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Home My WebLink About202-199Nolan 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: 10/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251002 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF T40937 BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF T40938 BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF T49038 BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG T40938 BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF T40939 BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF T40940 BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf T40941 BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch T40942 BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf T40942 END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF T40943 END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF T40944 END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF T40945 KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf T40946 KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF T40947 KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF T40948 KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf T40948 MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL T40949 MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL T40950 MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf T40951 MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf T40952 NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL T40953 NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF T40954 PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL T40955 PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL T40956 SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf T40957 SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf T40958 SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf T40958 Please include current contact information if different from above. PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.03 09:00:56 -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 thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU P1-08A Update to Sundry 325- 314 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-199 50-029-22384-01-00 317B ADL 0028297 12444 Conductor Surface Intermediate Liner Liner 8764 80 3519 10156 883 2887 9406 20" 10-3/4" 7-5/8" 4-1/2" 3-3/16" x 2-7/8" 8447 42 - 122 41 - 3560 37 - 10193 10017 - 10900 9557 - 12444 3168 42 - 122 41 - 3554 37 - 8742 8728 - 8759 8542 - 8764 Unknown 470 2480 4790 9406, 9818 1490 5210 6890 9250 - 12370 4-1/2" 12.6# L-80 35 - 90888343 - 8762 Structural 4-1/2" TIW HBBP Packer 4-1/2" Camco TRCF-4A 9017, 8176 2260, 2256 Date: Bo York Operations Manager Michael Hibbert michael.hibbert@hilcorp.com 907-903-5990 PRUDHOE BAY 9/8/2025 Current Pools: Stump Island Oil Proposed Pools: Stump Island Oil Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:51 am, Sep 03, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.09.02 19:58:20 - 08'00' Bo York (1248) 325-540 CDW 09/03/2025 A.Dewhurst 03SEP25 10-404 JJL 9/4/25 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test tubing PRV (global treating PRV) and pump trips prior to treatment. Same chemicals as original approved Sundry 325-314. DSR-9/9/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.10 08:47:27 -08'00'09/10/25 RBDMS JSB 091125 Well Name:P1-08A Permit to Drill:202-199 Current Status:Producer API Number:50-029-22384-01 Estimated Start Date:9/8/25 Estimated Duration:5days Regulatory Contact:Abbie Barker Sundry Number:325-314 -TBD First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Jerry Lau (907) 360-6233 (M) Program Revision:1 Current Bottom Hole Pressure:4103 psi @ 8,350’ TVDss From downhole gauges 3/10/25 Max Anticipated Surface Pressure:3,168 psi Based on 0.1 psi/ft gas gradient Last SI WHP:1,300 psi 3/10/25 Min ID:3.725” @ 9,066’ MD SWN Nipple Max Angle:49.6 deg @ 9,384’ MD Brief Well Summary: P1-08A has been recompleted to the Stump Island Pool. A fracture stimulation was pumped on this well on 11/22/24. The job screened-out with 27k lbs of proppant placed behind pipe. Objective: Prepare well for fracture stimulation and pressure test. Hydraulically fracture stimulation to improve well productivity to further appraise this Brookian interval. Post-frac slickline work and portable test unit flowback. Updated Objective (8/25/2025) The interval from 9,250’-9,260’ was reperforated and fracture stimulated on 8/15/25 with similar results that were seen in November of 2024. An early screen-out was pumped with ~15,000 lbs of proppant placed behind pipe. The proposed plan forward will be to perform a CT FCO down to ~15’ above the perforations, add 5’ of perforation above the top of fill and attempt a fracture stimulation in fresh rock. Current Status: Operable Producer, Shut-In Procedural Steps: Slickline & Fullbore Completed 8/8/25 1. Load tubing and IA with crude 2. 3. Set TTP 4. Dummy GLVs 5. MIT and MIT-IA to 3500 psi 6. Pull TTP 7. Drift and tag for EL perforating. 8. Set DB frac iso-sleeve across SSSV at 2260’ Eline Completed 8/9/25 1. Re-perforate 9,250’-9,260’ Frac Completed 8/15/25 1. Conduct Safety meeting, inspect location, and review approved Frac 10-403. 2. Ensure all pre-frac well work has been completed and the tubing and IA are freeze protected. 3. Install Tree saver. 4. MIRU SLB frac equipment and associated frac tanks. 5. Pressure test surface lines and tree saver to at least 7,206 psi. 6. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,325 psi. 7. Bring IA pressure up to hold pressure of 3,025 psi. 8. Perform ball-out perforation breakdown, step-down test and data frac if needed. (see Sundry 324-608) See Sundry 325-314 for work described below and frac checklist. -A.Dewhurst 03SEP25 9. Pump scour stage/HCL if needed to eliminate near well-bore friction. 10. Pump the fracture stimulation per the proposed pump schedule attached below. Maximum allowable treating pressure is 6,206 psi. Estimated 1,940 bbl of fluid, and 152,000# proppant. 11. RDMO frac equipment. Ensure tubing is freeze protected. New Proposed Procedure Slickline 1. D&T to SSSV 2. Pull protection sleeve from 2,260’. 3. D&T – confirm fill depth – tie into jewelry for a corrected tag depth if possible Coiled Tubing – 1. FCO down to ~9,235’ MD 2. Circulate a bottoms upand then shut down and get a tag to confirm sand top. 3. PT sandplug to 3000 psi and determine an LLR. If LLR is above 1 bpm then add ~10’ of river sand as a cap to the sand plug. 4. Confirm sand top and PT again to confirm minimal leak-off. Slickline & Fullbore – 1. D&T – tie into tubing tail to correct tag depth 2. Set TTP per last passing MIT-T on 8/8/25 and MIT-T to 4500 psi. 3. Pull TTP Eline– 1. Pull CBL log from tag to 9,000’ pull repeat passes as needed – send field logs to Michael Hibbert for analysis prior to perforating. 2. Perforate 5’ depending on CBL data between 9,185’-9,230’. Slickline – 1. Tag TD 2. Set protection sleeve across SSSV at 2,260’ Frac - 1. MIRU frac spread and associated equipment/tanks. a. Heat water to 110 deg F, minimum pumping temp – 90 deg F 2. Conduct Safety meeting, inspect location, and review approved/amended Frac 10-403. 3. Ensure all pre-frac well work has been completed and the tubing and IA are freeze protected. 4. Install Tree saver. 5. Pressure test surface lines and tree saver to at least 8,183 psi. 6. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,393 psi. 7. Bring IA pressure up to hold pressure of 3,093 psi. 8. Perform step-down test and data frac if needed. 9. Pump scour stage/HCL if needed to eliminate near well-bore friction. 10. Pump the fracture stimulation per the proposed pump schedule attached below. Maximum allowable treating pressure is 7,183 psi. Estimated 1,993 bbl of fluid, and 156,000# proppant. 11. RDMO frac equipment. Ensure tubing is freeze protected. Proposed Pump Schedule: ťÍČôώϭ >īŪĖî ťÍČô «ĺīŪıô ϼČÍīϽ ŪıŪīÍťĖŽô «ĺīŪıôώϼČÍīϽ Íťô Řĺŕϟ ĺĲèϟώϼŕŕÍϽ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲť ϼϭϽ ͐͒͏ϭώ[ĖĲôÍŘ [ĺÍîϳ͐ϟ͑Ƅ ͖Ϡ͒͏͏͖Ϡ͒͏͏͔ϱ͐͏ ͑͒͏ϭώ³ϱ[ĖĲħ ťôŕώîĺſĲώťôŜť ͕Ϡ͏͏͏͐͒Ϡ͒͏͏͑ϱ͒͏ ēŪťώîĺſĲ ͒ĺĲťĖĲČôĲťώF[ϯèĺŪŘ ͑Ϡ͏͏͏͔͐Ϡ͒͏͏͓͑ ͓͑͏ϭώ[ĖĲôÍŘ iŽôŘώ>īŪŜē ͕Ϡ͏͏͏͑͐Ϡ͒͏͏͑͗ ēŪťîĺſĲ ͔͒͏ϭώ³ϱ[ĖĲħ Íî ͓͐Ϡ͏͏͏͔͒Ϡ͒͏͏͑͗ ͕͒͏ϭώ³ϱ[ĖĲħ ϟ͔ώ͐͑Ϡ͔͏͏͓͖Ϡ͗͏͏͑͗͏ϟ͔͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕Ϡ͔͑͏ ͖͒͏ϭώ³ϱ[ĖĲħ ͐ώ͐Ϡ͔͏͏͓͘Ϡ͒͏͏͑͗͐ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐Ϡ͔͏͏ ͗͒͏ϭώ³ϱ[ĖĲħ ͑ώ͑Ϡ͔͏͏͔͐Ϡ͗͏͏͑͗͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔Ϡ͏͏͏ ͒͘͏ϭώ³ϱ[ĖĲħ ͒ώ͒Ϡ͔͏͏͔͔Ϡ͒͏͏͑͗͒ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͏Ϡ͔͏͏ ͐͏͒͏ϭώ³ϱ[ĖĲħ ͓ώ͓Ϡ͏͏͏͔͘Ϡ͒͏͏͓͑͗ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͐Ϡ͏͏͏ ͐͐͒͏ϭώ³ϱ[ĖĲħ ͔ώ͔Ϡ͓͏͏͕͓Ϡ͖͏͏͔͑͗ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͖͑Ϡ͏͏͏ ͐͑͒͏ϭώ³ϱ[ĖĲħ ͕ώ͔Ϡ͏͏͏͕͘Ϡ͖͏͏ ͑͗ ͕ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͒͏Ϡ͏͏͏ ͐͒͒͏ϭώ³ϱ[ĖĲħ ͖ώ͓Ϡ͏͏͏͖͒Ϡ͖͏͏͖͑͗ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͗Ϡ͏͏͏ ͓͐͒͏ϭώ³ϱ[ĖĲħ ͗ώ͓Ϡ͏͏͏͖͖Ϡ͖͏͏͑͗͗ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͒͑Ϡ͏͏͏ ͔͐͑͏ϭώ[ĖĲôÍŘ >īŪŜē ͕Ϡ͏͏͏͗͒Ϡ͖͏͏͑͗ Estimated Cumulative fluid volume: 83,700 gal (1,993 bbl) Estimated total proppant: 156,250 lbs Anticipated Pressures: MIT-T 4,500 psi MIT-IA 3,572 psi Maximum Anticipated Treating Pressure:5,700 psi IA Pop-off Set Pressure (~95% of MIT-IA):3,393 psi IA Minimum Hold Pressure (Pop-off – 300 psi):3,093 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):7,183 psi w/ 3,093 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6,465 – 6,824 psi N2 POP-off set pressure (MATP):7,183 psi Treating Line Test Pressure (MATP + 1000 psi):8,183 psi OA Pressure:Monitor – Rig up open bleed hose Max Anticipated Proppant Loading:8 PPA Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Slickline – 1. Pull protection sleeve from 2,260’ 2. D&T 3. Install GL design Coiled Tubing – 1. Contingent FCO Portable Testers – 1. Post Frac flowback Attachments – x Current Wellbore Schematic x Frac Pump Schedule x Location Layout x Sundry Revision Change Form Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Current Wellbore Schematic: Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Location Layout: Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Sundry Revision Change Form: Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Approval Rcv’d (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date PBU P1-08A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-199 50-029-22384-01-00 317B ADL 0028297 12444 8764 80 3519 10156 883 2887 9406 20" 10-3/4" 7-5/8" 4-1/2" 3-3/16" x 2-7/8" 8447 42 - 122 41 - 3560 37 - 10193 10017 - 10900 9557 - 12444 3168 42 - 122 41 - 3554 37 - 8742 8728 - 8759 8542 - 8764 Unknown9406, 9818 1490 5210 6890 11390 - 12370 4-1/2" 12.6# L-80 35 - 90888771 - 8762 4-1/2" TIW HBBP Packer 4-1/2" Camco TRCF-4A 9017, 8176 2260, 2256 Bo York Operations Manager Michael Hibbert michael.hibbert@hilcorp.com 907-903-5990 PRUDHOE BAY 7/10/2025 Stump Island Oil Stump Island Oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.05.20 15:42:52 - 08'00' Bo York (1248) 325-314 By Grace Christianson at 9:06 am, May 21, 2025 10-404 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test tubing PRV (global treating PRV) and pump trips prior to treatment. JJL 7/7/25 DSR-6/3/25 7/10/2025 A.Dewhurst 07JUL25 CDW 05/29/2025 'tϬϳͬϬϴͬϮϬϮϱ Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.08 08:57:57 -08'00'07/08/25 RBDMS JSB 070925 Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Well Name:P1-08A Permit to Drill:202-199 Current Status:Producer API Number:50-029-22384-01 Estimated Start Date:7/10/25 Estimated Duration:3days Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Jerry Lau (907) 360-6233 (M) Current Bottom Hole Pressure:4103 psi @ 8,350’ TVDss From downhole gauges 3/10/25 Max Anticipated Surface Pressure:3,168 psi Based on 0.1 psi/ft gas gradient Last SI WHP:1,300 psi 3/10/25 Min ID:3.725” @ 9,066’ MD SWN Nipple Max Angle:49.6 deg @ 9,384’ MD Brief Well Summary: P1-08A has been recompleted to the Stump Island Pool. A fracture stimulation was pumped on this well on 11/22/24. The job screened-out with 27k lbs of proppant placed behind pipe. Objective: Prepare well for fracture stimulation and pressure test. Hydraulically fracture stimulation to improve well productivity to further appraise this Brookian interval. Post-frac slickline work and portable test unit flowback. Current Status: Operable Procedural Steps: Slickline & Fullbore 1. Loadtubing and IA with crude 2. Set TTP 3. Dummy GLVs 4. MIT and MIT-IA to 3500 psi 5. Pull TTP Eline 1. Re-perforate 9,250’-9,260’ Frac 1. Conduct Safety meeting, inspect location, and review approved Frac 10-403. 2. Ensure all pre-frac well work has been completed and the tubing and IA are freeze protected. 3. Install Tree saver. 4. MIRU SLB frac equipment and associated frac tanks. 5. Pressure test surface lines and tree saver to at least 7,206 psi. 6. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,325psi. 7. Bring IA pressure up to hold pressure of 3,025 psi. 8. Perform ball-out perforation breakdown, step-down test and data frac if needed. 9. Pump scour stage/HCL if needed to eliminate near well-bore friction. 10. Pump the fracture stimulation per the proposed pump schedule attached below. Maximum allowable treating pressure is 6,206psi. Estimated 1,940 bbl of fluid, and 152,000# proppant. 11. RDMO frac equipment. Ensure tubing is freeze protected. Previous frac authorized 10/2024 under Sundry 324-608. CDW 05/27/2025 Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Slickline 1. D&T 2. Install GL design Coiled Tubing - Contingent CT FCO if necessary 1. FCO down to ~9400’ MD Portable Testers 1. Post Frac flowback Attachments – Current Wellbore Schematic Frac Pump Schedule Location Layout Sundry Revision Change Form Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Current Wellbore Schematic: Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Location Layout: Reference Log: Stump Island Re-Frac Well: P1-08A PTD: 202-199 API: 50-029-22384-01 Sundry Revision Change Form: Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Approval Rcv’d (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date Date: May 16, 2025 Subject: P1-08A Stump Island SandstoneRe-Fracture Stimulation From: Michael Hibbert C: (907) 903-5990 To: AOGCC Estimated Start Date: 7/10/2025 Attached is Hilcorp’s proposal and supporting documents perform a fracture stimulation on well P1-08A in the Pt Mac Stump Island Oil Pool. P1-08A was recently recompleted from the Point McIntyre pool to the Stump Island Pool. The well was perforated and tested, and resulting diagnostics indicate single digit millidarcy formation permeability with high oil cuts and little to no water production. These diagnostics indicate that the well performance could improve with a hydraulic fracture stimulation. An initial fracture stimulation was pumped on P1-13 as well as P1-08A. The P1-13 frac was successfully placed per plan, but the resultant production was a failure in that skin increased and after pressure transient analysis no fracture was observable in the data. The P1-08A frac was a failure in that the well screened out with only 27k lbs of proppant behind pipe of the planned 210k lbs. The production rates post-frac also confirmed that a productive frac was not placed. The plan being presented is to re-perforate the Stump Island Pool and pump a fracture stimulation to continue to assess the viability of this interval. Hilcorp requests an exception to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling, based on Area Injection Orders. Please direct questions or comments to Michael Hibbert. SECTION 1 - AFFIDAVIT (20 AAC 25. 283, a, 1): Below is an affidavitstating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 1. SIGNED AFFIDAVIT: COPY OF NOTIFICATION SENT VIA EMAIL: SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN 1/2 MILE – SURFACE (20 AAC 25. 283, a, 2, B): List of wells in Plat (20 AAC 25.283, a, 2, B) SECTION 3: EXEMPTION FOR FRESHWATER AQUIFERS (20 AAC 25. 283, a, 3): Well P1-08A is located in the Eastern Operating Area of Prudhoe Bay (AIO 4G, 2015). In 1993 AIO 4 was amended to include the Pt. Mcintyre, Stump Island, and West Beach Oil pools in AIO 4A. Conclusion #10 (Area Injection Order 4A, August 12, 1993, Page 5) states that “No underground sources of drinking water (USDWs) are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field.” Area Injection Order 4G, October 15, 2015, Page 3 states that “All information related to AIO 4, AIO 4A, AIO 413, AIO 4C, AIO 4D, AIO 4E and AIO 4F is hereby incorporated by reference into the record for this order.” Based on the Area Injection Order sections referenced above, Hilcorp requests exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. 413, Hilcorp requests exemption from 20 AAC 25. 283, a, 3- 4 SECTION 4: PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS (20 AAC 25.283.a): There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5: DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25. 283, a, 5): All casing is cemented in accordance with 20 AAC 25.52, b and tested in accordance with 20 AAC 25.030, g when completed. See current wellbore schematic for casing details: SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL(20 AAC 25.283, a, 6): Summary: P1-08 was spudded 7/14/1993. The 13-1/2” hole was drilled to 3,560’ and 10-3/4” casing was ran to 3,560’. The 10-3/4” casing was cemented with 1027 sx (397 bbl) of Permafrost E lead and 350 sx (72 bbl) of Class G tail cement. The plug was bumped. A 250 sx (42bbl) top job was performed. The 9-7/8” hole was drilled to 10,193’ and 7-5/8” casing was ran to 10,193’. The 7-5/8” casing was cemented with 630 sx (135 bbl) of Class G cement. No CBL was logged in the 7-5/8”. Volumetric and lift calculations from data available on the 7-5/8”primary cement job put the TOC at 7,741’ md (7,146’ ssTVD). This is equivalent to a 40% excess factor and accounts for the rathole and shoe tract volumes. The 6” production hole was drilled to 10,900’ and completed with a 4-1/2” slotted liner. P1-08 was sidetracked to P1-08A on 12/21/2002. The rig drilled out of the shoe of the existing 4-1/2” slotted liner to a TD of 12,444’ with the entire lateral in the Kuparuk reservoir. The 3-1/2” x 3-1/4” x 2- 7/8” CTD liner was ran to 12,444’ and cemented with 41bbl of 15.8ppg Class G cement. Full returns were noted throughout the job. A CBL logged on 7/23/2024 logged the TOC behind the CTD liner at 9,751’ md. The CTD liner was cut and pulled to access the Stump Island interval. Top of Stump Island interval is 8,226’ ssTVD. The calculated TOC behind the 7-5/8” casing at 7,149’ ssTVD indicates isolation across the Kuparuk and Stump Island pools and their associated confining intervals. A cement plug was placed above the cut liner from 9557 to 9406’ on 11/15/24. This TOC was witnessed and tagged on 11/16/24 @ 9370’. MIT-T to 2210 psi (witnessed 11/16/24). All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within well design limits. No CBL was logged in the 7-5/8”. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, A, 7): As part of the well preparation pre-frac, the 7-5/8” x 4-1/2” annulus will be tested to 3,500psi and the 4- 1/2” tubing will be tested to 3,500psi. The 7-5/8” x 4-1/2” and the 10-3/4” x 7-5/8” annulus pressures will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. SECTION 8: PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD (20 AAC 25.283, A, 8): Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 10-3/4” Surface Casing 45.5# NT80 5210 2470 7-5/8” Production Casing 29.7# NT95HS 8180 5130 4-1/2” Production Tubing 12.6# L80 8430 7500 Wellhead FMC manufactured wellhead, rated to 5,000 psi. Tubing head adaptor: 11" 5, 000 psi x 4-1/16" 5,000 psi Tubing Spool: 11" 5,000 psi w/ 2-1/16" side outlets Casing Spool: 11" 5,000 psi w/ 2-1/16" side outlets Tree: CIW 4-1/16" 5,000 psi A 10k psi rated Tree-Saver will be used during these fracturing operations.A 10k psi rated Tree-Saver will be used during these fracturing operations. SECTION 9: DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, A, 9): SECTION 10: LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10): Plat of wells within one-half mile of P1-08A wellbore reservoir trajectory and location of faults. Black squares indicate Stump Island pool intersections. The plat shows the location and orientation of each well that transects the confining zone. Hilcorp has formed the opinion, based on the following assessments for each well, seismic, and other subsurface information currently available, that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing and Cement assessments for all wells that transect the confining zone: P1-13 (PTD 193074) Spud date for P1-13 was 5/28/1993. A 13-1/2” hole was drilled and 10-3/4” surface casing was ran to 3570’. The surface casing was cemented with a lead of 2235 cubic ft of Type E Permafrost cement followed by 403 cubic ft Class G tail. The plug bumped and pressured up to 2000psi. A 235 cubic ft sx top job was also performed. A 9-7/8” intermediate hole was drilled and cased with 10275’ of 