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Home My WebLink About224-087MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:14 Township:10N Range:14E Meridian:Umiat Drilling Rig:NA Rig Elevation:NA Total Depth:14513 ft MD Lease No.:ADL 028315 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 119 Feet Csg Cut@ na Feet Surface:13 3/8"O.D. Shoe@ 2525 Feet Csg Cut@ na Feet Intermediate:9 5/8"O.D. Shoe@ 5814 Feet Csg Cut@ na Feet Production:O.D. Shoe@ Feet Csg Cut@ na Feet Liner:7"O.D. Shoe@ 10503 Feet Csg Cut@ na Feet Liner:4 1/2"O.D. Shoe@ 13802 Feet Csg Cut@ na Feet Tubing:n/a O.D. Tail@ Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Retainer 2600 ft 2518 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2765 2719 2703 IA 0 0 0 OA 0 0 0 Initial 15 min 30 min 45 min Result Tubing IA OA Attachments: Nick Drapper Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Remarks: I traveled to PBU 13-24B to witness P&A operations - wireline tag of cement and a pressure test. The tool string was made up with 8 ft of 2 5/8" weight bar, jars, long spanges, a centralizer, knuckle joint, and a 3-ft long sample bailer. 225lbs of hanging weight. They tagged top of cement @ 2518 ft MD inside 4 1/2" tied back liner. The bailer brought back a good sample of firm cement. Pressure test good. September 17, 2025 Adam Earl Well Bore Plug & Abandonment PBU 13-24B Hilcorp North Slope LLC PTD 2240870; Sundry 325-144 none Test Data: P Casing Removal: rev. 3-24-2022 2025-0917_Plug_Verification_PBU_13-24B_ae                     Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 09/15/2025 InspectNo:susSTS250729154911 Well Pressures (psi): Date Inspected:7/26/2025 Inspector:Sully Sullivan If Verified, How?Other (specify in comments) Suspension Date:1/10/2025 #324-452 Tubing:60 IA:250 OA:0 Operator:Hilcorp North Slope, LLC Operator Rep:Andy Ogg Date AOGCC Notified:7/25/2025 Type of Inspection:Initial Well Name:PRUDHOE BAY UNIT 13-24B Permit Number:2240870 Wellhead Condition Clean and well maintained Surrounding Surface Condition Clean with no subsidence Condition of Cellar Clean with no sign of contaminents Comments Location verified by well pad plot map Supervisor Comments Photos (3) attached Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Monday, September 15, 2025 9 9 99 9 9 9 9 9 9 9 9 9 9 9 2025-0726_Suspend_PBU_13-24B_photos_ss Page 1 of 2 Suspended Well Inspection – PBU 13-24B PTD 2240870 AOGCC Inspection Rpt # susSTS250729154911 Photos by AOGCC Inspector S. Sullivan 7/26/2025 2025-0726_Suspend_PBU_13-24B_photos_ss Page 2 of 2 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: 10/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251016 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# END 2-36 50029220140000 190024 9/17/2025 BAKER SPN T40994 END 2-74 50029237850000 224024 9/22/2025 HALLIBURTON PATCH T40995 KU 12-17 50133205770000 208089 9/23/2025 YELLOWJACKET TEMP-CALIPER T40996 KU 24-7RD 50133203520100 205099 9/24/2025 YELLOWJACKET TEMP-CALIPER T40997 M-25 50733203910000 187086 8/31/2025 YELLOWJACKET CALIPER T40998 MPC-22A 50029224890100 195198 10/4/2025 READ CaliperSurvey T40999 MPF-61 50029225820000 195117 9/27/2025 READ CaliperSurvey T41000 MPU H-16 50029232270000 204190 10/6/2025 HALLIBURTON COILFLAG T41001 NIK SI17-SE2 50629235120000 214041 9/23/2025 HALLIBURTON IPROF T41002 NS-19 50029231220000 202207 9/8/2025 HALLIBURTON COILFLAG T41003 NS-19 50029231220000 202207 9/15/2025 HALLIBURTON COILFLAG T41003 ODSN-26 50703206420000 211121 10/7/2025 HALLIBURTON MFC24 T41004 PBU 01-25A 50029208740100 225056 9/13/2025 BAKER MRPM T41005 PBU 01-25A 50029208740100 225056 9/13/2025 HALLIBURTON RBT-COILFLAG T41005 PBU 01-31A 50029216260100 225070 9/22/2025 BAKER MRPM T41006 PBU 01-31A 50029216260100 225070 9/23/2025 HALLIBURTON RBT-COILFLAG T41006 PBU 05-09A 50029202540100 199014 9/18/2025 READ ArcherVIVID T41007 PBU 07-16A 50029208560100 201153 9/20/2025 HALLIBURTON RBT T41008 PBU 07-23C 50029216350300 225043 7/4/2025 BAKER MRPM T41009 PBU 13-24B 50029207390200 224087 9/18/2025 HALLIBURTON RBT T41010 PBU 15-11C 50029206530300 210163 9/6/2025 HALLIBURTON RBT T41011 PBU 15-49C 50029226510300 215129 9/10/2025 HALLIBURTON RBT T41012 PBU H-07B 50029202420200 225064 9/30/2025 HALLIBURTON RBT-COILFLAG T41013 PBU P19 L1 50029220946000 212056 10/3/2025 HALLIBURTON RBT T41014 PBU S-14A 50029208040100 204071 9/25/2025 HALLIBURTON RBT T41015 PBU V-105 50029230970000 202131 9/30/2025 HALLIBURTON RMT3D T41016 Please include current contact information if different from above. PBU 13-24B 50029207390200 224087 9/18/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 13:17:06 -08'00' PBU 13-24B Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-087 50-029-20739-02-00 14513 8855 79 2486 5777 4869 13767 9315 20" 13-3/8" 9-5/8" 7" 4-1/2" 7873 40 - 119 39 - 2525 37 - 5814 5634 - 10503 35 - 13802 40 - 119 39 - 2525 37 - 5309 5169 - 8836 35 - 8858 10180 9315, 9870, 10794 1490 5380 6870 8160 8430 None None No Packer No Packer Bo York Operations Manager Andy Ogg andrew.ogg@hilcorp.com 907-659-5102 PRUDHOE BAY, Prudhoe Oil ADL 0028315, 0028314 N/A N/A 223 250 0 60 N/A Prudhoe Oil No SSSV Installed STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.08.18 19:13:31 - 08'00' Bo York (1248) By Grace Christianson at 8:30 am, Aug 19, 2025 RBDMS JSB 082125 DSR-9/11/25J.Lau 11/4/25 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: 3/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250318 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40221 T40221 T40222 T40222 T40223 T40224 T40225 T40226 T40226 T40227 T40228 T40229 T40230 T40231 T40232 T40233 T40234 PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.18 15:55:41 -08'00' 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 this 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 13-24B Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-087 50-029-20739-02-00 ADL 028315 & 028314 14513 Conductor Surface Intermediate Liner Liner 8855 79 2486 5777 4869 13767 9315 20" 13-3/8" 9-5/8" 7" 4-1/2" 7873 40 - 119 39 - 2525 37 - 5814 5634 - 10503 35 - 13802 2470 40 - 119 39 - 2525 37 - 5309 5169 - 8836 35 - 8858 10180 470 2670 4760 7020 7500 9315 , 9870 , 10794 1490 5380 6870 8160 8430 None None Structural No Packer No SSSV Date: Bo York Operations Manager Jerry Lau jerry.lau@hilcorp.com 907-360-6233 PRUDHOE BAY 5/15/2025 Current Pools: PRUDHOE OIL Proposed Pools: PRUDHOE 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 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.03.13 12:25:28 - 08'00' Bo York (1248) 325-144 By Grace Christianson at 2:46 pm, Mar 13, 2025 WCB 4-1-2025 DSR-3/24/25 *AOGCC witness casing cuts before any top job commences. *AOGCC witness marker cap install before backfilling. *Photo evidence of cement tops post-cut. A.Dewhurst 28APR25 10-407 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 08:07:46 -08'00'05/12/25 RBDMS JSB 051225 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 Well Name:13-24B Permit to Drill Number 224-087 Estimated Start Date:5/15/2025 API Number:50-029-20739-02-00 Regulatory Contact:Carrie Janowski 907-564-5179 (O)Carrie.Janowski@hilcorp.com Operations Engineer Jerry Lau 907-360-6233 (C)Jerry.Lau@hilcorp.com Second Call Engineer:Oliver Sternicki 907-350-0759 (C)Oliver.Sternicki@hilcorp.com Current Bottom Hole Pressure:3,250 psi @ 8,800’ TVD 7.3 PPGE | Max. Expected BHP:3,350 psi @ 8,800’ TVD 7.4 PPGE | Max. Anticipated Surface Pressure:2,470 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:0 psi (Taken on 1/10/25) Min ID 3.958” 4-1/2” TBG Max Angle:52° Deg @ 10,800’ MD Well History: PBU 13-24B drilling ops halted after partially drilling the lateral. Throughout the lateral section, there were severe fluid losses in Zone 3 of the Ivishak, along with BHA tool failures (7) and washouts (2). A collapse of the 9-5/8” CSG was found at 2651’ when a 6-1/8” drilling BHA became detained while POOH. A restriction and possible casing holes were logged with a caliper in the 9-5/8” casing at 2,651’. A 4-1/2” killstring was run and cemented at the toe and LCM was pumped down the IA to heal losses prior to the drilling rig moving off the well. A block squeeze placed a 200’ MD cement plug in 4-1/2” and 4-1/2”x7” annulus across the confining shale of the Prudhoe Oil Pool to plug and abandon the reservoir. Current Well Condition: x The 9-5/8” x 4-1/2” annulus is filled with diesel, brine, and possibly some LCM pills. The LCM has likely settled out below our scope interval. x Slickline tagged TOC in TBG at 9300’ MD, MIT-T passed to 2695 psi. Shut in TBG pressure is 0 psi. x IA injectivity is 0.55 bpm at 500 psi. Shut in IA pressure is stable at 225 psi. x MIT-OA passed to 2000 psi on 10/11/2004 x 9-5/8” possible CSG holes and restriction at 2651’ Objective: The intent of this program is to perform a full P&A of the well per 20 AAC 25.112. We will excavate and cut casings 3’ below original tundra level and install a market plate. Procedure: 1. Eline a. Punch 4-1/2” TBG from 2600-2605’ MD b. Set 4-1/2” NS CMT retainer at 2585’ MD (+/- 5’) avoiding collars. Use the poppit style that we can pump through with fullbore. 