S-17BS-17C S-18 S-18A S-19 S-20 S-200 S-200A S-201 S-201A S-202 S-202L3 S-202L4 S-20A S-21 S-210 S-213 S-213A S-213AL3 S-215 S-216 S-217 S-218 S-22 S-22A S-22B S-23 S-24A S-24B S-25 S-26 S-27 S-27A S-27B S-28S-28AS-28B S-29 S-29A S-31 S-31A S-33 S-34 S-35 S-36 S-38 S-400S-400A S-401 S-42 S-42A S-44 S-44A S-504 TW-C V-200 W-202 W-221 Prudhoe Bay Unit Sec. 21 Sec. 35 Sec. 29 Sec. 20 Sec. 27 Sec. 32 Sec. 5 Sec. 26 Sec. 22 Sec. 28 Sec. 23 Sec. 8 Sec. 9 Sec. 10 Sec. 2 Sec. 33 Sec. 34 Sec. 11 Sec. 3 Sec. 4 U012N012E U011N012E S PAD ADL28259 ADL28258 ADL28261 ADL47450 ADL28255 ADL47448 ADL28260 ADL28256 ADL28257 PLAN: S-100A_SHL PLAN: S-100A_TPH PLAN: S-100A_BHL Map Date: 6/10/2024 Prudhoe Bay Unit S-100A Well wp06 E0 1,200 2,400 Feet Legend S_100A_wp06 $)PLAN: S-100A_BHL !PLAN: S-100A_SHL D PLAN: S-100A_TPH $)Other Bottom Holes (BHL) Other Well Paths Oil and Gas Unit Boundary Pad Footprint Aurora PA Aurora CO 457B Aurora AIO 22F Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_PBU_S-100A_wp06.mxd 67006750680068506900True Vertical Depth (100 usft/in)-3400 -3200 -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 Vertical Section at 190.00° (400 usft/in)S-100S-100A wp06Top of Window - 12000'MDTD - 14892'MD15002000250030003500400045005000South(-)/North(+) (1000 usft/in)-10000 -9500 -9000 -8500 -8000 -7500 -7000 -6500 West(-)/East(+) (1000 usft/in)4 0 0800120 01600200024002800320036004000440048005200560060006400680072007351 V-2006810S-10067534400S-10644004800520056006000S-11352005600600064 0 0 6 8 0 0 6984 S-113A5200 5600S-113B4400480052005600S-11456006000S-114A6894S-100A wp06Top of Window - 12000'MDTD - 14892'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 12000.00 90.37 274.41 6811.30 4426.08 -7618.23 0.00 0.00 -3035.952 12020.00 88.99 273.25 6811.41 4427.42 -7638.18 9.00 -140.00 -3033.803 12091.00 83.56 268.66 6816.03 4428.60 -7708.98 10.00 -140.00 -3022.674 12240.60 90.00 255.13 6824.47 4407.56 -7856.41 10.00 -65.00 -2976.345 12461.00 90.00 233.09 6824.47 4311.92 -8053.48 10.00 -90.00 -2847.946 12601.00 92.88 219.39 6820.93 4215.37 -8154.31 10.00 -78.00 -2735.357 12860.00 92.59 193.46 6808.34 3985.67 -8268.44 10.00 -90.00 -2489.328 12930.00 92.57 186.45 6805.18 3916.83 -8280.52 10.00 -90.00 -2419.439 13022.75 92.50 177.17 6801.07 3824.32 -8283.44 10.00 -90.25 -2327.8210 13243.01 92.50 199.22 6791.46 3607.86 -8314.60 10.00 90.00 -2109.2311 13483.01 92.50 175.19 6780.99 3371.72 -8344.45 10.00 -90.00 -1871.5012 13723.01 92.50 199.22 6770.52 3135.58 -8374.29 10.00 90.00 -1633.7613 13948.01 92.50 176.69 6760.71 2914.39 -8405.20 10.00 -90.00 -1410.5614 14148.01 92.50 196.71 6751.99 2716.95 -8428.40 10.00 90.00 -1212.1015 14358.91 90.00 175.76 6747.33 2508.52 -8451.16 10.00 -96.50 -1002.8816 14469.00 90.00 186.77 6747.33 2398.63 -8453.60 10.00 90.00 -894.2317 14674.00 69.83 183.06 6783.07 2198.63 -8471.00 10.00 -170.00 -694.2518 14892.00 48.43 178.11 6894.33 2012.71 -8473.81 10.00 -170.00 -510.67Project: Prudhoe BaySite: SWell: S-100Wellbore: PLAN: S-100APlan: S-100A wp06WELLBORE DETAILSParent Wellbore:PLAN: S-100APB1Top of Window: 12000.00S-100A wp06Depth From Depth To Survey/Plan Tool211.44 211.44 S-100 Rigs MWD (S-100) 3_MWD304.28 12000.00 Survey #1 MWD+IFR: AK (S-100) 3_MWD (BP MWD+IFR:AK)12000.00 14892.00 S-100A wp06 (PLAN: S-100A) 3_MWDWELL DETAILSNorthing: 5980639.87Easting: 618929.90Lattitude: 70° 21' 20.7343 NLongitude: 149° 2' 2.9193 WS-100A wp06SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well S-100, True NorthVertical (TVD) Reference: KB @ 64.65usft (S-100)Measured Depth Reference: KB @ 64.65usft (S-100)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION ! 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" # $ % * ' +- 8 # 0 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. 224-083 PBU S-100A PRUDHOE BAY AURORA OIL WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN AURO S-100AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240830PRUDHOE BAY, AURORA OIL - 640120NA1Permit fee attachedYesADL028257 and ADL0282582Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, AURORA OIL - 640120 - governed by CO 457B4Well 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)YesThis well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.18Conductor string providedYesThis well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.19Surface casing protects all known USDWsYesThis well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.20CMT vol adequate to circulate on conductor & surf csgYesThis well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYesThis well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.23Casing designs adequate for C, T, B & permafrostYesCDR2 has adequate tankage and good trucking support24Adequate tankage or reserve pitYesSundry 323-33825If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan identifies no close approaches26Adequate wellbore separation proposedNAAll drilliinng below the surface casing shoe. No diverter required.27If diverter required, does it meet regulationsYesMPD but reservoir pressure below water gradient.28Drilling fluid program schematic & equip list adequateYes CT Packoff, flow cross, annular, blind shear, CT pipe slips, flow cross, BHA pipe slips, CT pipe slips29BOPEs, do they meet regulationYes7-1/16" 5000 psi stack pressure tested to 3500 psi.30BOPE press rating appropriate; test to (put psig in comments)YesFlanged choke and kill lines between dual combi's w remote choke31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesPBU S-pad is an H2S pad >100 ppm. Monitoring will be required.33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)NoMeasures required. 80 ppm measured at parent wellbore PBU S-100 (2023)35Permit can be issued w/o hydrogen sulfide measuresYesPore pressure anticipated to be 7.9 ppg EMW. MPD to be employed to target 9.8 ppg.36Data presented on potential overpressure zonesNAThree fault crossings expected.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate9/12/2024ApprMGRDate7/26/2024ApprADDDate9/12/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: JLC 9/17/2024