7-5/8” casing. The casing was cemented with 163.2 bbl of 15.8ppg cement, no losses reported, and the top plug bumped at 472 bbl (reported 4,682 strokes at 0.1008bbl/stroke) versus a calculated volume to float collar of 468 bbl. Accounting for the shoe track and zero rathole puts 159.5 bbl of cement in the annulus (897 cu ft or 159.8bbl reported on the 10-407). A 1.15 excess factor (1.3 times the openhole x casing capacity) places the cement top behind the 7-5/8” casing at 6,649’ md. Using an additionally conservative 2.0 excess factor (2 times the openhole x casing capacity) puts the calculated top of cement at 8,193’ md. Current pick of top of Stump Island Sandstone is 8,797’ md (8,196’ ssTVD). A Cement Bond Log was pulled on April 8, 2024 and logged good cement behind the 7-5/8” from the bottom of the logging interval at 9,050’ up to the 4-1/2” tubing tail at 8,704’ md. This log indicates that the top of cement behind the 7- 5/8” casing is above 8,704’ md (8,123’ ssTVD). This log indicates good cement isolation above and below the Stump Island pool. A 6-3/4” production hole was drilled and the well was completed with a 4-1/2” un-cemented production liner down to 11010’. On 8/20/2015, 108 bbl of Class G cement was circulated in to the 7-5/8” x 4-1/2” annulus to cement off a production casing leak. A subsequent MIT-IA to 2500psi passed. P1-02 (PTD 188005) Formerly Point McIntyre #3 Well was spudded 3/12/1988. The 12-1/4” surface hole was drilled down to 4,496’ and 9-5/8” casing was ran to 4,483’. The 9-5/8” casing was cemented with 2000sx CS II and 400 sx of Class G, with cement returns to surface. The 8-1/2” hole was drilled to 9,416’ and 7” casing was run to 9,407’. The 7” casing was cemented with 444 sx (187 bbl) 12.5 ppg Class G with 12% gel slurry lead and a 290 sx (60 bbl) 15.7 ppg Class G tail. An external casing packer was run as part of the 7” casing with a set depth of 8,933’ – 8,954’. A cement bond log was ran in the 7” casing on 4/6/1988 and the Tail TOC picked from that log is 8,725’ md (8,168’ ssTVD) and the Lead TOC picked at 6,160’ md (5,755’ ssTVD). Top of Stump Island interval is at 8,171’ ssTVD. On 3/22/02, coiled tubing layed in a Class G cement abandonment plug from 9,343’ up to 7,000’ after squeezing 15 bbl behind pipe. The tubing was then cut at 6,530’ and the well was sidetracked to P1- 02A. P1-02A (PTD 202065) P1-02A sidetracked out of the parent well P1-02. The 7” casing was exited in the UG1 at 6,491’ on 3/31/2002 and a 6” hole was drilled to 11,370’ md. The 4-1/2” liner was ran but became stuck, was left from 5,238’ – 10,285’, and was not able to be cemented. A liner top packer was set and pressure tested to 3,000psi. The 4-1/2” shoe tract was drilled out and a 2-7/8” production liner was ran to 11,224’. The 2-7/8” was cemented with 216 sxs (41 bbl) of 15.9 ppg cement. A CBL was ran on 5/8/2002 and logged the TOC behind the 2-7/8” production liner at 10,380’ (8,183’ ssTVD). Top of Stump Island interval is at 8,306’ ssTVD. P1-09 (PTD 196154) P1-09 was spudded on 10/3/1996. A 12-1/4” surface hole was drilled to 5,030’ and 9-5/8” casing was ran to 5,022’. The 9-5/8” casing was cemented with 1,574 sx (615 bbl) of Coldset III lead and 333 sx (70 bbl) of Class G tail cement. The plug was bumped, no losses were reported during the job, and cement was returned to surface. The 8-1/2” hole was drilled to 11,445’ and 7” production casing was ran to 11,134’. The 7” casing was cemented with 275 sx (58 bbl) Class G cement with good returns noted throughout job. The 6” exploration tail was drill down to 13,242’ and a 4-1/2” production liner was ran from 11,034’ – 13,242’. The 4-1/2” production liner was cemented with 472 sx (100 bbl) of Class G cement. The plug was bumped, and the well was reverse circulated off the liner top with no cement returns noted at surface. A CBL was ran on 11/2/1996 from a tag of 11,048’ up to 9,700’ md (8,052’ ssTVD) with cement being logged across the entire interval. This indicates the TOC behind the 4-1/2” liner is above 9,700’ (8,052’ ssTVD). Top of Stump Island interval is 8,310’ ssTVD. PTMCINT-01 (PTD 177046) PTMCINT-01 was spudded on 8/11/1977 as an exploration well. It is currently plugged and abandoned. The 20” conductor was spudded to 85’ and cemented with 200 sx of permafrost cement. A 17-1/2” surface hole was drilled to 2,725’ md and 13-3/8” surface casing was ran to 2,712’ md. The 13-3/8” casing was cemented with 4,500 sx of permafrost cement. Cement was returned to surface. A 12-1/4” intermediate hole was drilled to 12,318’ md and 9-5/8” casing was ran to 12,314’ md. The 9-5/8” intermediate casing was cemented with 1,000 sx of Class G cement with 20 bbl of losses to formation noted. A Cement Bond Log was ran on 9/28/1977 and logged a TOC behind the 9-5/8” at 11,302’ md (9,153’ ssTVD). The 8-1/2” production hole was drilled to 13,440’ md. Formation evaluation logs were ran, then a 50 sx Class G cement plug was placed from 13,307’ up to 13,182’ to isolate the wellbore from the Sag River/Sadlerchit. A second cement plug was placed across the 9-5/8” shoe from 12,417’ up to 12,217’ with 81 sx Class G cement. Then the 9-5/8” casing was punched from 10,333’ – 10,337’, a retainer was set at 10,216’ (8,421’ ssTVD), and a 300 sx squeeze was performed with Class G cement. The rig attempted to cut a window in the 9-5/8” casing from 10,110’ – 10,140’ before the objective changed and the window was plugged back with a 36 sx Class G cement plug from 10,140’ up to 10,080’ (8,365’ – 8,320’ ssTVD). The 9-5/8” was cut and pulled from 2,850’, then a final 245 sx Class G cement plug was placed inside the 13-3/8” casing from 2,860’ up to 2,650’ (2,831’ – 2,621’ ssTVD). Top of Stump Island interval is 8,301’ ssTVD. PTMCINT-01 was called P&A’d on 10/7/1977 and immediately sidetracked to PTMCINT-02 (PTD 177065) below the existing 13-3/8” surface casing shoe. PTMCINT-02 penetrates the Stump Island pool outside of the 1/2 mile radius of P1-08A. P1-17 (PTD 193051) P1-17 was spudded 4/3/1993. A 13-1/2” hole was drilled to 3,860’ md and 10-3/4” surface casing was ran to 3,860’. The 10-3/4” casing was cemented with 2,385 sx (425 bbl) of Permafrost E cement lead followed by 350 sx (72 bbl) Class G tail. Full returns were noted throughout the primary cement job, and the plug bumped. A top job was performed with 250 sx Permafrost C cement. The 9-7/8” production hole was drilled to 10,532’ md and 7-5/8” production casing was ran to 10,532’. The 7-5/8” casing was cemented with 530 sx (120 bbl) Class G cement. Full returns were noted, and the plug bumped. A Cement Bond Log was ran 5/13/1993 and logged from 10,413’ md up to the tubing tail at 9,488’. Cement was logged across the entire interval, which puts the TOC behind the 7-5/8” casing above 9,488’ md (8,155’ ssTVD). Top of Stump Island interval is at 8,248’ ssTVD. P1-18A (202076) The parent well P1-18 (PTD 199116 – also known a NV-18) was drilled to test the Nuvuk formation. The well was spudded on 12/6/1999. A 12-1/4” hole was drilled to 4,625’ and 9-5/8” surface casing was ran to 4,609’. The 9-5/8” casing was cemented in two stages with the first stage being 189 sx (150 bbl) 10.7 ppg ArcticSet Lite III lead followed by a 219 sx (46 bbl) Class G tail. The plug was bumped, an ES cementer was opened and 375 bbl of 10.7ppg ArcticSet Lite III cement was pumped. “Clabbered” returns were noted at surface, and the plug was bumped. The 8-3/4” exploration hole was drilled to 11,187’. After exploration data was collected, P&A operations began on the 8-3/4” open hole. The first P&A cement plug was placed across the Ivishak and Sag from TD up to 10,877’ with 26 bbl of Class G. The second P&A cement plug was placed across the Kuparuk and Stump Island in two stages from 10,487’ up to 9,913’ with 48 bbl of Class G, and from 9,913’ up to 9,320’ with another 48 bbl of Class G. Then a 9-5/8” EZSV was set at 4,543’ and 13bbl of Class G cement were squeezed through the retainer and 4 bbl of Class G were layed in on top. The rig was released on 1/4/2000. P1-18 (NV-18) does not penetrate the Stump Island within a 1/2 mile radius of P1-08A). P1-18A exited the 9-5/8” casing from the parent well with the window from 4,491’ – 4,507’ md. The 8- 3/4” production hole was drilled to 10,641’ and 7” production casing was ran to 10,623’ md. The 7” production casing was cemented with 190 sx (110 bbl) of 11.2 ppg lead followed by 205 sx (42 bbl) 15.8 ppg tail. The plug was bumped and returns while cementing were noted at 90%. A Cement Bond Log was ran on 5/16/2002. Cement was present across the entire logging interval from 10,520’ md up to the tubing tail at 9,788’ md (8,632’ ssTVD). This log indicates that the TOC behind the 7” production casing is above 8,632’ ssTVD. Volumetric and lift calculations from data available on the 7” primary cement job put the TOC at 7,505’ md (6,706’ ssTVD). This is equivalent to a 60% excess factor and accounts for the rathole and shoe tract volumes and factors in the 90% return rate. Top of Stump Island interval is 8,285’ ssTVD. SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES (20AAC 25.283, A, 11): Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 2 mapped faults that transect the Stump Island interval and enter the confining zone within the 1/2 mile radius of the production and confining zone trajectory for P1-08A. Fracture gradients within the confining zone (Top Stump Island Shale and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. Faults 1and 2 intersect the production interval and confining zone within the 1/2 mile radius of the planned frac. Their displacements, sense of throw, and zone in which they terminate upwards are given below. Fault 1 Fault 2 Maximum stress direction is estimated to be North – South plus or minus 15 degrees based data from the P1-02 FMS log from 30-MAR-1988. The planned frac half-length of 285’ should not reach any of the mapped faults. Fault 1 is the closest to P1-08A, at 880’ away. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12): Fracture Stimulation Pump Schedule Estimated Cumulative fluid volume: 81,450 gal (1,940 bbl) Estimated total proppant: 152,000 # Table 5 – Anticipated Pressures MIT-T 3500 psi MIT-IA 3500 psi Maximum Anticipated Treating Pressure: 4500 psi IA Pop-off Set Pressure (~95% of MIT-IA): 3325 psi IA Minimum Hold Pressure (Pop-off – 300 psi): 3025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1): 6206 psi w/ 3025 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP: 5585-5896 psi Global Kickout (95% of MATP): 5896 psi N2 POP-off set pressure (MATP): 6206 psi Treating Line Test Pressure (MATP + 1000 psi): 7206 psi OA Pressure: Monitor – Rigup bleed hose and/or PRV Max Anticipated Proppant Loading: 8 PPA There are three overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. The OA will have a bleed hose and/or a PRV to handle any potential communication to the OA. Frac Modelling: Maximum Anticipated Treating Pressure: ~4,500 psi Surface pressure is calculated based on a conservative closure pressure of ~0.70 psi/ ft or ~5,845 psi. Net pressure estimated to be built (600 psi). Total friction pressure estimated at1,200 psi between pipe friction and perforation friction. Hydrostatic pressure of the pad fluid is estimated at3,690 psi (8.5ppg). 5845psi (closure)+ 600psi (net)+ 1200psi (friction) - 3690psi (hydrostatic) = 3955psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average topconfining layer stress is anticipated to be 0.71 psi/ ft and average bottom confining layer stress is anticipated to be 0.70 psi/ft. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~285ft with a height of ~179ft TVD. The Kuparuk interval below the Stump Island in P1-08A has a high gas-oil ratio making production marginal. The fracture stimulation was designed to reduce the likelihood of inducing a fracture that will penetrate through the lower confining interval to avoid linking up to the high gas-oil ratio Kuparuk production. Disclaimer Notice: This model was generated by a third party using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. Pre-Job Anticipated Chemicals to be pumped: SECTION 13: POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN (20 AAC 25.283, A, 13): After the fracture stimulation and potentially during the post frac coiled tubing fill cleanout, the well will be put on production through a portable well test unit. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if proppant production is above the acceptable threshold. The initial flowback period is intended to produce back the treating fluid volume to tanks as quickly as possible. When production is less than 20% water cut and less than 0.5% solids the flowback will be routed to the LPC production facility. There will be a flowback tank farm on pad to store any produced fluids from flowback operations that do not meet the LPC facility specifications mentioned above. The fluids and proppantnot suitable for LPC processing will be hauled to GNI for disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 July 7, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. ADD 07JUL25 (a)(2) Plat Provided with application. ADD 07JUL25 (a)(2)(A) Well location Provided with application. P1-08A lies in Sections 16 and 15 of T12N, R14E, UM. ADD 07JUL25 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online October 24, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of P1-08A. There are no subsurface water rights or temporary subsurface water rights within 11-1/2 miles of the surface location of P1-08A. SFD 10/24/2024 ADD 07JUL25 (a)(2)(C) Identify all well types within ½ mile List of wells provided with application. ADD 07JUL25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. Absence of freshwater aquifers is supported by AIO 4A Finding 17 (salinity of 12,000 to 20,000 ppm for all aquifers in the Pt. McIntyre oil field) and AIO 4A Conclusion 10 (no USDWs are known to exist in the PBU Eastern Operating Area and Pt. McIntyre oil field). The Affected Area of AIO 4A includes P1-08A and P1-08. A review of nearby well Pt. McIntyre 3 (PTD 188-005), which is the closest well with shallow porosity data that lies within ½ mile of P1-08A, shows all sands between the base of permafrost and surface casing shoe are very low in resistivity, clearly indicating brackish formation water. AOGCC’s quick-look analysis using Pickett Plots demonstrates that these sands all contain formation waters that exceed 10,000 mg/l TDS. SFD 10/28/2024 ADD 07JUL25 (a)(4) Baseline water sampling plan None required. ADD 07JUL25 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 July 7, 2025 (a)(5) Casing and cementing information Provided with application. Schematic provided. CDW 05/28/2025 (a)(6) Casing and cementing operation assessment 10-3/4” casing cemented required a 42 bbl top job. 7-5/8” was cemented without CBL – volumetric cement data indicates TOC of 7741 ft with 40% excess. 4.5” slotted liner run to 10900 ft MD. The P1-08A well sidetracked from the existing 4.5” liner shoe. 3.5x3.25x2.875” liner cemented with full returns. CBL run showed TOC behind liner at 9751 ft MD. CDW 05/28/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 10/24/2024 ADD 07JUL25 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing was set at 3560’ MD (-3,558’ TVD) and cemented. 42 bbl top job performed. For the original well P1-08, 9-7/8” hole was drilled from the base of surface casing set at 3560’ MD (-3560’ TVD) to total depth of 10,193’ MD (-8,693’ TVD). The mud log indicates good-quality oil shows were encountered in P1-08 below 9,150’ MD (-8,225’ TVDSS) and the top of the Stump sand is at 9,167’ MD (-8,238’ TVDSS). The 7-5/8” casing shoe was set at 10,193’ MD (8,693’ TVDSS) and cemented with 135 barrels of Class G 15.8 ppg. Assuming 40% washout, the estimated top of cement is about 7,740’ MD (-7,145’ TVDSS). P1-08A was drilled out through the bottom of P1-08 and continued horizontally within the Kuparuk reservoir. So, the original cement surrounding the 7-5/8” casing isolates the Stump and Kuparuk hydrocarbon-bearing zones. SFD 10/25/2024 ADD 07JUL25 CDW 5/29/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 July 7, 2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3500 psi MITIA planned, 3500 psi MITT plan. CDW 05/28/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi tree saver max. frac. Pressure 6206 psi. Pump knock out 5585-5896 and GORV 6206 psi., lines test 7206 psi. CDW 05/28/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Colville mudstones, shales, and siltstones that have an aggregate thickness of about 1,330’ true vertical thickness (TVT) underlain by the Stump Island siltstone and shale that is 11’ TVT. Fracture gradients are about 0.70 to 0.71 psi/ft (~13.5 ppg EMW). Fracturing Zone: Stump Island consisting of very fine- grained sandstone and siltstone is cemented. Fracture gradient expected to range from about 0.66 psi/ft (12.7 ppg EMW). Lower confining zones: HRZ Shale with an aggregate TVT of over 64’. Fracture gradient expected to range from about 0.70 psi/ft (13.5 ppg EMW). SFD 10/25/2024 ADD 07JUL25 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. Hilcorp has identified (and platted) 37 wells (including sidetracks) and identified 7 wells that transect the confining zone within ½ mile of P1-08A. For these 7 wells, Hilcorp has provided cementing review including TOC (CBL log) and zonal isolation – with only PTMCINT-01 (Now P&A) without zonal isolation. Six wells within the AOR all display cement isolation of the Stump interval. For the seventh well, Pt McIntyre 1, the CDW 5/29/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 July 7, 2025 Ivishak, Shublik, Sag River, and Kuparuk are isolated by cement. In this well, the Stump Island interval is hydrocarbon-bearing (fair-quality mud log oil show), but the interval is likely not entirely covered by cement. However, the Stump intercept in Pt McIntyre 1 is located about 2,000' north of the intercept in P1-08A. Due to that separation it is highly unlikely that Pt McIntyre-01 will interfere with frac fluids in P1-08A. SFD 10/26/2024 ADD 07JUL25 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Two faults: The operator has identified two faults using seismic and well data within a ½-mile radius of P1-08A. This fault does not intersect P1-08 or Pl-08A, and it lies approximately 900’ from the proposed fracturing interval, and the modeled half-length of the induced fracture is 285’. It is unlikely that this fault will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 10/25/2024 ADD 07JUL25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/28/2025 (a)(12)(A) Estimated volume Provided with application. 1940 bbl total dirty vol. 152K lb total proppant CDW 05/28/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/28/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. SLB disclosure provided. CDW 05/28/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 05/28/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 July 7, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 4500 psi. Max. 6206 psi allowable treating pressure. Max pressure is 5585-5896psi pump trips and GORV 6206 psi. With 3025 psi back pressure IA (IA popoff set 3325 psi), max tubing differential should be 2881 psi. CDW 05/28/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 285’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 180’ (top TVD of about 8,255’ and base TVD of about 8,435), so induced fractures may penetrate a short distance into the overlying confining Colville confining layer that is about 1,300’ thick in this area. It may also penetrate into, but not through, the underlying HRZ shale that provides lower confinement. SFD 10/25/2024 ADD 07JUL25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. GNI disposal identified CDW 05/28/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3025 psi back pressure, plan to test to 3500 psi, popoff set as 3325 psi CDW 05/28/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 10-3/4” casing cemented required a 42 bbl top job. 7-5/8” was cemented without CBL – volumetric cement data indicates TOC of 7741 ft with 40% excess. 