2. Fullbore – IA Surface CMT plug a. Perform injectivity test down the IA and TBG with DSL. Max pressure is 2000 psi. Send results to OE. b. Verify circ path with DSL c. Circ out down TBG with IA returns. i. 5 bbls MEOH 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 ii. 60 bbls hot (160 degF) fresh water + surfactant iii. 200 bbls (20 bbls excess) of 1% KCL/SW (100-120 degF) iv. Max pressure 2000 psi d. Pump Cement and Displacement down TBG with IA returns i. Pump 166 bbls of Class G CMT (141 bbls + 25 bbls excess) ii. Displace with 38.4 bbls of DSL iii. Confirm cement at surface in IA 1. Cement plug in IA will be from TBG punches to surface 2. Cement plug in TBG will be from TBG punches to ~2525’ MD. IA Surface Cement Properties: BHST: 35 degF Required Density: Class G or Arctic Set 14-15.8 ppg Pumpability Time: minimum 8hrs Fluid Loss: 20-200 cc/30 min IA Surface CMT Volumes: x 4-1/2” TBG from 2525’ to 2605’ = (2605’-2525’) x 0.0152 bpf = 1.2 bbls x 4-1/2” x 9-5/8” annulus from surface to 2605’ = 2605’ x 0.0535 bpf = 139.4 bbls x Total cement = 1.2 + 139.4 + (25.4 excess) = 166 bbls x Displacement in 4-1/2” TBG to 2525’ = 2525’ x 0.0152 bpf = 38.4 bbls 3. Slickline a. WOC for 3 days b. AOGCC Witnessed D&T TOC and MIT-T to 2500 psi c. Drift for E-line 4. E-line a. Perform 10’ of punches thru TBG, cemented IA, and 9-5/8” CSG to open flowpath for TBG x OA surface CMT plug. Punch from 2500’ to 2510’ MD. 5. Fullbore – This step is broken out from the cementing step to allow further troubleshooting of Arctic Pack in OA, if necessary. a. Verify circ path with DSL b. Circ out down TBG with OA returns. i. 5 bbls MEOH ii. 50 bbls hot DSL (min 120 degF) iii. 100 bbls hot (160 degF) fresh water + surfactant iv. 200 bbls (16 bbls excess) of 9.8 ppg brine (80-100 degF) v. 11 bbls DSL, U-tube for 30 min (If ambient temps are less than 20 degF) vi. Max pressure 2000 psi 6. Fullbore – TBG x OA surface CMT plug a. Pump CMT down TBG with OA returns. i. Pump 202 bbls of Class G CMT (184 bbls + 18 bbls excess) 60/40 methanol for FP to help insure proper cement bonding. -WCB Cement to be preceded by methanol spear and FW spacer. -WCB 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 ii. No displacement TBG x OA Surface CMT Properties: BHST: 35 degF Required Density: Class G or Arctic Set 14-15.8 ppg Pumpability Time: minimum 8hrs Fluid Loss: 20-200 cc/30 min TBG x OA Surface CMT Volumes: x 4-1/2” TBG from surface to 2510’ = 2510 x 0.0152 bpf = 38.2 bbls x 9-5/8” x 13-3/8” annulus from surface to 2605’ = 2605’ x 0.0535 bpf = 145.8 bbls x Total cement = 38.2 + 145.8 + (18 excess) = 202 bbls 7. Well Diagnostics a. Assist Fullbore with cement job and pump N2 across the wellhead to remove excess cement from valves. b. Bleed all wellhead pressures to 0 psi c. Monitor wellhead pressures for 24 hours after pressures were bled to 0 psi 8. Special Projects a. Excavate and cut off all casings and wellhead 3’ below original tundra grade level. b. AOGCC witness of cut-off casings before any top job commences. c. AOGCC witness cement tops in all annuli. Top off with cement as needed. d. Bead weld ¼” thick steel marker cap on outermost casing string. Photo document all steps and AOGCC witness of installed cap.Market cap to read as follows: FĖīèĺŘŕώbĺŘťēώīĺŕôϠώ[[ "ώϭώ͓͑͑ϱ͏͖͗ ®ôīīϡώώ͐͒ϱ͓͑ Iώϭώ͔͏ϱ͏͑͘ϱ͑͏͖͒͘ϱ͏͑ϱ͏͏ e. Remove shoring box, backfill excavation. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic w/ Cement Detail 3. Sundry Change Form 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 Current Wellbore Schematic 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 Proposed Schematic with Cement Detail 13-24B P&A PTD:224-087 API: 50-029-20739-02-00 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 HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Operations Manager Date Operations Engineer Date MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 14 Township: 10 N Range: 14E Meridian: Umiat Drilling Rig: Rig Elevation: Total Depth: 14513 ft MD Lease No.: ADL 028315 Operator Rep: Suspend: X P&A: Conductor: 20" O.D. Shoe@ 119 Feet Csg Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 2525 Feet Csg Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 5814 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: 7" O.D. Shoe@ 10503 Feet Csg Cut@ Feet Tubing: 4 1/2" O.D. Tail@ 13802 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Tubing Bridge plug 9870 ft 9300 ft 6.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2778 2722 2695 IA 228 228 229 OA 1 1 1 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Andreas Ponti Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): A slick line tag was performed with a 2-inch bailer. Bailer returned small hard chunks of cement. Severe damage to 9 5/8-inch intermediate casing at ~2700 ft MD. A liquid leak rate test was performed on the IA (9 5/8 x 4 1/2 inch annulus) - took 0.55 BPM @ 500 psi, for a total of 6 BBLs pumped. January 10, 2025 Bob Noble Well Bore Plug & Abandonment PBU 13-24B Hilcorp North Slope LLC PTD 2240870; Sundry 324-589 none Test Data: P Casing Removal: rev. 3-24-2022 2025-0110_Plug_Verification_PBU_13-24B_bn 9 9 9 9 9 99 9 9 9 9 9 9 99 9 9 9 999 99 9 9 9g A liquid leak rate test was performed on the IA (9 5/8 x 4 1/2 inch annulus) - took 0.55 BPMgq @ 500 psi, for a total of 6 BBLs pumped. James B. Regg Digitally signed by James B. Regg Date: 2025.02.03 11:48:31 -09'00' 1 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Tuesday, January 21, 2025 12:03 PM To:Oliver Sternicki Cc:Rixse, Melvin G (OGC) Subject:RE: 13-24B (PTD# 224087) Suspension Sundry# 324-589 Clarification Request Oliver, Given the successful placement of a reservoir cement plug in 13-24B, as confirmed by tag and MITT. Hilcorp's request to remove the condition of approval requiring the remediation of the "9-5/8” casing leak by January 31, 2025," as specified in Sundry #324-589, is hereby approved under the following conditions: 1. Hilcorp must submit a Form 10-403 for abandonment no later than February 28, 2025. 2. A 9-5/8” cement plug addressing the leak must be installed during the year 2025. Jack From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Tuesday, January 21, 2025 11:23 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: 13-24B (PTD# 224087) Suspension Sundry# 324-589 Clarification Request Jack, 13-24B work scope for reservoir abandonment and suspension per the procedure in sundry approval # 324-589 was completed on 1/10/2025. Within the conditions of approval for sundry # 324-589, a requirement was included to remediate the 9-5/8” casing leak at 2651’ MD. This additional requirement wasn’t in scope of the work request for reservoir abandonment and will require additional sundry approval. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 13-24B has no future utility due to the 9-5/8” casing restriction and the decision has been made to fully abandon the well as part of the 2025 P&A program under OTH-16-038. We plan to submit a request for abandonment of the well in February 2025 with completion of the P&A activity by the end of 2025. Hilcorp is requesting removal of the requirement: “9-5/8” casing leak to be remediated by January 31, 2025” in Sundry # 324-589 , such that the 10-407 for the completed reservoir abandonment work can be submitted and the 9-5/8” casing leak work can be handled under the abandonment sundry work. Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Supervisor Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Gluyas, Gavin R (OGC) From:Rixse, Melvin G (OGC) Sent:Saturday, January 4, 2025 2:50 PM To:Jerry Lau Cc:Joseph Lastufka; Shiloh Wagoner; Andrew Huddleston - (C) Subject:20250104 1448 APPROVAL 13-24B Suspension Sundry 324-589 Plug 1 CBL (PTD# 224-087) Attachments:HILCORP 13-24B CEMENT BOND LOG.pdf Jerry, Approved to proceed on Sundry 324-589. IA Reservoir cement plug CBL appears satisfactory. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Lastufka, Wagoner, Huddleston From: Jerry Lau <Jerry.Lau@hilcorp.com> Sent: Saturday, January 4, 2025 1:48 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Shiloh Wagoner <Shiloh.Wagoner@hilcorp.com>; Andrew Huddleston - (C) <Andrew.Huddleston@hilcorp.com> Subject: 13-24B Suspension Sundry 324-589 Plug 1 CBL (PTD#224-087) Mel, Attached is the CBL for 13-24B to determine cement isolation across the 4-1/2” x 7” Annulus. My interpretation deems that our objective to place a 200’ MD cement was met. CBL amplitude shows good cement from 9615’ to 9815’ MD with good cement patches above and below that interval. This good cement interval is shown in red on the cement detail diagram below. We will plan to run our approved CIBP at 9870’MD and await final state approval of CBL prior to pumping the next cement plug. Let me know if you want to discuss more. Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) 2 Cell: (907) 360-6233 Office: (907) 564-5280 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, January 3, 2025 6:54 PM To: Jerry Lau <Jerry.Lau@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: 13-24B Suspension Sundry 324-589 notification for CBL and requested change in scope (PTD#224-087) 3 Jerry, Approved to set the CIBP at 9870’ MD. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Joe Lastufka From: Jerry Lau <Jerry.Lau@hilcorp.com> Sent: Friday, January 3, 2025 11:48 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: 13-24B Suspension Sundry 324-589 notification for CBL and requested change in scope (PTD#224-087) Mel, Here is an update on current operations and a request for change in procedure for 13-24B. CTU pumped the first stage of cement on 13-24B after performing the extended tubing punch. No surprises thus far. We tagged cement just below the top punch. We are in the process of milling through the cement plug and then will run a the CBL. At this point, we are anticipating having the CBL sent over for state review around midnight. Having an answer upon 12 hrs of submission would be greatly appreciated. When I sent the CBL over, I’ll send a detailed cartoon with placement of cement in annulus in relation to formation tops and well features to assist with the review process. Request: While awaiting state approval on CBL, I would like to set a CIBP at ~9870’ (see detailed picture below) to provide a hard bottom in TBG in preparation for the plug 2 cement job. Plug 2 fills the 4-1/2” the milled back up with CMT from 9320’-9850’. Let me know if you have any questions Regards, Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 Cell: (907) 360-6233 Office: (907) 564-5280 Let me know if you have any questions Regards, 5 Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) Cell: (907) 360-6233 Office: (907) 564-5280 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, December 18, 2024 3:36 PM To: Jerry Lau <Jerry.Lau@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: 13-24B Suspension Sundry 324-589 Update (PTD#224-087) Jerry, Thanks for the update. I look forward to the CBL. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Jerry Lau <Jerry.Lau@hilcorp.com> Sent: Tuesday, December 17, 2024 1:43 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: 13-24B Suspension Sundry 324-589 Update (PTD#224-087) Mel, Here is a progress update on the 13-24B suspension sundry program. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 6 Completed steps: 1. Eline set CIBP and punched 30’ of TBG per program 2. Fullbore pumped injectivity test per program. We were able to get 1.5 bpm of injectivity down the TBG @ 1300 psi with diesel. We did not see any IA pressure response. The punches are designed to not penetrate the 7” (only the 4-1/2”). It appears that our flowpath is down the TBG, through the punches, down the 4- 1/2” x 7” annulus to formation beneath the 7” CSG shoe. Plan forward:  Continue monitoring IA pressure with alarm set to catch excursion event. No excursions or increases in IA pressure have occurred to date.  Perform CT cement plug scope per program. The 400’ of special ordered charges and carriers have arrived on the slope. We have this job scheduled for 1-2 weeks out.  Continue with remainder of program once AOGCC approves CBL. 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Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -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: 10/25/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: PBU 13-24B +PB1 +PB2 +PB3 PTD: 224-087 API: 50-029-23739-02-00 (13-24B) 50-029-23739-70-00 (13-24BPB1) 50-029-23739-71-00 (13-24BPB2) 50-029-23739-72-00 (13-24BPB3) FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (07/20/2024 to 09/17/2024) x ROP, BaseStar GR, StrataStar & ADR Resistivity, LithoStar Porosity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Surveys x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: PBU 13-24B LWD Subfolder: PBU 13-24B Geosteering Subfolder:g T39715 T39716 T39717 T39718 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.28 08:11:02 -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 Please include current contact information if different from above. PBU 13-24BPB1 +PB2 +PB3 LWD Subfolders: Please include current contact information if different from above. By Grace Christianson at 7:50 am, Oct 11, 2024 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.10.10 16:36:59 - 08'00' Bo York (1248) 324-589 A.Dewhurst 11OCT24 DSR-10/11/24 * 9-5/8" casing leak to be remediated by January 31, 2025. MGR11OCT24 10-407 January 31, 2025 * Service coil perf gun length not to exceed 400'. * CBL to AOGCC for approval to proceed with tubing plug. * Final pressure test of tubing to 2500 psi. * Pressure and leak rate on IA reservoir plug to be recorded to assure integrity of IA reservoir plug. 31-JAN-2025 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.11 11:07:33 -08'00'10/11/24 RBDMS JSB 101524 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Well Name:13-24B Permit to Drill Number 224-087 Estimated Start Date:10/12/24 API Number:50-029-20739-02-00 Regulatory Contact:Joseph Lastufka 907-777-8400 (O) jo4472@hilcorp.com Operations Engineer Jerry Lau 907-360-6233 (C) Jerry.lau@hilcorp.com Second Call Engineer:Dave Bjork (907) 440-0331 (M) Current Bottom Hole Pressure:3,250 psi @ 8,800’ TVD 7.3 PPGE | Max. Expected BHP:3,350 psi @ 8,800’ TVD 7.4 PPGE | Max. Anticipated Surface Pressure:2,470 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:0 psi (Taken on 10/9/24) Min ID 3.958” 4-1/2” TBG Max Angle:52° Deg @ 10,800’ MD Brief Well Summary: PBU 13-24B has drilled ~ 4000’ of the planned lateral, with ~540’ Sag River Sand. Throughout the lateral, severe fluid losses in Zone 3 of the Ivishak were experienced, along with BHA tool failures (7) and washouts (2). While pulling out of the hole with the most recent failed BHA on 9/18, the 6-1/8” drilling BHA became detained inside the 9-5/8” (47# BTC ran in 1982) at ~ 2700’, which required jarring up to free. After LD BHA, which had minimal damage, a cleanout run to push any junk down hole and troubleshoot that depth with a 6-1/8” bit was ran. The cleanout run stacked out at the same depth, taking 40k# with no progress deeper in the hole, regardless of circulation or rotation. A drift was performed with slick 4” DP past it the restriction, then slickline was rigged up for a caliper log. The log shows the ID of 9-5/8” casing at the trouble depth is necked down to ~ 5.4”, along with sections of high wall loss. Because of this severely damaged 9-5/8”, and any risk of further damage or loss of access to the reservoir swedging/milling/etc could cause, Hilcorp has elected to plug this reservoir section - allowing for future RWO and drilling options. Current Well Condition: A restriction and possible casing holes were logged with a caliper in the 9-5/8” casing at ~2,700’. This drove the decision to pursue cement plugs. A 4-1/2” killstring was landed at 13,801’, and cemented in place. Killstring passes a pressure test and is not available to pump down. The 9-5/8” x 4-1/2” annulus has been on continuous hole fill. Top of cement behind the 4-1/2” killstring is unknown due to the loss zone. Major losses were being experienced in the Top Conglomerate/Zone 3. The well intersects the loss zone at approximately 10,963’ on the uphole side of the sump. On 9/25/24 the rig bullheaded multiple LCM pills down the 9-5/8” x 4-1/2” annulus and the loss rate has fallen to a minimum allowing fluid level to be kept at surface in the 9-5/8” x 4-1/2” annulus. 4-1/2” punches were made from 10935’-10947’. Eline CBL from 11140’-5495’ did not find cement. Subsequent pumping ops to establish circulation were inadequate for a cement plug. 4-1/2” punches were made from 10844’-10856’. Pumping ops were able to get ~10% returns while pumping 350 bbls seawater down TBG with IA returns. This was deemed sufficient to move forward with CTU cementing plan. CTU set a retainer at 10,794’ – they were unable to get circulation down CT with IA returns to surface. 223 bbls of diesel were pumped to ensure IA remained freeze protected. x The 4-1/2” killstring is loaded with seawater and a diesel freeze protect. x The 9-5/8” x 4-1/2” annulus is loaded with two LCM pills, seawater and a diesel freeze protect. x Valve style cement retainer at 10,794’ is closed – now functioning as a plug in the 4-1/2”. Objective: 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Drilling Operations Shutdown. Place a 200+ ft cement plug to isolate the Prudhoe oil pool from the rest of the wellbore. Plug will be contained within the 7” CSG remedial cement logged interval straddling the top of the HRZ. IA Volume: 9-5/8” x 4-1/2” down to 5,624’ = 0.0535 bbl/ft x 5,624’ = 301 bbl 7” x 4-1/2” down to 10,503’ = 0.0168 bbl/ft x (10,503’ – 5,624’) = 82 bbl Total annulus volume to 7” shoe = 383 bbl Required Cement Properties: BHST: 175 degF Required Density: 15.8ppg +/- 0.2 ppg Pumpability Time: minimum 8hrs Fluid Loss: 100 – 200 cc/30 min Procedure: 1. Eline a. Set 4-1/2” CBP or CIBP at 9,860’ MD. b. Punch 30’ of 4-1/2” TBG from 9,820’ – 9,850’ MD. Use 6 spf (or more) shot density with big hole charges designed to penetrate 4-1/2” and not 7”. This is the bottom 30’ of the 400’ proposed block squeeze interval. We will use this to see if we can establish a flowpath. 2. Fullbore a. Attempt to get injectivity into TBG punches at 3000 psi with up to 40 bbls of diesel. The objective is to see if LCM in annulus can be lifted or flushed downhole prior to coil cement job, which could change our strategy. b. Monitor IA for pressure response. Keep IA pressure below 500 psi. Authorization to increase to 1000 psi with OE approval. c. Contact OE with injectivity test and IA pressure response results for further instruction. Note: If steps 1 and 2 enable us to establish a flowpath to flush annulus fluids into formation or to circulate annulus fluids out of the IA, then a program revision will be made with more traditional methodology to place a cement plug (ie. bullhead/downsqueeze or circulating in a balance plug). The following steps to place the cement via a block squeeze assume minimal or no flowpath is established prior to coil rigging up. Coiled Tubing Procedure: 3. RIH with logging tools for coil flag and displace TBG down to 4-1/2” CIBP with 9.8 PPG brine. a. Total volume of 4-1/2” to CIBP: 0.0152 bpf x 9,860’ = 150 bbls. 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 Perforating jobs, 24-hour crew and WSS coverage is required. x The well will be killed and monitored before making up the initial perfs guns. 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. 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. 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 4. 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. 5. Max tubing pressure 2500 psi. 6. At surface, prepare for deployment of TCP guns. 7. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 9.8 PPG Brine as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 8.*Perform drill by picking up safety joint with 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. a.At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns one time to confirm the threads are compatible. 9.Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying punches to ensure the well remains killed and there is no excess flow. Punch Schedule Punch Interval Punch Length Weight of Gun (lbs) 8.8 lbs/ft 9450 - 9850 400’3520 10. RIH with punches and tie-in to coil flag correlation. Pickup and punch interval per schedule above. a. Note any tubing pressure change in WSR. 11. After punching, 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. 12. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary. 13. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 14. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 15. Swap from open hole deployment to standard PCE system for subsequent runs. 16. Perform injectivity test down coil backside at 3000 psi to assess flowpath. Monitor IA pressure. Max IA pressure is 500 psi (1000 psi with OE approval). Reports results to OE. 17. RIH slim with cementing nozzle a. Swap backside over to diesel down to 9000’ while leaving fresh water at the nozzle. b. Drift through punched interval while attempting to bullhead into punches. Perform weight checks frequently to ensure LCM is not falling on backside of coil. Planned TOC in 4-1/2” is 9,320’. c. Place 17 bbls 15.8 PPG cement plug from 9450’ – 9850’ in TxIA. i. TBG volume = 400’ x 0.0152 bpf = 6.1 bbls ii. Annular volume = 400’ x .0175 bpf = 7 bbls iii. Excess volume = 2 bbls underdisplaced + 2 bbls squeeze = 4 bbls iv. Total volume = 6.1 + 7 + 4 = 17.1 bbls d. POOH. 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 18. WOC for 12 hrs. 19. RIH and mill out cement plug and 4-1/2” CIBP. Cleanout down to 10,150’ MD. 20. RIH with CBL and log from 10,100’ to 5500’. 21. Coil RIH slim with cementing nozzle a. Lay in 8 bbl 15.8 PPG cement plug from 9320’ – 9850’ in 4-1/2” TBG. Planned TOC is 9,320’. I. TBG volume = 527’ x 0.0152 bpf = 8 bbls b. Leave wellbore freeze protected down to 2500’ c. POOH. 22. Coil RDMO 23. WOC for 3 days 24. Slickline a. Drift and tag TOC. b. Pressure test TBG to 2500 psi with diesel. c. IA injectivity test to 500 psi with diesel. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Reservoir Plug Cement Detail 4. Coil Tubing BOPE Schematic 5. Standing Orders for Open Hole Well Control during Perf Gun Deployment 6. Equipment Layout Diagram 7. Sundry Change Form * CBL to AOGCC for review and approval to proceed. - mgr 24 hour notice for AOGCC to witness tag, pressure test tubing, and IA injectivity test. - mgr 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Reservoir Plug Cement Detail 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Coiled Tubing BOPs 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Standing Orders for Open Hole Well Control during Perf Gun Deployment 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 Equipment Layout Diagram 13-24B Ops Shutdown PTD: 224-087 API: 50-029-20739-02-00 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 HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Operations Manager Date Operations Engineer Date Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.09.26 16:58:10 - 08'00' Bo York (1248) September 25, 2024 By Grace Christianson at 8:20 am, Sep 27, 2024 324-558 Yes A.Dewhurst 27SEP24 * 9-5/8" casing leak will require additional 10-403 within 30 days of completion of this work with plan to secure IC casing leak with patch or with an approved cement abandonment plug. * Variance to 20 AAC 25.112 (g) (2) approved for 500 psi pressure test of reservoir plug.. Mel Rixse - Senior Petroleum Engineer 10-407 27-Sep-2024 MGR27SEP24 * CBL logs to AOGCC for review. * Target IA TOC at 10,003' MD in IA and tubing. * Service coil tag for reservoir plug. Pressure test not possible because of 9-5/8" casing collapse. * IA TOC for reservoir plug to be reviewed and approved by AOGCC by CBL review. * 24/7 man watch at wellsite until IA secured at the reservoir plug. DSR-9/27/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.30 08:29:09 -08'00'09/30/24 RBDMS JSB 100124 * AOGCC to require 24/7 man watch on IA pressure gauge. If pressure build, bullheading is preferred, otherwise lube and bleed to reduce pressures. - mgr 26. Slick line tag or service coil tag of cement ~10,003 inside 4-1/2" tubing. AOGCC to witness. 30 minute pressure test of reservoir plugs to 500' psi. Pressure test to be charted and recorded with AOGCC notice for opportunity to witness. - mgr AOGCC approval of reservoir plugs with review of CBLs and pressure test. Within 30 days of approved reservoir plug Hilcorp to submit a 10-403 for securing 9-5/8" casing leak. - mgr CBL to AOGCC. 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: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240927 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T39593 T39594 T39595 T39596 T39597 T39598 T39599 T39600 T39601 T39602 T39603 T39603 T39604 T39605 T39605 T39605 T39605 T39606 T39606 T39607 T39608 T39609 T39609 T39610 T39611 PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -08'00' From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Date:Monday, September 16, 2024 9:57:13 AM From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, August 21, 2024 9:24 AM To: Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, For preliminary planning, I would like to see the packer be set >= 100’ below the top of the HRZ and hopefully have 50’+ of continuous cement above the production packer. This is all in accordance to 25.412 (b) stating: 20 AAC 25.412 Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (a) A well used for injection must be cased and cemented in accordance with 20 AAC 25.030 to prevent leakage into oil, gas, or freshwater sources. (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. I will need Andy and Steve to agree to this here at AOGCC so this is not yet final. I just wanted to pass along so you could see where I stand on this. AOGCC maybe asking for OH logs. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Andy, Steve, Chris From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 4:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Thank you, Sir. Sounds good, will talk in the morning. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, August 20, 2024 4:37 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Hilcorp is approved to set cement retainer and bullhead ~30 bbls of cement. I want to review confining zones with Chris Wallace, Andy Dewhurst and Steve Davies before shooting holes and squeezing cement above the retainer. Because this is a service well, we will want the production packer below the top of the confining zones to assure a monitorable annulus, so no injection goes out of zone. We can decide on the perforation holes in the morning. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 12:49 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: Hilcorp PBU 13-24B (PTD 224-087) Update Mel – I wanted to give you an update on PBU 13-24B. We set our second whipstock and drilled the intermediate redrill to TD of 10511’ MD (Top Sag 10506’ MD) without issue. We then ran our 7” liner in the hole, circulating at planned depths of ~ 7400 and 9400 with no issues. We ran in hole on elevators to 10,500’ MD, establishing circulation and returns, however yesterday evening when we picked up the cement head and began to wash down to planned shoe depth of 10508’ MD we were unable to get past 10503’, lost returns and had no pipe movement or rotation. We pressured up at .5 bpm to a limit of 1500psi (max before potentially functioning the pusher tool on the SLZXP) and ended up establish an injection rate at 600 psi before shutting down pumps. Unable to reliably attempt a cement job without risking filling the line with cement, we left-had released from the liner and pulled out of the hole without setting the liner hanger or packer. We then picked up a 7” cement retainer and are currently RIH to set the retainer ~ 30’ above the float collar of the liner to attempt to squeeze the shoe with ~ 30 bbls of cement. Our proposed plan forward for a remedial cement job is as follows: RIH with 7” cement retainer and set ~ 10,353’ MD Establish Injection or circulation and pump 30bbl 15.8ppg Class G Cement 30bbl max or until pressures up RU Eline, set bridge plug ~ 9600’ 100’ below top of HRZ Perforate with e-line at ~9561’ MD 50’ MD below top of HRZ (top HRZ 9,511’ MD) RIH with Cement retainer and set at ~ 9500’ Squeeze cement underneath retainer and into perforations Cement volume: 70bbl 15.8ppg Class G ~1000’ MD of 9-7/8” x 7” annulus with 30% washout 70 bbl max or until pressures up Wait on Cement RU E-Line and Perform CBL across squeeze interval RIH set liner top packer Drill out 7” retainers and shoe track Proceed as per approved PTD 4-1/2” liner hanger will be brought up to 150’ above the remedial perfs and cemented to isolate the perforations With 13-24B being proposed as an MI injector, it is imperative that injection fluids are confined to the Sag River Pool. Hilcorp believes a cement squeeze of the 7” shoe will provide solid FIT, unstable/collapsed Kingak has shown to prevent circulation up to 600 psi (where injection was established, ~12.3ppg EMW with 600 psi and 11 ppg mud), a cement plug starting 50’ below the top of the HRZ in the confining zone verified with CBL, and the 4-1/2” cemented liner top packer being set 150’ above the remedial perforations is sufficient to demonstrate controlled injection. Out of zone injection will be further mitigated by lateral sump design with the first injection perforation ~ 2000’ MD away the 7” liner shoe. Attached is a proposed schematic showing remedial perforations and the 4-1/2” cemented liner lap. Please let me know if you approve of this remedial plan or if you have any questions. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Hilcorp PBU 13-24B (PTD 224-087) Update Date:Monday, September 16, 2024 9:56:36 AM From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, August 20, 2024 4:37 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Hilcorp is approved to set cement retainer and bullhead ~30 bbls of cement. I want to review confining zones with Chris Wallace, Andy Dewhurst and Steve Davies before shooting holes and squeezing cement above the retainer. Because this is a service well, we will want the production packer below the top of the confining zones to assure a monitorable annulus, so no injection goes out of zone. We can decide on the perforation holes in the morning. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 12:49 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: Hilcorp PBU 13-24B (PTD 224-087) Update Mel – I wanted to give you an update on PBU 13-24B. We set our second whipstock and drilled the intermediate redrill to TD of 10511’ MD (Top Sag 10506’ MD) without issue. We then ran our 7” liner in the hole, circulating at planned depths of ~ 7400 and 9400 with no issues. We ran in hole on elevators to 10,500’ MD, establishing circulation and returns, however yesterday evening when we picked up the cement head and began to wash down to planned shoe depth of 10508’ MD we were unable to get past 10503’, lost returns and had no pipe movement or rotation. We pressured up at .5 bpm to a limit of 1500psi (max before potentially functioning the pusher tool on the SLZXP) and ended up establish an injection rate at 600 psi before shutting down pumps. Unable to reliably attempt a cement job without risking filling the line with cement, we left-had released from the liner and pulled out of the hole without setting the liner hanger or packer. We then picked up a 7” cement retainer and are currently RIH to set the retainer ~ 30’ above the float collar of the liner to attempt to squeeze the shoe with ~ 30 bbls of cement. Our proposed plan forward for a remedial cement job is as follows: RIH with 7” cement retainer and set ~ 10,353’ MD Establish Injection or circulation and pump 30bbl 15.8ppg Class G Cement 30bbl max or until pressures up RU Eline, set bridge plug ~ 9600’ 100’ below top of HRZ Perforate with e-line at ~9561’ MD 50’ MD below top of HRZ (top HRZ 9,511’ MD) RIH with Cement retainer and set at ~ 9500’ Squeeze cement underneath retainer and into perforations Cement volume: 70bbl 15.8ppg Class G ~1000’ MD of 9-7/8” x 7” annulus with 30% washout 70 bbl max or until pressures up Wait on Cement RU E-Line and Perform CBL across squeeze interval RIH set liner top packer Drill out 7” retainers and shoe track Proceed as per approved PTD 4-1/2” liner hanger will be brought up to 150’ above the remedial perfs and cemented to isolate the perforations With 13-24B being proposed as an MI injector, it is imperative that injection fluids are confined to the Sag River Pool. Hilcorp believes a cement squeeze of the 7” shoe will provide solid FIT, unstable/collapsed Kingak has shown to prevent circulation up to 600 psi (where injection was established, ~12.3ppg EMW with 600 psi and 11 ppg mud), a cement plug starting 50’ below the top of the HRZ in the confining zone verified with CBL, and the 4-1/2” cemented liner top packer being set 150’ above the remedial perforations is sufficient to demonstrate controlled injection. Out of zone injection will be further mitigated by lateral sump design with the first injection perforation ~ 2000’ MD away the 7” liner shoe. Attached is a proposed schematic showing remedial perforations and the 4-1/2” cemented liner lap. Please let me know if you approve of this remedial plan or if you have any questions. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Some people who received this message don't often get email from jengel@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Date:Monday, September 16, 2024 9:56:03 AM Attachments:image001.png PBU 13-24B RT 5IN MD.pdf13-24B.txt From: Joseph Engel <jengel@hilcorp.com> Sent: Wednesday, August 21, 2024 10:19 AM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Mel – Thank you for the guidance. Jerry and I will make sure that for our proposed squeeze program we will have perforations and tubing set depths to satisfy those requirements: “the packer be set >= 100’ below the top of the HRZ and hopefully have 50’+ of continuous cement above the production packer” During our shoe squeeze yesterday evening, we pumped 41 bbls and we did see lift pressure which was encouraging that our pack off could be higher than anticipated. We are currently RIH with e-line to perform a CBL, after 1000 psi comp strength is achieved as per UCA chart, to see if there is cement above the shoe. Once we see those results, we will communicate them to you to proceed forward. Andy – Attached are the LWD logs in MD, the surveys, and the actual formation tops seen in this intermediate hole. I will be out of office starting this afternoon, Nathan Sperry will be covering for me and Jerry Lau has been involved in the conversations. Thank you for your time and help. Joe Formation Tops: From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, August 21, 2024 9:32 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Yes, to assist us, would you please provide field copies of the directional plan (.txt, .csv, etc), LWD logs (.las), and a list of relevant actual/observed formation tops. Thank you, Andy From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, 21 August, 2024 09:24 To: Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, For preliminary planning, I would like to see the packer be set >= 100’ below the top of the HRZ and hopefully have 50’+ of continuous cement above the production packer. This is all in accordance to 25.412 (b) stating: 20 AAC 25.412 Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (a) A well used for injection must be cased and cemented in accordance with 20 AAC 25.030 to prevent leakage into oil, gas, or freshwater sources. (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. I will need Andy and Steve to agree to this here at AOGCC so this is not yet final. I just wanted to pass along so you could see where I stand on this. AOGCC maybe asking for OH logs. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Andy, Steve, Chris From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 4:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Thank you, Sir. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Sounds good, will talk in the morning. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, August 20, 2024 4:37 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Hilcorp is approved to set cement retainer and bullhead ~30 bbls of cement. I want to review confining zones with Chris Wallace, Andy Dewhurst and Steve Davies before shooting holes and squeezing cement above the retainer. Because this is a service well, we will want the production packer below the top of the confining zones to assure a monitorable annulus, so no injection goes out of zone. We can decide on the perforation holes in the morning. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 12:49 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: Hilcorp PBU 13-24B (PTD 224-087) Update Mel – I wanted to give you an update on PBU 13-24B. We set our second whipstock and drilled the intermediate redrill to TD of 10511’ MD (Top Sag 10506’ MD) without issue. We then ran our 7” liner in the hole, circulating at planned depths of ~ 7400 and 9400 with no issues. We ran in hole on elevators to 10,500’ MD, establishing circulation and returns, however yesterday evening when we picked up the cement head and began to wash down to planned shoe depth of 10508’ MD we were unable to get past 10503’, lost returns and had no pipe movement or rotation. We pressured up at .5 bpm to a limit of 1500psi (max before potentially functioning the pusher tool on the SLZXP) and ended up establish an injection rate at 600 psi before shutting down pumps. Unable to reliably attempt a cement job without risking filling the line with cement, we left-had released from the liner and pulled out of the hole without setting the liner hanger or packer. We then picked up a 7” cement retainer and are currently RIH to set the retainer ~ 30’ above the float collar of the liner to attempt to squeeze the shoe with ~ 30 bbls of cement. Our proposed plan forward for a remedial cement job is as follows: RIH with 7” cement retainer and set ~ 10,353’ MD Establish Injection or circulation and pump 30bbl 15.8ppg Class G Cement 30bbl max or until pressures up RU Eline, set bridge plug ~ 9600’ 100’ below top of HRZ Perforate with e-line at ~9561’ MD 50’ MD below top of HRZ (top HRZ 9,511’ MD) RIH with Cement retainer and set at ~ 9500’ Squeeze cement underneath retainer and into perforations Cement volume: 70bbl 15.8ppg Class G ~1000’ MD of 9-7/8” x 7” annulus with 30% washout 70 bbl max or until pressures up Wait on Cement RU E-Line and Perform CBL across squeeze interval RIH set liner top packer Drill out 7” retainers and shoe track Proceed as per approved PTD 4-1/2” liner hanger will be brought up to 150’ above the remedial perfs and cemented to isolate the perforations With 13-24B being proposed as an MI injector, it is imperative that injection fluids are confined to the Sag River Pool. Hilcorp believes a cement squeeze of the 7” shoe will provide solid FIT, unstable/collapsed Kingak has shown to prevent circulation up to 600 psi (where injection was established, ~12.3ppg EMW with 600 psi and 11 ppg mud), a cement plug starting 50’ below the top of the HRZ in the confining zone verified with CBL, and the 4-1/2” cemented liner top packer being set 150’ above the remedial perforations is sufficient to demonstrate controlled injection. Out of zone injection will be further mitigated by lateral sump design with the first injection perforation ~ 2000’ MD away the 7” liner shoe. Attached is a proposed schematic showing remedial perforations and the 4-1/2” cemented liner lap. Please let me know if you approve of this remedial plan or if you have any questions. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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'HQVLW\&RUUHFWLRQ JUDPSHUFF KRXUV )RUPDWLRQ([S7LPH 'HQVLW\530 UHYSHUPLQ CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Some people who received this message don't often get email from jerry.lau@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PTD 224-087 Hilcorp Well PBU 13-24B Update Date:Monday, September 16, 2024 9:55:28 AM Attachments:image001.png PBU 13-24B Proposed Schematic V2 08-21-24.pdf From: Jerry Lau <Jerry.Lau@hilcorp.com> Sent: Wednesday, August 21, 2024 2:30 PM To: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Engel <jengel@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: PTD 224-087 Hilcorp Well PBU 13-24B Update Mel, Attached is a first look at the Proposed schematic for the remedial cement sundry Joe L is sending your way soon. The updated packer depth is 120’ feet below THRZ in accordance with 25.412 (b) requirements. We are assuming that the CBL just ran will not find cement. If possible, we would appreciate verbal/written approval to move forward with the next steps for eline to set a bridge plug at ~9800’, perforate 5’ per schematic, and set retainer above perforations at ~9700’ while we await sundry approval. Regards, Jerry Lau Operations Engineer Hilcorp Alaska, LLC From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Wednesday, August 21, 2024 1:42 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Engel <jengel@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: PTD 224-087 Hilcorp Well PBU 13-24B Update Mel, We are in the process of running the CBL but the initial pass shows no cement. We were able to get down to 10,271’ MD with e-line. Joe is out-of-the-office now. I’ll work with Joe Lastufka to submit a procedure via sundry here this afternoon. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, August 21, 2024 10:22 AM To: Joseph Engel <jengel@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, I look forward to seeing the CBL later today. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Joseph Engel <jengel@hilcorp.com> Sent: Wednesday, August 21, 2024 10:19 AM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Mel – Thank you for the guidance. Jerry and I will make sure that for our proposed squeeze program we will have perforations and tubing set depths to satisfy those requirements: “the packer be set >= 100’ below the top of the HRZ and hopefully have 50’+ of continuous cement above the production packer” During our shoe squeeze yesterday evening, we pumped 41 bbls and we did see lift pressure which was encouraging that our pack off could be higher than anticipated. We are currently RIH with e-line to perform a CBL, after 1000 psi comp strength is achieved as per UCA chart, to see if there is cement above the shoe. Once we see those results, we will communicate them to you to proceed forward. Andy – Attached are the LWD logs in MD, the surveys, and the actual formation tops seen in this intermediate hole. I will be out of office starting this afternoon, Nathan Sperry will be covering for me and Jerry Lau has been involved in the conversations. Thank you for your time and help. Joe Formation Tops: CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, August 21, 2024 9:32 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Yes, to assist us, would you please provide field copies of the directional plan (.txt, .csv, etc), LWD logs (.las), and a list of relevant actual/observed formation tops. Thank you, Andy From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, 21 August, 2024 09:24 To: Joseph Engel <jengel@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, For preliminary planning, I would like to see the packer be set >= 100’ below the top of the HRZ and hopefully have 50’+ of continuous cement above the production packer. This is all in accordance to 25.412 (b) stating: 20 AAC 25.412 Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (a) A well used for injection must be cased and cemented in accordance with 20 AAC 25.030 to prevent leakage into oil, gas, or freshwater sources. (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. I will need Andy and Steve to agree to this here at AOGCC so this is not yet final. I just wanted to pass along so you could see where I stand on this. AOGCC maybe asking for OH logs. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Andy, Steve, Chris From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 4:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Thank you, Sir. Sounds good, will talk in the morning. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, August 20, 2024 4:37 PM To: Joseph Engel <jengel@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] RE: Hilcorp PBU 13-24B (PTD 224-087) Update Joe, Hilcorp is approved to set cement retainer and bullhead ~30 bbls of cement. I want to review confining zones with Chris Wallace, Andy Dewhurst and Steve Davies before shooting holes and squeezing cement above the retainer. Because this is a service well, we will want the production packer below the top of the confining zones to assure a monitorable annulus, so no injection goes out of zone. We can decide on the perforation holes in the morning. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, August 20, 2024 12:49 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Jerry Lau <Jerry.Lau@hilcorp.com> Subject: Hilcorp PBU 13-24B (PTD 224-087) Update CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Mel – I wanted to give you an update on PBU 13-24B. We set our second whipstock and drilled the intermediate redrill to TD of 10511’ MD (Top Sag 10506’ MD) without issue. We then ran our 7” liner in the hole, circulating at planned depths of ~ 7400 and 9400 with no issues. We ran in hole on elevators to 10,500’ MD, establishing circulation and returns, however yesterday evening when we picked up the cement head and began to wash down to planned shoe depth of 10508’ MD we were unable to get past 10503’, lost returns and had no pipe movement or rotation. We pressured up at .5 bpm to a limit of 1500psi (max before potentially functioning the pusher tool on the SLZXP) and ended up establish an injection rate at 600 psi before shutting down pumps. Unable to reliably attempt a cement job without risking filling the line with cement, we left-had released from the liner and pulled out of the hole without setting the liner hanger or packer. We then picked up a 7” cement retainer and are currently RIH to set the retainer ~ 30’ above the float collar of the liner to attempt to squeeze the shoe with ~ 30 bbls of cement. Our proposed plan forward for a remedial cement job is as follows: RIH with 7” cement retainer and set ~ 10,353’ MD Establish Injection or circulation and pump 30bbl 15.8ppg Class G Cement 30bbl max or until pressures up RU Eline, set bridge plug ~ 9600’ 100’ below top of HRZ Perforate with e-line at ~9561’ MD 50’ MD below top of HRZ (top HRZ 9,511’ MD) RIH with Cement retainer and set at ~ 9500’ Squeeze cement underneath retainer and into perforations Cement volume: 70bbl 15.8ppg Class G ~1000’ MD of 9-7/8” x 7” annulus with 30% washout 70 bbl max or until pressures up Wait on Cement RU E-Line and Perform CBL across squeeze interval RIH set liner top packer Drill out 7” retainers and shoe track Proceed as per approved PTD 4-1/2” liner hanger will be brought up to 150’ above the remedial perfs and cemented to isolate the perforations With 13-24B being proposed as an MI injector, it is imperative that injection fluids are confined to the Sag River Pool. Hilcorp believes a cement squeeze of the 7” shoe will provide solid FIT, unstable/collapsed Kingak has shown to prevent circulation up to 600 psi (where injection was established, ~12.3ppg EMW with 600 psi and 11 ppg mud), a cement plug starting 50’ below the top of the HRZ in the confining zone verified with CBL, and the 4-1/2” cemented liner top packer being set 150’ above the remedial perforations is sufficient to demonstrate controlled injection. Out of zone injection will be further mitigated by lateral sump design with the first injection perforation ~ 2000’ MD away the 7” liner shoe. Attached is a proposed schematic showing remedial perforations and the 4-1/2” cemented liner lap. Please let me know if you approve of this remedial plan or if you have any questions. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictlyprohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient shouldcarry out such virus and other checks as it considers appropriate. _____________________________________________________________________________________ Revised By: JJL 8/20/2024 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU 13-24B Last Completed: TBD PTD: 224-087 *Estimated, Actual Depths Will Vary TREE & WELLHEAD Tree 5-1/8 bore x 7-1/16” flange FMC Wellhead FMC 13-5/8” 5K OPEN HOLE / CEMENT DETAIL 30” 490 sx Arctic Set II 17-1/2” 2555 sx Fondu, 400 sx Permafrost C 12-1/4” 500 sx Class G, 300 sx Permafrost C 8-1/2” TBD 6-1/8” 921 sx Class G Sidetrack Information B Sidetrack Window: 5814’ – 5830’ Whipstock @ 5830’ JEWELRY DETAIL No. Top MD* Item ID 1 2,200’ X Nipple 3.813” 2 TBD 1” Side Pocket Gas Lift Mandrel TBD 3 5,670’ 7” x 9-5/8” LTP 6.21” 4 5,685’ 7” x 9-5/8” LNR HGR 6.19” 5 TBD 1” Side Pocket Gas Lift Mandrel TBD 6 TBD 1” Side Pocket Gas Lift Mandrel TBD 7 9,601’ X Nipple 3.813” 8 9,630’ HES TNT 4-1/2” x 7” Production Packer 3.856” 9 9,641’ XN Nipple 3.725” 10 9,662' 5” x 7” LTP 4.320” 11 9,668’ 4-1/2” WLEG 4.00” 12 9,676’ 4-1/2” x 7” LNR HGR 3.875” PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status HRZ 9,736’ 9,741’ 5’ SAG 5,000’ GENERAL WELL INFO API: 50-029-20739-02-00 Completion Date: TD =19,111’(MD) / TD =9,011’(TVD) 5 20” Whipstock @ 5814’ KB Elev.: 73.57’ / GL Elev.: 46.97’ 9-5/8” TOC at ~7930’ 9 3 7” 1 2 Whipstock @ 6017’ 13-3/8” 10 12 PBTD =19,100’(MD) / PBTD = 9,011’ (TVD) 6 11 4 7 4-1/2” 8 4-1/2” PB1: 5830’ – 10589’ Casing 5900’ – 6880’ Cement @ ~9000’ - ~9510’ TUBING / CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20” Conductor 91.5 / H-40 / Weld N/A Surface 119’ N/A 13-3/8” Surface 72/ L-80 / BTC 12.347 Surface 2,525’ 0.1481 9-5/8” Intermediate 47 / L-80 / BTC 8.681 Surface 5,814’ 0.0732 7” Production 29 / L-80 / Vam Top 6.125 5,634’ 10,503’ 0.0451 4-1/2” Liner 12.6 / L-80 / 563 3.958 ~9,662’ 19,111’ 0.0152 4-1/2” Tubing 12.6 / L-80 / JFE Bear 3.958 Surface ~9,668’ 0.0152 WELL INCLINATION DETAIL KOP @ 5814’ Max Angle 105 deg @ 11,425’ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT 13-24B JBR 10/16/2024 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:1 Tested with 4" and 5" TJ, Accumulator bottles 20 @ 1000psi. One F on UPR VBR on 5" Low test Replaced Blocks and passed. "NT" on # 3 Rams as they did not use 7" pipe. Test Results TEST DATA Rig Rep:Vanhoose/EvansOperator:Hilcorp North Slope, LLC Operator Rep:Christopher Yearout Rig Owner/Rig No.:Hilcorp Innovation PTD#:2240870 DATE:9/3/2024 Type Operation:DRILL Annular: 250/3500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopKPS240904111540 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 2431 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 2 P Inside BOP 2 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 2-7/8" x 5-1/2 FP #2 Rams 1 Blinds P #3 Rams 1 7" Fixed NT #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 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1550 200 PSI Attained P24 Full Pressure Attained P95 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6 @ 2283 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 P11 #1 Rams P9 #2 Rams P9 #3 Rams NT0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9999 9 9 9 9 9 One F on UPR VBR FP "NT" on # 3 Rams as they did not use 7" pipe 2240870 Drilling Manager 08/21/24 Monty M Myers 324-483 By Grace Christianson at 2:55 pm, Aug 21, 2024 YES 21-AUG-2024 A.Dewhurst 21AUG24 10-407 (final completion) MGR21AUG24 DSR-8/21/24 Mel Rixse SFD for GCW 8/22/2024 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.22 08:13:54 -08'00'08/22/24 RBDMS JSB 082324 Well: PBU 13-24B PTD: 224-087 API: 50-029-20739-02-00 Well Name:PBU 13-24B Permit to Drill:224-087 API Number:50-029-20739-02-00 Estimated Start Date:Aug 20, 2024 Regulatory Contact:Joseph Lastufka 907-777-8400 (O) jo4472@hilcorp.com First Call Engineer:Joseph Engel 907-777-8395 (O) jengel@hilcorp.com Brief Well Summary: PBU 13-24B drilled the intermediate redrill to TD of 10511’ MD (Top Sag 10506’ MD) without issue. We then ran our 7” liner in the hole, circulating at planned depths of ~ 7400 and 9400 with no issues. We ran in hole on elevators to 10,500’ MD, establishing circulation and returns, however yesterday evening when we picked up the cement head and began to wash down to planned shoe depth of 10508’ MD we were unable to get past 10503’, lost returns and had no pipe movement or rotation. We pressured up at .5 bpm to a limit of 1500psi (max before potentially functioning the pusher tool on the SLZXP) and ended up establishing an injection rate at 600 psi before shutting down pumps. Unable to reliably attempt a cement job without risking filling the line with cement, we left-had released from the liner and pulled out of the hole without setting the liner hanger or packer. Objective: Hilcorp requests approval for a remedial cement job of the 7” liner, including a shoe squeeze and annulus squeeze of the 7” inside the HRZ to isolate future injection fluids. 13-24B is proposed as an MI injector, it is imperative that injection fluids are confined to the Sag River Pool. Hilcorp believes a cement squeeze of the 7” shoe will provide solid FIT, unstable/collapsed Kingak has shown to prevent circulation up to1500 psi (where injection was established at at 600 psi after breakdown, ~12.3ppg EMW with 600 psi and 11 ppg mud), a cement plug starting 50’ below the top of the HRZ in the confining zone verified with CBL, and the 4-1/2” cemented liner top packer being set 150’ above the remedial perforations is sufficient to demonstrate controlled injection. Out of zone injection will be further mitigated by lateral sump design with the first injection perforation ~ 2000’ MD away the 7” liner shoe. Plan Forward: Our proposed plan forward for a remedial cement job is as follows: RIH with 7” cement retainer and set ~ 10,353’ MD Establish Injection or circulation and pump 40bbl 15.8ppg Class G Cement o 30bbl max or until pressures up Perform CBL to determine of shoe cement squeeze had any lift pressure o Send CBL to AOGCC If shoe squeeze is not sufficient: RU Eline, set bridge plug ~ 9800’ Perforate with e-line at ~9741’ MD o ~230’ MD below top of HRZ (top HRZ 9,511’ MD) in the confining zone RIH with Cement retainer and set at ~ 9700’ Squeeze cement underneath retainer and into perforations o Cement volume: 70bbl 15.8ppg Class G ~1000’ MD of 9-7/8” x 7” annulus with 30% washout 70 bbl max or until pressures up Wait on Cement Well: PBU 13-24B PTD: 224-087 API: 50-029-20739-02-00 RU E-Line and Perform CBL across squeeze interval Send CBL to AOGCC RIH set liner top packer Drill out 7” retainers and shoe track Proceed as per approved PTD o 4-1/2” liner top packer will be brought up to ~75’ above the remedial perfs and cemented to isolate the perforations, ~ set depth 9,662’ MD o 4-1/2” Tubing Packer to be set ~120’ below top HRZ confining zone at ~ 9630’ MD ( Top HRZ: 9,511’ MD) Attachments – Current & Proposed Wellbore Schematics _____________________________________________________________________________________ Revised By: JJL 8/20/2024 CURRENT SCHEMATIC Prudhoe Bay Unit Well: PBU 13-24B Last Completed: TBD PTD: 224-087 *Estimated, Actual Depths Will Vary TREE & WELLHEAD Tree 5-1/8 bore x 7-1/16” flange FMC Wellhead FMC 13-5/8” 5K OPEN HOLE / CEMENT DETAIL 30” 490 sx Arctic Set II 17-1/2” 2555 sx Fondu, 400 sx Permafrost C 12-1/4” 500 sx Class G, 300 sx Permafrost C 8-1/2” TBD Sidetrack Information B Sidetrack Window: 5814’ – 5830’ Whipstock @ 5830’ JEWELRY DETAIL No. Top MD* Item ID 1 2,200’ X Nipple 3.813” 2 TBD 1” Side Pocket Gas Lift Mandrel TBD 3 5,670’ 7” x 9-5/8” LTP 6.21” 4 5,685’ 7” x 9-5/8” LNR HGR 6.19” 5 TBD 1” Side Pocket Gas Lift Mandrel TBD 6 TBD 1” Side Pocket Gas Lift Mandrel TBD 7 9,601’ X Nipple 3.813” 8 9,630’ HES TNT 4-1/2” x 7” Production Packer 3.856” 9 9,641’ XN Nipple 3.725” 10 9,662' 5” x 7” LTP 4.320” 11 9,668’ 4-1/2” WLEG 4.00” 12 9,676’ 4-1/2” x 7” LNR HGR 3.875” PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status GENERAL WELL INFO API: 50-029-20739-02-00 Completion Date: TD =10,511’(MD) / TD =8,842’(TVD) 20” Whipstock @ 5814’ KB Elev.: 73.57’ / GL Elev.: 46.97’ 9-5/8” TOC at ~7930’ 7” Whipstock @ 6017’ 13-3/8” PBTD =10,511’ (MD) / PBTD =8,842’ (TVD) PB1: 5830’ – 10589’ Casing 5900’ – 6880’ Cement @ ~9000’ - ~9510’ TUBING / CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" x 34” Conductor 215.5 / A53 / Weld N/A Surface 79’ N/A 13-3/8” Surface 72/ L-80 / BTC 12.347 Surface 2,525’ 0.1481 9-5/8” Intermediate 47 / L-80 / BTC 8.681 Surface 5,814’ 0.0732 7” Production 29 / L-80 / Vam Top 6.125 5,634’ 10,503’ 0.0451 WELL INCLINATION DETAIL KOP @ 5814’ Max Angle 105 deg @ 11,425’ _____________________________________________________________________________________ Revised By: JJL 8/20/2024 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU 13-24B Last Completed: TBD PTD: 224-087 *Estimated, Actual Depths Will Vary TREE & WELLHEAD Tree 5-1/8 bore x 7-1/16” flange FMC Wellhead FMC 13-5/8” 5K OPEN HOLE / CEMENT DETAIL 30” 490 sx Arctic Set II 17-1/2” 2555 sx Fondu, 400 sx Permafrost C 12-1/4” 500 sx Class G, 300 sx Permafrost C 8-1/2” TBD 6-1/8” 921 sx Class G Sidetrack Information B Sidetrack Window: 5814’ – 5830’ Whipstock @ 5830’ JEWELRY DETAIL No. Top MD* Item ID 1 2,200’ X Nipple 3.813” 2 TBD 1” Side Pocket Gas Lift Mandrel TBD 3 5,670’ 7” x 9-5/8” LTP 6.21” 4 5,685’ 7” x 9-5/8” LNR HGR 6.19” 5 TBD 1” Side Pocket Gas Lift Mandrel TBD 6 TBD 1” Side Pocket Gas Lift Mandrel TBD 7 9,601’ X Nipple 3.813” 8 9,630’ HES TNT 4-1/2” x 7” Production Packer 3.856” 9 9,641’ XN Nipple 3.725” 10 9,662' 5” x 7” LTP 4.320” 11 9,668’ 4-1/2” WLEG 4.00” 12 9,676’ 4-1/2” x 7” LNR HGR 3.875” PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status HRZ 9,736’ 9,741’ 5’ SAG 5,000’ GENERAL WELL INFO API: 50-029-20739-02-00 Completion Date: TD =19,111’(MD) / TD =9,011’(TVD) 5 20” Whipstock @ 5814’ KB Elev.: 73.57’ / GL Elev.: 46.97’ 9-5/8” TOC at ~7930’ 9 3 7” 1 2 Whipstock @ 6017’ 13-3/8” 10 12 PBTD =19,100’(MD) / PBTD = 9,011’ (TVD) 6 11 4 7 4-1/2” 8 4-1/2” PB1: 5830’ – 10589’ Casing 5900’ – 6880’ Cement @ ~9000’ - ~9510’ TUBING / CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20” Conductor 91.5 / H-40 / Weld N/A Surface 119’ N/A 13-3/8” Surface 72/ L-80 / BTC 12.347 Surface 2,525’ 0.1481 9-5/8” Intermediate 47 / L-80 / BTC 8.681 Surface 5,814’ 0.0732 7” Production 29 / L-80 / Vam Top 6.125 5,634’ 10,503’ 0.0451 4-1/2” Liner 12.6 / L-80 / 563 3.958 ~9,662’ 19,111’ 0.0152 4-1/2” Tubing 12.6 / L-80 / JFE Bear 3.958 Surface ~9,668’ 0.0152 WELL INCLINATION DETAIL KOP @ 5814’ Max Angle 105 deg @ 11,425’ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 14 Township: 10N Range: 14 Meridian: Umiat Drilling Rig: Innovation Rig Elevation: 26.5 ft RKB Total Depth: 10589 ft MD Lease No.: ADL 028315 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 119 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 2525 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 6017 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: 7" O.D. Shoe@ 6882 Feet Csg Cut@ 5901 Feet Tubing: O.D. Tail@ Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Open Hole Balanced 9523 ft 9053 ft 10.8 ppg Drillpipe tag Initial 15 min 30 min 45 min Result Tubing IA OA Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: James Lott Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): I arrived on location at 18:00 and talked with Hilcorp company man Chris Yearout about the plan forward. I was informed there was a verbal approval to lay a balanced plug in the wellbore above the HRZ and Sag hydrocarbon zones to effectivly isolate them from the well bore after a failed 7" liner run. They finished running the drill pipe in the hole to a MD of 9053 ft; a light duty 3- 1/2" cement stringer was still on bottom and 20,000 lbs of weight down on the cement plug. I had them work it a few times to insure a good solid tag. I felt confident there was indeed good cement at this depth, The cement plug was layed in at a starting depth of 9,523 ft MD which calculates to 470 ft of cement plug in the open hole section. August 7, 2024 Josh Hunt Well Bore Plug & Abandonment PBU 13-24B Hilcorp North Slope LLC PTD 2240870; Sundry 324-452 none Test Data: Casing Removal: rev. 