4.5” slotted liner run to 10900 ft MD. The P1-08A well sidetracked from the existing 4.5” liner shoe. 3.5x3.25x2.875” liner cemented with full returns. CBL run showed TOC behind liner at 9751 ft MD. Liner to 7-5/8” sealed with packer at 9017 ft, 1276 ft below calc. TOC. CDW 05/28/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 325-314) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 July 7, 2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3500 psi. Max pressure differential is estimated as 1475 psi (4500 with 3025 psi backpressure) so test of 3500 psi satisfies 110% CDW 05/28/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 7206 psi line pressure test, pump knock out 5585-5896 psi with max. global kickout 6206 psi. IA PRV set as 3325 psi. CDW 05/28/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/28/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3325 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/28/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 05/28/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). ADD 07JUL25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. ADD 07JUL25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU P1-08A Extended Perforating, Pull Liner Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-199 50-029-22384-01-00 12444 Conductor Surface Intermediate Production Liner 8764 80 3519 10156 2887 9406 20" 10-3/4" 7-5/8" 3-1/2" x 3-3/16" x 2-7/8" 8447 42 - 122 41 - 3560 37 - 10193 9557- 12444 42 - 122 41 - 3554 37 - 8743 8542 - 8764 unknown 470 2480 5120 11160 9406 , 9818 1490 5210 8180 10570 9250 - 12370 4-1/2" 12.6# L-80 35 - 9088 8434 - 8762 Structural 4-1/2" TIW HBBP , 9017 , 8176 4-1/2" TRCF-4A , 2260 , 2256 9017 8176 Bo York Operations Manager Michael Hibbert Michael.Hibbert@hilcorp.com (907) 903-5990 PRUDHOE BAY / PT MCINTYRE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028297 35 - 8229 0 115 0 3500 0 70 0 1446 0 634 324-608 13b. Pools active after work:PM STUMP ISL OIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.03.10 17:02:37 - 08'00' Bo York (1248) By Grace Christianson at 11:14 am, Mar 11, 2025 CDW 03/11/2025 DSR-3/24/25 RBDMS JSB 060325 ACTIVITYDATE SUMMARY 11/4/2024 ***WELL FLOWING ON ARRIVAL***(fracturing) B&LOAD TUBING W/ 4 1/2" BRUSH, 3.50" GAUGE RING TO DEPLOYMENT SLEEVE @ 9,018' SLM (212bbls water pumped) SET 4 1/2" PX-PLUG W/ BAITED PRONG (used for catcher) IN SLIDING SLEEVE @ 8,946' MD (500psi pt) PULLED BK-S/O FROM STA #1 @ 4,152' MD SET BEK-FLOW SLEEVE IN STA #1 @ 4,152' MD ***CONT WSR ON 11/5/24*** 11/4/2024 T/I/O = 2550/1750/0 TFS Unit 1 (Assist S-Line Circ-out) Pumped 6 bbls 60/40 down P1-08 FL for FP. Load TBG with 2 bbl 60/40 spear & 212 bbls KCL followed by 2 bbl 60/40 tail. Pumped an additional 14 BBLS 60/40 to Assist Slickline downhole. ***JOB CONTINUES to 11-5-2024*** 11/5/2024 ***CONT WSR FROM 11/4/24*** (fracturing) RD HES 759 SLICKLINE UNIT DUE TO INCOMING WEATHER ***T-BIRD LEFT IN CONTROL OF WELL UPON DEPARTURE, PAD OP NOTIFED OF WELL STATUS*** 11/5/2024 ***JOB CONTINUES from 11-4-2024*** TFS Unit 1 Assist Slickline Pumped 10 BBLS 60/40 and 215 BBLS of 2% KCL to Circ P1-08 TBG and IA to P1-07 Flowline. Followed by 84 BBLS of Diesel to Freeze Protect Tubing and IA to 2000 ft. Lined up for a U-Tube after One Hour Shut in the Well. Well shut in upon TFS departure, DSO notified FINAL WHPS = 750/750/0 11/8/2024 ***WELL S/I ON ARRIVAL***(fracturing) HELD WELL CONTROL/MAN DOWN DRILL W/ CREW. PULLED BEK-FLOWSLEEVE FROM ST#1 @ 4,152' MD. SET BK-DGLV IN ST#1 @ 4,152' MD. PERFORMED PRESSURE TEST ON IA TO 1500psi.(see log) PULLED 4 1/2" BAITED PX-PLUG FROM 8,946' MD DRIFTED TO DEVIATION W/ 2.69" BARBELL, 1.75" S.BAILER TO 9,926' SLM ***WELL LEFT S/I UPON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS*** 11/10/2024 *** WELL S/I ON ARRIVAL*** OBJECTIVE: SET PLUG IN INTERVAL MIRU YELLOW JACKET E-LINE. PT PCE 300 PSI LOW./3000 PSI HIGH RIH W/CH/1.69'' GUN GAMMA/MSST AND NS 2.50" OD PLUG CORRELATED TO AK E-LINE CBL LOG DATED 23-JULY-2024 SET NS 2.50 CIBP @ 9818' MD JOB CONTIUE 11-11-2024 ***WELL S/I ON DEPARTURE*** 11/10/2024 T/I/O 0/100/0 (TFS unit 1 assist E-Line) Pumped 234 BBLS of brine down TBG for load. Pumped 15 BBLS of 60/40 down TBG for FP. Pumped 5 BBLS meth pill down TBG. Pumped a further 12.6 bbls of Neat meth down the TBG to Fluid pack. Well secured. Final WHPS=0/0/0 Daily Report of Well Operations PBU P1-08A Daily Report of Well Operations PBU P1-08A 11/11/2024 ***JOB CONTINUED FROM 11/10/2024 WELL S/I ON ARRIVAL*** OBJECTIVE: PERFORATE INTERVAL W/1-11/16" TUBING PUNCH, WELTEC CUT PT PCE 300 PSI LOW./3000 PSI HIGH RIH W/CH/1.69'' GUN GAMMA/5' OF 1-11/16'' TUBING PUNCH GUN 4 spf 0 DEG PHASE TO PERFORATE INTERVAL 9708'-9713' CCL TO TOP SHOT=12.6 ' CCL STOP DEPTH=9695.4' GAMMA RAY LOG CORRELATED TO AK E-LINE CBL LOG DATED 23-JULY-2024 RIH W/CH/1.69"/2.3" WELLTEC MECHANICAL CUTTER, CCL TO ANC 7.8' CCL TO CUTTERS 18' CUT TUBING @ 9557' TATTLE TALE READ 3.38 JOB COMPLETE ***WELL S/I ON DEPARTURE*** PERFORMED A MAN DOWN WITH WELLSITE LEADER AND CREW. 11/12/2024 CTU#2 - 2" Tapered. Job Scope: Pull Cut CTD Lnr / Lay in Cement Plug MIRU CTU. Test H2S/LEL system, Pass. Test safety joint. Pass. MU YJ fishing assembly. ***Job continued 11/13/24*** 11/13/2024 CTU#2 - 2" Tapered. Job Scope: Pull Cut CTD Lnr / Lay in Cement Plug Continue in hole with YJ fishing assembly. Tag the deployment sleeve at 9023' CTM / 9057' MD. Latched up and pulled liner free on the first attempt.Pull to surface pumping displacement with 8.6 brine. Lay down 3-1/2" & 3-3/16" liner. RIH with slim LRS 2" BDJSN. Tag 3-3/16" CIBP at ~ 9821' CTM / 9818' MD. Circulate the well to diesel. Rig-up HES cementers. Lose the C-pump on the LRS tractor. Call out mechanics. ***Job in Progress*** 11/14/2024 CTU #2 - 2" Tapered String. Job Scope: Pull Cut CTD LNR / Lay in Cement Plug. Swap out LRS C-pump. RIH and lay in 11.2 bbls of 15.8 ppg class G cement from 9818' to 9357'. Pick up to safety, perform 2200 psi squeeze. RIH and reverse out down to 9350', POOH while reverse circulating. Pump two 20 bbl gel sweeps while at surface through the coil at max rate. Freeze protect the coil with diesel. WOC to reach ~ 500 psi compressive strength. RIH with 2" BDJSN to tag. ***Job in Progress*** 11/15/2024 LRS CTU #2 - 2" Tapered String. Job Scope: Pull Cut CTD LNR / Lay in Cement Plug Tag TOC at ~ 9491' E / 9537' M (target TOC ~ 9457'). Call out HES cementers. Laid in 7 bbls of 15.8ppg class "G" cement from 9465' up to 9,300' and cleaned out down to 9,350'. Left top of cement at 9,350'. POOH while reversing out. Well full of diesel down to 9,300'. Pump 40 bbl gel sweep through coil, Freeze protected with diesel. POP off well the well and perform weekly BOP test. ***Job in Progress*** Daily Report of Well Operations PBU P1-08A 11/16/2024 LRS CTU #2 - 2" Tapered String. Job Scope: Pull Cut CTD LNR / Lay in Cement Plug Make up 2-1/8" NS MHA with HES GR/CCL logging toolstring in 2.20" carrier with 3.60" DJN. RIH and tag TOC at ~ 9370' CTM. Perform pre-AOGCC MIT-T to ~ 2250 psi (pass). Perform AOGCC MIT-T (witnessed by Guy Cook) to 2210 psi (pass) and re-tag TOC at ~ 9370' CTM. Log from tag up to 8,000' at 50 FPM. Paint a tie-in flag at 9200'. POOH and confirm good data (+30' correction, corr. TOC ~9406' MD). Perform MIT-T to 3105 psi (pass) and MIT-IA to 3239 psi (pass). RIH with 3-1/8" HES, 6 SPF, 60 degree gun and perforate 9250' - 9260'. Good indication of shot. POOH and lay down spent gun. Rig-up HES N2 truck and blow the 2" coil down with N2. RDMO and head to the yard to swap pipe. Turn the well over to slickline. ***Job Complete*** 11/16/2024 ***WELL S/I ON ARRIVAL*** STBY ON COIL ***CONTINUE 11/17/24*** 11/17/2024 ***CONTINUE FROM 11/16/24*** RAN 3.84" NO-GO CENT. 2' STEM, 4-1/2" BLB S/D @ 2,260' MD SET 4-1/2 DB-FRAC ISO-SLEEVE (2.25" I.D. 80" LIH) @ 2,260' MD ***WELL LEFT S/I*** 11/18/2024 T/I/O = 1730/180/10. Temp = SI. Bleed TP to 0 psi (OE). AL disconnected. Integral installed on IA. T FL @ surface. Bled TP to FB to 0+ psi in 2 min. IAP decreased 130 psi. Monitored for 30 min. TP increased 47 psi in the 1st 15 min & 19 psi in the 2nd 15 min for a total increase of 66 psi in 30 min. Final WHPs = 66/50/10. SV, WV, SSV = C. MV = O. IA, OA = OTG. 02:30 11/18/2024 Heating upright on Price Pad for P1-08 Frac. Heated 195 BBLS Seawater to 120*. Start Temp 78*. Finish Temp. 120*. 11/19/2024 T/I/O=150/60/13 Injectivity Test ( Pre Frac ) Pressure up IA to 2100 psi with 2 bbls diesel. Pump 150 bbls crude down Tbg at max rate up to 4200 psi max--See log for details FWHPs=1500/500/13 11/21/2024 Heated Vac Truck ( 9.8 Brine ) to 120* ***Job continued for 11/22/2024*** 11/22/2024 Assist w/ Frac (FRACTURING) Pumped 15 bbls 70* DSL down Tbg after frac screened out and flowed back. 2nd Hot Oil Pump Truck maintaining backside pressure w/ DSL. ***Job Cont to 11-23-24 WSR** 11/22/2024 ***Job continued from 11/21/2024*** ( FRACTURING ) Assist Frac. Heated Diesel Tanker to 80*. Pumped 3 bbls diesel to reach max pressure and maintain it. *** Job Continued 11-23-24 *** Daily Report of Well Operations PBU P1-08A 11/22/2024 MIRU HES Frac, Oil States Tree Saver, LRS backside pump. Pressure test treating lines and tree saver to 7460 psi. Function test pressure safety systems. LRS pressure up IA to 2,600 psi. Load well with 230 bbl 20# linear gel at 20 bpm. Pump Mini-frac at 35 bpm with 360 bbl 35# XL, flush with 148 bbl 20# linear gel & 10gpt BA-20. FG: 0.73 psi/ft. Pump 6400# 100 mesh scour stage at 10 bpm ramping from 0.5 -1.0 ppg with 47bbl pad and 169 bbl 20# linear gel at 10 bpm. Flush with 182 bbl 20# linear gel at 10 bpm. Shut in let sand settle 1hr. Pump frac at 32 bpm, max pressure 5,512 psi: Pad, 928 bbl 35# XL pad. 2.0 ppg 20/40 CarboLite, 180 bbl 35# XL. 4.0 ppg 20/40 CarboLite, 253 bbl 35# XL. 5.0 ppg 20/40 CarboLite, 38 bbl 35# XL. Screened out with 4 ppg at perfs. Hand well over to LRS for Freeze protect. 52k# 20/40 pumped, estimated 27k# 20/40 and 6,400# 100 mesh placed in formation. Estimated 25k# 20/40 left in wellbore. 1700 bbl 35# Hybor G XL, 775 bbl 20# linear gel pumped. ***Job Complete*** 11/23/2024 ***Job Cont form 11-22-24 WSR*** Assist Frac (FRACTURING) Pumped 15 bbls (30 bbls total) 70* DSL down Tbg for FP after Frac screen out. Other pump unit monitoring IA pressure for 1 hour after bleeding IA to 0 psi. **FP tag hung on MV 11/23/2024 *** Job Continued from 11-22-24 *** ( FRACTURING ) Assit Frac. Pumped 0.21 bbls diesel to hold pressure on IA. Final IA Psi- 0 psi Secure RD. 11/24/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Post Frac FCO Travel from Milne Point to P1-08. Spot in and rig up. Make up slim LRS FCO BHA with 1.75" BDJSN. Flow back ~ 35 BBL's of diesel and then start getting thick frac gel back. Swap the coil and well to KCL at 1500' and start cleaning out. ***Job in Progress*** 11/25/2024 LRS CTU #2, 1.75" Blue Coil. Job Objective: Post Frac FCO Dry drift from 1500' to 2500'. Pick back up, jet down through, and pump a bottoms up. Dry drift from 2500' to 5000'. Pump a bottoms up and start getting a lot of solids back through the choke without cleaning up. Pump 10 BBL gel pills at 3000' and 4500'. Dry drift down and tag top of proppant at ~ 8714' CTM. Reverse clean out down to cement (9381' CTM / 9406' MD). Get clean gel sweep from bottom and 1 more as we POOH. Freeze protect well with 38 BBL's of diesel. Pump 10 BBL clean gel sweep forward when at surface at maximum rate. FP CT w/60/40. RDMO ***Job Complete*** 11/25/2024 ***WELL S/I ON ARRIVAL*** RIG UP POLLARD UNIT 61 ***WSR CONT. ON 11-26-2024*** Daily Report of Well Operations PBU P1-08A 11/26/2024 ***WSR CONT. FROM 11-25-2024*** RAN 3.80'' G. RING TO FRAC SLEEVE @ 2260' MD PULLED 4-1/2'' DB-FRAC ISO SLEEVE @ 2260' MD RAN KJ, 4-1/2" BRUSH, 3.80" G-RING, TAG TOC/TOL @ 9378' SLM SET 4-1/2" X-CATCHER IN SWS NIP @ 9049' MD PULLED BK-DGLV FROM ST #2 @ 8883' MD PULLED BK-DGLV FROM ST #1 @ 4152' MD SET BK-LGLV IN ST #1 @ 4152' MD SET BK-OGLV IN ST #2 @ 8883' MD PULLED 4-1/2'' X-CATCHER @ 9049' MD ***WELL LEFT S/I ON DEPARTURE*** 12/6/2024 LRS Test Unit 6, Begin WSR on12/06/24 Post Frac Flowback, IL- P1-08, OL- P1-07, Unit Move, Begin, standby Continue WSR on 12/7/24 12/7/2024 LRS Test Unit 6, Continue WSR from12/06/24 Post Frac Flowback, IL- P1-08, OL- P1-07, Unit Move, Begin, standby Continue WSR on 12/8/24 12/8/2024 LRS Test Unit 6, Continue WSR from12/7/24 Post Frac Flowback, IL- P1-08, OL- P1- 07, Unit Move, Begin, standby Continue WSR on 12/9/24 12/9/2024 LRS Test Unit 6, Continue WSR from12/8/24 Post Frac Flowback, IL- P1-08, OL- P1- 07, Unit Move, Begin, standby Continue WSR on 12/10/24 12/10/2024 ***WELL FLOWING TO LRS TEST UNIT ON ARRIVEL*** R/U POL-61 ***WSR CONT ON 12-11-24*** 12/10/2024 LRS Test Unit 6, Continue WSR from12/9/24 Post Frac Flowback, IL- P1-08, OL- P1- 07, Unit Move, Begin, standby Continue WSR on 12/11/24 12/11/2024 T/I/OA= 2000/550/0 TFS Unit 4 ****P1-07**** Freeze Protect F-Line. Pump 7 bbls of 60/40 down P1-07 outlet well F-Line for Well Testers. Radio DSO to shut Inlet. Pressure up to 1500 psi. Tags and flagging hung on W.V. 12/11/2024 LRS Test Unit 6, Continue WSR from12/10/24 Post Frac Flowback, IL- P1-08, OL- P1-07, Unit Move, Begin, standby Continue WSR on 12/12/24 12/11/2024 ***WSR CONT FROM 12-10-24*** RAN 2'' x10' DMY GUN w/TEL & S-BAILER, UNABLE TO GET PAST 3730'SLM (lift forces & slugging 2.2-1.1mm) S/I WELL RAN 2"X10' DMY GUN W/ TEL & S-BAILER, LOC TT @ 9088'MD, TAG TD @ 9418'MD ***WELL LEFT S/I ON DEPARTURE*** (LRS TEST UNIT IN CONTROL OF WELL) 12/23/2024 ***WELL S/I ON ARRIVAL*** RAN 2' x 1-7/8" STEM, 3.80" CENT, 4-1/2" BRUSH, 3.69" G-RING, XN MILLED OUT IN 2002 NOT ON SCHEMATIC, BRUSHED SWS NIP @ 9049' MD (no issues) SET 3.81'' X LOCK w/GAUGES IN NIP @ 9049' MD RAN 4-1/2'' CHECK SET TO X LOCK @ 9049' MD (Good) ***WELL LEFT S/I ON DEPARTURE*** Daily Report of Well Operations PBU P1-08A 1/25/2025 ***WELL S/I ON ARRIVAL*** (Fracturing) PULLED 4-1/2" FLOW THRU SUB W/ DUAL SPARTEK GAUGES IN SWS-NIP @ 9,049' MD SET 4-1/2" FLOW THRU SUB W/ DUAL SPARTEK GAUGES IN SWS-NIP @ 9,049' MD ***WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF STATUS*** 2/6/2025 (Assist well testers with FL Freeze Protect) Pumped 6 bbls of 60/40 down the FL for FP. Pressured FL to 1500 psi upon completion. 2/6/2025 LRS Well Testing Unit #2. Begin WSR on 02/06/25. Well Test. IL PM1-08, OL P1-13. Begin RU. Pressure Test. BD, Pull and inspect IL CK. Continue WSR on 02/07/25. 2/7/2025 LRS Well Testing Unit #2. Continue WSR from 02/06/25. Well Test. IL PM1-08, OL PM1-13. RU and PT. Pop to back of unit, Leak on IL CK. BD, pull and inspect Choke. Continue WSR on 02/08/25. 2/8/2025 LRS Well Testing Unit #2. Continue WSR from 02/07/25. Well Test. IL PM1-08, OL PM1-13. Continue to Stabalize Well. Continue WSR on 02/09/25. 2/9/2025 LRS Well Testing Unit #2. Continue WSR from 02/08/25. Well Test. IL PM1-08, OL PM1-13. Continue to Stabalize Well. Continue WSR on 02/10/25. 2/10/2025 LRS Well Test Unit #2. Continue WSR from 02/9/25. Well Test. IL PM1-08, OL PM1- 13. Continue to Stabalize Well. BD, depressure, RD. Unit move to LRS yard. Begin unit maintenance from Flowback. End WSR on 02/11/25. 2/10/2025 TFS U4, (Freeze protect flowline for well testers) Testers flowing P1-13 to P1-08, Freeze protect flowline of P1-13, pumped 7 bbls neat down P1-13 flowline for freeze protect, did not pressure up flowline per DSO, testers and DSO notified of departure, ***wells left in LRS testers control*** Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 11/22/2024 Job End Date: 11/22/2024 State: Alaska County: Beechey Point API Number: 50-029-22384-01-00 Operator Name: Hilcorp Alaska, LLC Well Name and Number: P1 08A Latitude: 70.390361 Longitude: -148.587952 Datum: NAD83 Federal Well: NO Indian Well: NO True Vertical Depth: 9069 Total Base Water Volume (gal)*: 103930 Total Base Non Water Volume: 0 Water Source Percent Surface Water, > 1000TDS 100.00% Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments BA-20 BUFFERING AGENT Halliburton Buffer BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CARBOPROP 20/40 Carbo Ceramics Proppant CL-28M CROSSLINKER Halliburton Crosslinker CLA-WEB(TM) Halliburton Clay Stabilizer LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-III DELAYED RELEASE BREAKER Halliburton Breaker Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant SEAWATER Operator Base Fluid WG-36 GELLING AGENT Halliburton Gelling Agent Items above are Trade Names. Items below are the individual ingredients. Water 7732-18-5 100.00000 92.91929 None Sodium chloride 7647-14-5 5.00000 4.64596 None Ceramic materials and wares, chemicals 66402-68-4 100.00000 2.55301 None Crystalline silica, quartz 14808-60-7 100.00000 0.69102 None Guar gum 9000-30-0 100.00000 0.37220 None Water 7732-18-5 100.00000 0.25511 None Borate salts Proprietary 60.00000 0.06471 None Ammonium salt Proprietary 60.00000 0.04960 None Ethanol 64-17-5 60.00000 0.04644 None Ammonium acetate 631-61-8 100.00000 0.04433 None Sodium hydroxide 1310-73-2 30.00000 0.03678 None Heavy aromatic petroleum naphtha 64742-94-5 30.00000 0.02322 None Oxyalkylated nonyl phenolic resin Proprietary 30.00000 0.02322 None Monoethanolamine borate 26038-87-9 100.00000 0.01634 None Ammonium persulfate 7727-54-0 100.00000 0.01608 None Acetic acid 64-19-7 30.00000 0.01330 None Oxyalkylated phenolic resin Proprietary 10.00000 0.00774 None Inorganic mineral 1317-65-3 5.00000 0.00539 None Potassium chloride 7447-40-7 5.00000 0.00539 None Ethylene glycol 107-21-1 30.00000 0.00490 None Oxylated phenolic resin Proprietary 30.00000 0.00482 None Poly(oxy-1,2-ethanediyl), alpha-(4-nonylphenyl)- omega-hydroxy-, branched 127087-87-0 5.00000 0.00387 None Naphthalene 91-20-3 5.00000 0.00387 None 2-Bromo-2-nitro-1,3- propanediol 52-51-7 100.00000 0.00214 None Sodium chloride 7647-14-5 1.00000 0.00205 None Gluteraldehyde 111-30-8 1.00000 0.00108 None Calcium magnesium carbonate 16389-88-1 1.00000 0.00108 None Polymer Proprietary 1.00000 0.00108 None Inorganic mineral Proprietary 1.00000 0.00108 None 1,2,4 Trimethylbenzene 95-63-6 1.00000 0.00077 None Sodium bisulfate 7681-38-1 0.10000 0.00011 None Methanesulfonic acid, 1- hydroxy-, sodium salt 870-72-4 0.10000 0.00011 None Amine salts Proprietary 0.10000 0.00008 None Quaternary amine Proprietary 0.10000 0.00008 None 2,7- Naphthalenedisulfonic acid, 3-hydroxy-4-(4- sulfor-1-naphthalenyl) azo -, trisodium salt 915-67-3 0.10000 0.00002 None Magnesium nitrate 10377-60-3 0.01000 0.00001 None 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01000 0.00001 None 2-Methyl-4-isothiazolin- 3-one 2682-20-4 0.01000 0.00001 None Magensium chloride 7786-30-3 0.01000 0.00001 None * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 16 Township: 12N Range: 14E Meridian: Umiat Drilling Rig: n/a Rig Elevation: n/a Total Depth: 12444 ft MD Lease No.: ADL0028297 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 122 Feet Csg Cut@ Feet Surface: 10 3/4" O.D. Shoe@ 3560 Feet Csg Cut@ Feet Intermediate: 7 5/8" O.D. Shoe@ 10193 Feet Csg Cut@ Feet Production: 3.5" x 2 7/8" O.D. Shoe@ 12444 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 4.5" O.D. Tail@ 9088 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Annulus Bridge plug 9818 ft 9370 ft 15.8 ppg C.T. Tag Initial 15 min 30 min 45 min Result Tubing 2350 2237 2210 IA 65 59 57 OA 2 2 2 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Tagged cement with coil at 9370 ft MD and appled 10,000 pounds down on the plug with no movement. Pulled up and performed a MIT-T. The MIT-T was passing (1.8 bbls in and 2 bbls return). November 16, 2024 Guy Cook Well Bore Plug & Abandonment PBU P1-08A Hilcorp North Slope LLC PTD 2021990; Sundry 324-608 None Test Data: P Casing Removal: Miles Shaw Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-1116_Plug_Verification_PBU_P1-08A_gc 9 9 9 9 9 9 9 9 9 9 9 9 9 9 99 9 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.22 14:28:07 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 16 Township: 12N Range: 14E Meridian: Umiat Drilling Rig: n/a Rig Elevation: n/a Total Depth: 12444 ft MD Lease No.: ADL0028297 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 122 Feet Csg Cut@ Feet Surface: 10 3/4" O.D. Shoe@ 3560 Feet Csg Cut@ Feet Intermediate: 7 5/8" O.D. Shoe@ 10193 Feet Csg Cut@ Feet Production: 3.5" x 2 7/8" O.D. Shoe@ 12444 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 4.5" O.D. Tail@ 9088 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Annulus Bridge plug 9818 ft 9370 ft 15.8 ppg C.T. Tag Initial 15 min 30 min 45 min Result Tubing 2350 2237 2210 IA 65 59 57 OA 2 2 2 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Tagged cement with coil at 9370 ft MD and appled 10,000 pounds down on the plug with no movement. Pulled up and performed a MIT-T. The MIT-T was passing (1.8 bbls in and 2 bbls return). November 16, 2024 Guy Cook Well Bore Plug & Abandonment PBU P1-08A Hilcorp North Slope LLC PTD 2021990; Sundry 324-608 None Test Data: P Casing Removal: Miles Shaw Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-1116_Plug_Verification_PBU_P1-08A_gc 9 9 9 9 9 9 9 9 9 9 9 9 9 9 99 9 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.22 14:28:07 -09'00' 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 P1-08A Extended Perforating Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-199 50-029-22384-01-00 ADL 0028297 12444 Conductor Surface Intermediate Production Liner 8764 80 3519 10156 3399 12408 20" 10-3/4" 7-5/8" 3-1/2" x 3-3/16" x 2-7/8" 8763 42 - 122 41 - 3560 37 - 10193 9045 - 12444 2897 42 - 122 41 - 3554 37 - 8743 8197 - 8764 none 470 2480 5120 none 1490 5210 8180 11390 - 12370 4-1/2" 12.6# L-80 35 - 90888771 - 8762 Structural 4-1/2" TIW HBBP No SSSV 9017, 8176 No SSSV Date: Bo York Operations Manager Eric Dickerman Eric.Dickerman@hilcorp.com (907) 564-5258 PRUDHOE BAY 11/1/2024 Current Pools: PT MCINTYRE OIL Proposed Pools: PM STUMP ISL 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: 2024.10.21 14:21:50 - 08'00' Bo York (1248) By Grace Christianson at 2:17 pm, Oct 22, 2024 2:18 pm, Oct 22, 2024 CDW 10/25/2024 11/1/2024 DSR-10/25/24SFD 10/26/2024MGR25OCT24 10-404 * AOGCC to witness slickline tag of Kuparuk Oil Pool cement isolation plug ~ 9457' MD. *AOGCC to witness pressure test of cement plugs to 2200 psi. JLC 10/28/2024Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.29 03:34:35 -08'00' 10/29/24 RBDMS JSB 102924 Well: P1-08A PTD:202199 Well Name:P1-08A API Number:50-029-22384-01 Current Status:Operable Rig:SL/EL/Coil/Frac Estimated Start Date:Nov 1, 2024 Estimated Duration:7days Regulatory Contact:Carrie Janowski First Call Engineer:EricDickerman 307-250-4013 Second Call Engineer:David Bjork 907-440-0331 Current Bottom Hole Pressure:3,768 psi at 8,712’ TVD 8.4 PPGE | Taken 7/1/2021 Max. Anticipated Surface Pressure:2,897 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:2,600 psi (Taken on 8/8/24) Min ID:2.440” Max Angle:97 Deg at 11,327’ Brief Well Summary: P1-08A is currently completed as a Kuparuk lateral. Current Kuparuk production is marginal. Based on success in the Stump Island pool in P1-13, P1-08A has potential to be recompleted to the Stump Island pool. Objectives: Recomplete well from Kuparuk producer to Stump Island Producer. Cut and pull existing CTD liner. Place cement plug to isolate Kuparuk interval. Perforate Stump Island interval and perform hydraulic fracture stimulation. Procedure: Slickline: 1. Load IA with seawater and diesel freeze protect. 