3-24-2022 2024-0807_Plug_Verification_PBU_13-24B_jh 9 9 9 9 99 9 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.10.23 11:39:40 -08'00' Drilling Manager 08/05/24 Monty M Myers 324-452 By Grace Christianson at 3:49 pm, Aug 05, 2024 Yes 05-AUG-2024 MGR05AUG24 10-407 A.Dewhurst 06AUG24 Mel Rixse * BOPE test to 3500 psi. Annular to 2500 psi. DSR-8/12/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.12 16:39:42 -08'00'8/12/24 RBDMS JSB 081324 Isolate Plugback Well: PBU 13-24B PTD: 224-087 API: 50-029-20739-02-00 Well Name:PBU 13-24B Permit to Drill:224-087 API Number:50-029-20739-02-00 Estimated Start Date:Aug 5, 2024 Regulatory Contact:Joseph Lastufka 907-777-8400 (O) jo4472@hilcorp.com First Call Engineer:Joseph Engel 907-777-8395 (O) jengel@hilcorp.com Brief Well Summary: PBU 13-24B intermediate hole section in the top of the Sag at 10,589’ MD on 7/27, and began 7” Liner running operations on 7/29. Unfortunately, liner was unable to get past 10,250’ MD, ~500’ into the Kingak. Due to the low pressure of the sag and kingak stability risk, the decision was made to POOH for a cleanout run. While POOH with the liner, the liner became stuck at a depth of 6,882’ MD. (window depth ~ 6000’) Fishing operations were conducted, including milling the SLZXP, attempts to pull entire fish, cutting 7” fish at 5900’ and successfully removing ~3800’ of fish, and attempting to free the remaining ~980’ of fish that were unsuccessful. With unsuccessful fishing operations and deteriorating hole conditions with HRZ and Kingak that has been open for over a week, Hilcorp is making the decision to plug this hole section and re-sidetrack the well to the originally permitted target. Hilcorp as performed a cleanout run to 9523’ MD (Top HRZ 9503’ MD). Objective: Hilcorp requests to plug and isolate this hole section and sidetrack above existing whipstock to complete the well as originally permitted. Plan Forward: x aϙѹ͘͏͏Ѝϙĺċϙ͒ϱ͐ϯ͑ЋϙèôıôĲťϙŜťĖĲČôŘ x IFϙťĺϙ͔͑͒͘Ѝϙa" o ͑͏Ѝϙa"ϙϯϙ͓͐Ѝϙ«"ϙĖĲťĺϙťēôϙF¾ x Ūıŕϙ͕͑ϙææīϙæÍīÍĲèôîϙŕīŪČϙċŘĺıϙ͔͑͒͘Ѝϙa"ϙťĺϙ͘͏͑͒Ѝϙa" o ͔͏͏Ѝϙa"Ϡϙ͘ϱ͖ϯ͗ЋϙēĺīôϠϙ͒͏҇ϙôƄèôŜŜ x iiFϙ®i x IFϙÍĲîϙÍČϙi o i@ϙĲĺťĖċĖèÍťĖĺĲϙċĺŘϙĺŕŕĺŘťŪĲĖťƅϙťĺϙſĖťĲôŜŜ x iiFϙ["ϙôıôĲťϙťĖĲČôŘ x IFϙÍĲîϙŜôťϙſēĖŕŜťĺèħϙÍťϙѹϙ͔͗͒͏Ѝϙa"ϙťĺϙŜĖîôťŘÍèħϙťēôϙſôīīϙťĺϙĺŘĖČĖĲÍīīƅϙŕôŘıĖťťôîϙīĺèÍťĖĺĲ Attachments – Current & Proposed Wellbore Schematics _____________________________________________________________________________________ Revised By: JJL 8/5/2024 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU 13-24BPB1 Last Completed: TBD PTD: 224-087 TREE & WELLHEAD Tree 5-1/8 bore x 7-1/16” flange FMC Wellhead FMC 13-5/8” 5K OPEN HOLE / CEMENT DETAIL 30” 490 sx Artic Set II 17-1/2” 2555 sx Fondu, 400 sx Permafrost C 12-1/4” 500 sx Class G, 300 sx PF C 8-1/2” TBD GENERAL WELL INFO API: 50-029-20739-70-00 Completion Date: 20” Whipstock @ 6,017’ KB Elev.: 73.57’ / GL Elev.: 46.97’ 9-5/8” TOC at ~7930’ 13-3/8” PBTD = 9,000’ (MD) TD = 10,589’ (MD) / TSGR = 10,575’ (MD) Top 7” CSG @ 5900’ Top CMT plug @ ~9000’ Btm CMT plug @ 9510’ Btm 7” CSG @ 6880’ Proposed Whipstock @ 5,830’ TUBING / CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" x 34” Conductor 215.5 / A53 / Weld N/A Surface 79’ N/A 13-3/8” Surface 72/ L-80 / BTC 12.347 Surface 2,525’ 0.1481 9-5/8” Intermediate 47 / L-80 / BTC 8.681 Surface 6,017’ 0.0732 7” Production 29 / L-80 / Vam Top 6.125 5,900’ 6,880’ 0.0451 _____________________________________________________________________________________ Revised By: JJL 8/5/2024 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU 13-24B Last Completed: TBD PTD: 224-087 *Estimated, Actual Depths Will Vary TREE & WELLHEAD Tree 5-1/8 bore x 7-1/16” flange FMC Wellhead FMC 13-5/8” 5K OPEN HOLE / CEMENT DETAIL 30” 490 sx Arctic Set II 17-1/2” 2555 sx Fondu, 400 sx Permafrost C 12-1/4” 500 sx Class G, 300 sx Permafrost C 8-1/2” 153 sx Class G 6-1/8” 921 sx Class G Sidetrack Information B Sidetrack Window: 5830’ – 5800 Whipstock @ 5830’ JEWELRY DETAIL No. Top MD* Item ID 1 2,200’ X Nipple 3.813” 2 TBD 1” Side Pocket Gas Lift Mandrel TBD 3 5,670’ 7” x 9-5/8” LTP 6.21” 4 5,685’ 7” x 9-5/8” LNR HGR 6.19” 5 TBD 1” Side Pocket Gas Lift Mandrel TBD 6 TBD 1” Side Pocket Gas Lift Mandrel TBD 7 10,189’ X Nipple 3.813” 8 10,218’ HES TNT 4-1/2” x 7” Production Packer 3.856” 9 10,301’ XN Nipple 3.725” 10 10,308’ 5” x 7” LTP 4.320” 11 10,314’ 4-1/2” WLEG 4.00” 12 10,326’ 4-1/2” x 7” LNR HGR 3.875” PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status SAG 5,000’ GENERAL WELL INFO API: 50-029-20739-02-00 Completion Date: TD =19,111’(MD) / TD =9,011’(TVD) 5 20” Whipstock @ 5830’ KB Elev.: 73.57’ / GL Elev.: 46.97’ 9-5/8” TOC at ~7930’ 9 3 7” 1 2 Whipstock @ 6017’ 13-3/8” 10 12 PBTD =19,100’(MD) / PBTD = 9,011’ (TVD) 6 11 4 7 4-1/2” 8 4-1/2” PB1: 5830’ – 10589’ Casing 5900’ – 6880’ Cement @ ~9000’ - ~9510’ TUBING / CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" x 34” Conductor 215.5 / A53 / Weld N/A Surface 79’ N/A 13-3/8” Surface 72/ L-80 / BTC 12.347 Surface 2,525’ 0.1481 9-5/8” Intermediate 47 / L-80 / BTC 8.681 Surface 6,017’ 0.0732 7” Production 29 / L-80 / Vam Top 6.125 5,670’ 10,480’ 0.0451 4-1/2” Liner 12.6 / L-80 / 563 3.958 10,308’ 19,185’ 0.0152 4-1/2” Tubing 12.6 / L-80 / JFE Bear 3.958 Surface 10,314’ 0.0152 WELL INCLINATION DETAIL KOP @ 5830’ Max Angle 105 deg @ 11,425’ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT 13-24B JBR 09/25/2024 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:1 Tested with 4", 5" and 7" test joints. UPR failed on the 4" test joint were changed out and passed. Precharge Bottles = 20 each at 1000psi each. Test Results TEST DATA Rig Rep:Sture / LarsonOperator:Hilcorp North Slope, LLC Operator Rep:C. Yearout Rig Owner/Rig No.:Hilcorp Innovation PTD#:2240870 DATE:7/29/2024 Type Operation:DRILL Annular: 250/3500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopBDB240731162550 Inspector Brian Bixby Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 2431 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 2 P Inside BOP 2 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 2 7/8"x5"FP #2 Rams 1 Blinds P #3 Rams 1 7"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 3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1450 200 PSI Attained P33 Full Pressure Attained P113 Blind Switch Covers:PYES Bottle precharge P Nitgn Btls# &psi (avg)P6@2279 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P13 #1 Rams P9 #2 Rams P9 #3 Rams P9 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9999 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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 13-24B Hilcorp Alaska, LLC Permit to Drill Number: 224-087 Surface Location: 2342' FSL, 1584' FEL, Sec 14, T10N, R14E, UM, AK Bottomhole Location: 1189' FSL, 1095' FEL, Sec 22, T10N, R14E, 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, Brett W. Huber, Sr. Chair, Commissioner DATED this day of June 2024. Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.06.28 14:58:41 -08'00' 28th DSR-6/25/24MGR26JUNE2024 50-029-20739-02-00 SFD 6/28/2024 * BOPE test to 3500 psi. Annular to 2500 psi. * Casing test and FIT digital data to AOGCC upon completion of FIT. * Collision scan identifies offset well 13-29 Ivishak producer as potential collision risk while drilling this Sag well. Geosteering required and ability to close master on 13-29 offset in remote chance of wellbore intersection. * 24 hour notice for AOGCC witness of MIT-IA to 3500 psi. 2431 SFD3305 SFD 224-087 ($8 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.06.28 14:59:09 -08'00' 06/28/24 06/28/24 RBDMS JSB 070224 Verify no risk for trapped pressure under BPV. Lubricate if risk of pressure. - mgr CBL to AOGCC. -mgr 0.0152 130.5 237.7 - mgr 24 hour notice to AOGCC for opportunity to witness CMIT TXIA to 3500 psi. - mgr * Assure pad operator aware of drill by while drilling approaches 15,000' MD and can shut in master on 13-29 in the remote chance of well intersection. - mgr 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 13-24B PRUDHOE BAY 224-087 PRUDHOE OIL WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 13-24BInitial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2240870PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes Surface Location lies within ADL0028315; Top Prod Int & TD lie within ADL0028314.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes 13-31 (194-040), 13-31A (205-160), 13-29 (183-043), 13-29L1 (202-069),15 All wells within 1/4 mile area of review identified (For service well only)Yes 13-32 (182-123), 13-32A (201-235), 13-26 (182-074), 13-14 (182-171).16 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 is a sidetrack from intermediate casing at ~6000' MD18 Conductor string providedYes This is a sidetrack from intermediate casing at ~6000' MD19 Surface casing protects all known USDWsYes This is a sidetrack from intermediate casing at ~6000' MD20 CMT vol adequate to circulate on conductor & surf csgYes This is a sidetrack from intermediate casing at ~6000' MD21 CMT vol adequate to tie-in long string to surf csgYes DS 13 at PBU has identified no moveable hydrocarbons above the Sag River.22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Sundry 324-21125 If a re-drill, has a 10-403 for abandonment been approvedYes Offset well 13-29 will fails HES collision scan. Geosteering required.26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes All fluids overbalance to pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Innovation has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1x3-1/8" remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes DS 13 has a history of H2S. Monitoring required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required: high risk; rig has sensors and alarms; see p. 44.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.365 to 0.515 psi/ft (7 to 9.9 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/28/2024ApprMGRDate6/28/2024ApprSFDDate6/28/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate($8