2. DGLVs. Eline: 3. Load tubing with 250 bbl (1.5x WBV to bottom perf) of 8.6 ppg KWF. 4. Set 3-3/16” bridge plug at 9,800’. 5. Punch 3-3/16” liner from 9,708’ – 9,713’. 6. Cut 3-3/16” liner at 9,557’. CBL logged TOC at 9,751’. Coiled Tubing: Notes: x Due to the necessary open hole deployment of Extended Perforating (liner undeployment) jobs, 24- hour crew and WSS coverage is required. x The well will be killed and monitored before undeploying the CTD liner. This is generally done during the drift 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, it will either be killed by bullheading or circulating bottoms up. 7. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH. 8. MU PCE, RIH to TOL at 9,057’ and circulate 175bbl 8.6 ppg KWF.. a. Wellbore volume to CIBP = 145 bbls Well: P1-08A PTD:202199 b. 4-1/2” Tubing – 9,057’ x 0.0152 bpf = 138 bbl c. 3-1/2”” Liner – (9,489’ – 9,057’) x 0.0087 bpf = 4 bbl d. 3-3/16” Liner – (9,800’ – 9,489’) x 0.0076 bpf = 3 bbl 9. Spear CTD liner top. 10. Confirm well is dead then begin POOH while pumping pipe displacement. 11. At surface, prepare for recovery of 3-1/2” x 3-3/16” STL liner. Estimated weight is 3,675 #. a. 3-1/2” Weight = (9,489’ – 9,057’) x 8.81#/ft = 3,806 # in air (3,306# in 8.6ppg) b. 3-3/16” Weight = (9,557’ – 9,489’) x 6.2#/ft = 422 # in air (367 # in 8.6ppg) 12. Confirm well is dead. Bleed any pressure off to return tank. Kill well with 8.6 ppg brine as needed. Maintain continuous 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. 13.*Perform drill by picking up safety joint with TIW valve and space out before MU fishing assembly. Review well control steps with crew prior to breaking lubricator connection and commencing liner recovery. 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. 14. Break lubricator connection at QTS and begin laying down liner per schedule below. Use lift nubbins. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. Liner Recovery Liner Interval Length Weight of liner (lbs) 9,057’ - 9,489’432’3806# (8.81#) 9,489’ - 9,557’68’422# (6.2 #) 4228# 15. End of open hole operations. All subsequent steps will be performed with PCE. 16. RIH with cementing nozzle. Turn wellbore over to diesel. 17. Lay in cement plug across the top of the Kuparuk up to the HRZ with a target TOC of 9,457’ md. c. Top Kuparuk at 9,537’ md. Bottom HRZ at 9,537’ md. Top HRZ at 9,434’ md. See reference log. d. If possible, enter 3-3/16” liner at cut and begin laying in cement plug from CIBP at 9,800’ md up to the target TOC at 9,457’ md (12.5bbl of 15.8 ppg Class G cement). e. If unable to enter 3-3/16” liner, lay in cement from cut at 9,557’ up to the target TOC of 9,457’ md (4.6bbl of 15.8 ppg Class G cement). 18. POOH pumping pipe displacement. 19. Freeze protect well. 20. RDMO CTU. Slickline: 21. Tag TOC with AOGCC witness. Provide 24hr notice to AOGCC prior to witness. 22. Pressure test cement plug to 2,200 psi a. (0.25 psi/ft x 8,479’ TVD (9,457’ md) = 2,120 psi. 23. Set TTP in nipple at 9,049’. 24. MIT-T and MIT-IA to 3,000psi.3,000 2,200 Well: P1-08A PTD:202199 25. Pull TTP. 26. Dummy gun drift for eline add perf. Eline: 27. Add Stump Island Perforations from ~9,250’ – 9,260’. Frac: 28. Perform hydraulic fracture stimulation per pump schedule provided in Sundry application. Treating pressures also noted in sundry application. ťÍČô ϭ >īŪĖî ťÍČô «ĺīŪıôϼČÍīϽ ŪıŪīÍťĖŽôώ«ĺīŪıô ϼČÍīϽ Íťô Řĺŕϟ ĺĲèϟ ϼŕŕÍϽ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲť ϼϭϽ ͐͑͏ϭώ[ĖĲôÍŘ [ĺÍî ͕Ϡ͒͏͏͕Ϡ͒͏͏͐͏ ͑͑͏ϭώ[ĖĲôÍŘ >(͗Ϡ͖͏͏͔͐Ϡ͏͏͏͔͑ ͒ēŪťîĺſĲ ͔͐Ϡ͏͏͏ ͓͒͏ϭώ³ϱ[ĖĲħ Íî ͑Ϡ͏͏͏͖͐Ϡ͏͏͏͔͑ ͔͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͑Ϡ͏͏͏͐͘Ϡ͏͏͏͔͑͏ϟ͔͐͏͏ώıôŜē ͐Ϡ͏͏͏ ͕͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͐Ϡ͓͏͏͑͏Ϡ͓͏͏͔͑͏ϟ͖͔͐͏͏ώıôŜē ͐Ϡ͏͔͏ ͖͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͐Ϡ͏͏͏͑͐Ϡ͓͏͏͔͑͐ϟ͏͐͏͏ώıôŜē ͐Ϡ͏͏͏ ͗͑͏ϭώ[ĖĲôÍŘ iŽôŘώ>īŪŜē ͗Ϡ͓͏͏͑͘Ϡ͗͏͏͔͑ ͘ēŪťîĺſĲ ͑͘Ϡ͗͏͏ ͐͏͒͏ϭώ³ϱ[ĖĲħ Íî ͘Ϡ͏͏͏͒͗Ϡ͗͏͏͔͑ ͐͐͒͏ϭώ³ϱ[ĖĲħ ͐ώ͐͏Ϡ͏͏͏͓͗Ϡ͗͏͏͔͑͐ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͏Ϡ͏͏͏ ͐͑͒͏ϭώ³ϱ[ĖĲħ ͑ώ͐͏Ϡ͏͏͏͔͗Ϡ͗͏͏͔͑͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͏Ϡ͏͏͏ ͐͒͒͏ϭώ³ϱ[ĖĲħ ͒ώ͐͏Ϡ͏͏͏͕͗Ϡ͗͏͏͔͑͒ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͒͏Ϡ͏͏͏ ͓͐͒͏ϭώ³ϱ[ĖĲħ ͓ώ͐͏Ϡ͏͏͏͖͗Ϡ͗͏͏͔͓͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͏Ϡ͏͏͏ ͔͐͒͏ϭώ³ϱ[ĖĲħ ͔͐͏Ϡ͏͏͏͗͗Ϡ͗͏͏͔͔͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͏Ϡ͏͏͏ ͕͐͒͏ϭώ³ϱ[ĖĲħ ͕ώ͐͏Ϡ͏͏͏͗͘Ϡ͗͏͏͔͕͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͏Ϡ͏͏͏ ͖͐͑͏ϭ[ĖĲôÍŘ >īŪŜē ͗Ϡ͓͏͏͐͏͖Ϡ͑͏͏ MIT-T 3000 psi MIT-IA 3000 psi Maximum Anticipated Treating Pressure:4000 psi IA Pop-off Set Pressure (~95% of MIT-IA):2850 psi IA Minimum Hold Pressure (Pop-off – 300 psi):2550 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):5275 psi w/ 2550 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:4750 psi Global Kickout (95% of MATP):5015 psi N2 POP-off set pressure (MATP):5275 psi Treating Line Test Pressure (MATP + 1000 psi):6275 psi OA Pressure:Monitor Max Anticipated Proppant Loading:6 PPA 9,250’ – 9,260’. FRAC CREW Steps to add to step 28: 28 a. Install and test tree saver to 6275 psi. 28 b. Pressure test treating lines to 6275 psi. 28 c. Pressure test pump kick outs to 4750 and global kickouts to 5015 psi. 28 d. Pressure test IA Pop off to 2850 psi. - mgr 5275 psi 4000 psi Well: P1-08A PTD:202199 Slickline: 29. Set live gas lift design. Well testing: 30. Post frac flowback with contingent coil cleanout. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Coil Tubing BOPE Schematic 4. Standing Orders for Open Hole Well Control during Open hole operations 5. Equipment Layout Diagram 6. Reference log 7. Sundry Change Form Well: P1-08A PTD:202199 Current Wellbore Schematic Well: P1-08A PTD:202199 Proposed Wellbore Schematic Well: P1-08A PTD:202199 Coiled Tubing BOPs Well: P1-08A PTD:202199 Standing Orders for Open Hole Well Control during Open hole operations Well: P1-08A PTD:202199 Equipment Layout Diagram Well: P1-08A PTD:202199 Reference Log Well: P1-08A PTD:202199 Sundry change form 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 Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date Date: Oct 19, 2024 Subject: P1-08A Stump Island Sandstone Recomplete and Fracture Stimulation From: Eric Dickerman O: (907) 564-4061 C: (307) 250-4013 To: AOGCC Estimated Start Date: 11/01/2024 Attached is Hilcorp’s proposal and supporting documents to recomplete well P1-08A from the Kuparuk (Pt Mcintyre oil pool) to the Stump Island (Pt M Stump Is oil pool) and perform a fracture stimulation. P1-13 was recently recompleted from the Point McIntyre pool to the Stump Island Pool. The well was perforated and tested, and resulting diagnostics indicate single digit millidarcy formation permeability with high oil cuts and little to no water production. These diagnostics indicate that the well performance could improve with a hydraulic fracture stimulation. P1-13 is currently the only well completed and producing from the Stump Island pool, and a fracture stimulation is planned. As a continuation of evaluating the Stump Island pool, P1-08A is also planned to be recompleted and fracture stimulated in the Stump Island to allow pulse testing between the two wells to better understand the extent of the reservoir. Currently P1-08A is on a 21 days on 36 days off cycle program, and existing Kuparuk production is marginal. Hilcorp requests an exception to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling, based on Area Injection Orders. Please direct questions or comments to Eric Dickerman. SECTION 1 - AFFIDAVIT (20 AAC 25. 283, a, 1): Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 1. SIGNED AFFIDAVIT: COPY OF NOTIFICATION SENT VIA EMAIL: SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN 1/2 MILE – SURFACE (20 AAC 25. 283, a, 2, B): List of wells in Plat (20 AAC 25.283, a, 2, B) SECTION 3: EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25. 283, a, 3): Well P1-08A is located in the Eastern Operating Area of Prudhoe Bay (AIO 4G, 2015). In 1993 AIO 4 was amended to include the Pt. Mcintyre, Stump Island, and West Beach Oil pools in AIO 4A. Conclusion #10 (Area Injection Order 4A, August 12, 1993, Page 5) states that “No underground sources of drinking water (USDWs) are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field.” Area Injection Order 4G, October 15, 2015, Page 3 states that “All information related to AIO 4, AIO 4A, AIO 413, AIO 4C, AIO 4D, AIO 4E and AIO 4F is hereby incorporated by reference into the record for this order.” Based on the Area Injection Order sections referenced above, Hilcorp requests exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling.Agree that no freshwater aquifers are present within AOR. SFD SECTION 4: PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS (20 AAC 25.283.a): There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5: DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25. 283, a, 5): All casing is cemented in accordance with 20 AAC 25.52, b and tested in accordance with 20 AAC 25.030, g when completed. See current wellbore schematic for casing details: SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL (20 AAC 25.283, a, 6): Summary: P1-08 was spudded 7/14/1993. The 13-1/2” hole was drilled to 3,560’ and 10-3/4” casing was ran to 3,560’. The 10-3/4” casing was cemented with 1027 sx (397 bbl) of Permafrost E lead and 350 sx (72 bbl) of Class G tail cement. The plug was bumped. A 250 sx (42bbl) top job was performed. The 9-7/8” hole was drilled to 10,193’ and 7-5/8” casing was ran to 10,193’. The 7-5/8” casing was cemented with 630 sx (135 bbl) of Class G cement. No CBL was logged in the 7-5/8”. Volumetric and lift calculations from data available on the 7-5/8” primary cement job put the TOC at 7,741’ md (7,146’ ssTVD). This is equivalent to a 40% excess factor and accounts for the rathole and shoe tract volumes. The 6” production hole was drilled to 10,900’ and completed with a 4-1/2” slotted liner. P1-08 was sidetracked to P1-08A on 12/21/2002. The rig drilled out of the shoe of the existing 4-1/2” slotted liner to a TD of 12,444’ with the entire lateral in the Kuparuk reservoir. The 3-1/2” x 3-1/4” x 2- 7/8” CTD liner was ran to 12,444’ and cemented with 41bbl of 15.8ppg Class G cement. Full returns were noted throughout the job. A CBL logged on 7/23/2024 logged the TOC behind the CTD liner at 9,751’ md. The CTD liner will need to be cut and pulled to access the Stump Island interval. Top of Stump Island interval is 8,226’ ssTVD. The calculated TOC behind the 7-5/8” casing at 7,149’ ssTVD indicates isolation across the Kuparuk and Stump Island pools and their associated confining intervals. All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within well design limits. No CBL was logged in the 7-5/8”. The calculated TOC behind the 7-5/8” casing at 7,149’ ssTVD Agree that each hydrocarbon zone is cement-isolated. SFD hydrocarbon zone penetrated by the well is isolated. 7,741’ md (7,146’ ssTVD). SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, A, 7): As part of the well preparation pre-frac, the 7-5/8” x 4-1/2” annulus will be tested to 3,000psi and the 4- 1/2” tubing will be tested to 3,000psi. The 7-5/8” x 4-1/2” and the 10-3/4” x 7-5/8” annulus pressures will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. SECTION 8: PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD (20 AAC 25.283, A, 8): Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 10-3/4” Surface Casing 45.5#NT80 5210 2470 7-5/8” Production Casing 29.7#NT95HS 8180 5130 4-1/2” Production Tubing 12.6#L80 8430 7500 Wellhead FMC manufactured wellhead, rated to 5,000 psi. Tubing head adaptor: 11" 5, 000 psi x 4-1/16" 5,000 psi Tubing Spool: 11" 5,000 psi w/ 2-1/16" side outlets Casing Spool: 11" 5,000 psi w/ 2-1/16" side outlets Tree: CIW 4-1/16" 5,000 psi A 10k psi rated TreeSaver will be used during these fracturing operations. SECTION 9: DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, A, 9): >ĺıÍťĖĺĲ a" ĺŕ a" ÍŜô «"ŜŜ ĺŕ «"ŜŜ ĺť «" ēĖèħĲôŜŜ >ŘÍèώ@ŘÍîϟ ŕŜĖϯċť [Ėťēϟώ"ôŜèϟ ĺīīŽĖīīôώaŪîŜťĺĲôŜ ϼa͒Ͻ ͖͓͓͔͕͔͕͐͐͐͗͗͑͑͐͒͒͐͘͘͏ϟ͖͏ēÍīô ĺŕ ťŪıŕώIŜīÍĲî ēÍīô ͔͕͕͕͖͐͐͐͗͑͑͗͑͒͐͐͘͘͏ϟ͖͐ĖīťϯēÍīô ťŪıŕώIŜīÍĲî ÍĲîŜťĺĲô ͕͕͓͓͖͓͕͖͐͒͗͑͒͗͐͐͘͘͘͏ϟ͕͕ĖīťϯÍĲîŜťĺĲô F¾͓͓͔͖͓͕͓͒͒͗͐͗͗͘͘͏͕͓͏ϟ͖͏ēÍīô XŪŕÍŘŪħ ͔͖͒͘ϱ ͓͗͗͏ϱ ϱ ͏ϟ͕͒ÍĲîŜťĺĲô SECTION 10: LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10): Plat of wells within one-half mile of P1-08A wellborereservoir trajectory and location of faults. Black squares indicate Stump Island pool intersections. The plat shows the location and orientation of each well that transects the confining zone. Hilcorp has formed the opinion, based on the following assessments for each well, seismic, and other subsurface information currently available, that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing and Cement assessments for all wells that transect the confining zone: P1-13 (PTD 193074) Spud date for P1-13 was 5/28/1993. A 13-1/2” hole was drilled and 10-3/4” surface casing was ran to 3570’. The surface casing was cemented with a lead of 2235 cubic ft of Type E Permafrost cement followed by 403 cubic ft Class G tail. The plug bumped and pressured up to 2000psi. A 235 cubic ft sx top job was also performed. A 9-7/8” intermediate hole was drilled and cased with 10275’ of 7-5/8” casing. The casing was cemented with 163.2 bbl of 15.8ppg cement, no losses reported, and the top plug bumped at 472 bbl (reported 4,682 strokes at 0.1008bbl/stroke) versus a calculated volume to float collar of 468 bbl. Accounting for the shoe track and zero rathole puts 159.5 bbl of cement in the annulus (897 cu ft or 159.8bbl reported on the 10-407). A 1.15 excess factor (1.3 times the openhole x casing capacity) places the cement top behind the 7-5/8” casing at 6,649’ md. Using an additionally conservative 2.0 excess factor (2 times the openhole x casing capacity) puts the calculated top of cement at 8,193’ md. Current pick of top of Stump Island Sandstone is 8,797’ md (8,196’ ssTVD). A Cement Bond Log was pulled on April 8, 2024 and logged good cement behind the 7-5/8” from the bottom of the logging interval at 9,050’ up to the 4-1/2” tubing tail at 8,704’ md. This log indicates that the top of cement behind the 7- 5/8” casing is above 8,704’ md (8,123’ ssTVD). This log indicates good cement isolation above and below the Stump Island pool. A 6-3/4” production hole was drilled and the well was completed with a 4-1/2” un-cemented production liner down to 11010’. On 8/20/2015, 108 bbl of Class G cement was circulated in to the 7-5/8” x 4-1/2” annulus to cement off a production casing leak. A subsequent MIT-IA to 2500psi passed. P1-02 (PTD 188005) Formerly Point McIntyre #3 Well was spudded 3/12/1988. The 12-1/4” surface hole was drilled down to 4,496’ and 9-5/8” casing was ran to 4,483’. The 9-5/8” casing was cemented with 2000sx CS II and 400 sx of Class G, with cement returns to surface. The 8-1/2” hole was drilled to 9,416’ and 7” casing was run to 9,407’. The 7” casing was cemented with 444 sx (187 bbl) 12.5 ppg Class G with 12% gel slurry lead and a 290 sx (60 bbl) 15.7 ppg Class G tail. An external casing packer was run as part of the 7” casing with a set depth of 8,933’ – 8,954’. A cement bond log was ran in the 7” casing on 4/6/1988 and the Tail TOC picked from that log is 8,725’ md (8,168’ ssTVD) and the Lead TOC picked at 6,160’ md (5,755’ ssTVD). Top of Stump Island interval is at 8,171’ ssTVD. On 3/22/02, coiled tubing layed in a Class G cement abandonment plug from 9,343’ up to 7,000’ after squeezing 15 bbl behind pipe. The tubing was then cut at 6,530’ and the well was sidetracked to P1- 02A. P1-02A (PTD 202065) good cement isolation above and below the Stump Island pool 8,725’ Tail TOC Lead TOC picked at 6,160’ md P1-02A sidetracked out of the parent well P1-02. The 7” casing was exited in the UG1 at 6,491’ on 3/31/2002 and a 6” hole was drilled to 11,370’ md. The 4-1/2” liner was ran but became stuck, was left from 5,238’ – 10,285’, and was not able to be cemented. A liner top packer was set and pressure tested to 3,000psi. The 4-1/2” shoe tract was drilled out and a 2-7/8” production liner was ran to 11,224’. The 2-7/8” was cemented with 216 sxs (41 bbl) of 15.9 ppg cement. A CBL was ran on 5/8/2002 and logged the TOC behind the 2-7/8” production liner at 10,380’ (8,183’ ssTVD). Top of Stump Island interval is at 8,306’ ssTVD. P1-09 (PTD 196154) P1-09 was spudded on 10/3/1996. A 12-1/4” surface hole was drilled to 5,030’ and 9-5/8” casing was ran to 5,022’. The 9-5/8” casing was cemented with 1,574 sx (615 bbl) of Coldset III lead and 333 sx (70 bbl) of Class G tail cement. The plug was bumped, no losses were reported during the job, and cement was returned to surface. The 8-1/2” hole was drilled to 11,445’ and 7” production casing was ran to 11,134’. The 7” casing was cemented with 275 sx (58 bbl) Class G cement with good returns noted throughout job. The 6” exploration tail was drill down to 13,242’ and a 4-1/2” production liner was ran from 11,034’ – 13,242’. The 4-1/2” production liner was cemented with 472 sx (100 bbl) of Class G cement. The plug was bumped, and the well was reverse circulated off the liner top with no cement returns noted at surface. A CBL was ran on 11/2/1996 from a tag of 11,048’ up to 9,700’ md (8,052’ ssTVD) with cement being logged across the entire interval. This indicates the TOC behind the 4-1/2” liner is above 9,700’ (8,052’ ssTVD). Top of Stump Island interval is 8,310’ ssTVD. PTMCINT-01 (PTD 177046) PTMCINT-01 was spudded on 8/11/1977 as an exploration well. It is currently plugged and abandoned. The 20” conductor was spudded to 85’ and cemented with 200 sx of permafrost cement. A 17-1/2” surface hole was drilled to 2,725’ md and 13-3/8” surface casing was ran to 2,712’ md. The 13-3/8” casing was cemented with 4,500 sx of permafrost cement. Cement was returned to surface. A 12-1/4” intermediate hole was drilled to 12,318’ md and 9-5/8” casing was ran to 12,314’ md. The 9-5/8” intermediate casing was cemented with 1,000 sx of Class G cement with 20 bbl of losses to formation noted. A Cement Bond Log was ran on 9/28/1977 and logged a TOC behind the 9-5/8” at 11,302’ md (9,153’ ssTVD). The 8-1/2” production hole was drilled to 13,440’ md. Formation evaluation logs were ran, then a 50 sx Class G cement plug was placed from 13,307’ up to 13,182’ to isolate the wellbore from the Sag River/Sadlerchit. A second cement plug was placed across the 9-5/8” shoe from 12,417’ up to 12,217’ with 81 sx Class G cement. Then the 9-5/8” casing was punched from 10,333’ – 10,337’, a retainer was set at 10,216’ (8,421’ ssTVD), and a 300 sx squeeze was performed with Class G cement. The rig attempted to cut a window in the 9-5/8” casing from 10,110’ – 10,140’ before the objective changed and the window was plugged back with a 36 sx Class G cement plug from 10,140’ up to 10,080’ (8,365’ – 8,320’ ssTVD). The 9-5/8” was cut and pulled from 2,850’, then a final 245 sx Class G cement plug was placed inside the 13-3/8” casing from 2,860’ up to 2,650’ (2,831’ – 2,621’ ssTVD). Top of Stump Island interval is 8,301’ ssTVD. In PTMCINT-01, the Ivishak, Shublik, Sag River, and Kuparuk are isolated by cement. The Stump Island interval is likely not entirely covered by cement. However, the Stump intercept in Pt McIntyre 1 is located about 2,000' north of the Stump intercept in P1-08A. Due to that separation it is highly unlikely that Pt McIntyre-01 will interfere with frac fluids in the proposed P1-08A operations. SFD TOC behind the 4-1/2” liner is above 9,700’ (8,052’ ssTVD). Top of Stump Island interval is 8,310’ ssTVD. Top of Stump Island interval is at 8,306’ ssTVD. The 4-1/2” liner was ran but became stuck, was left from 5,238’ – 10,285’, and was not able to be cemented. TOC behind the 2-7/8” production liner at 10,380’ (8,183’ ssTVD) PTMCINT-01 was called P&A’d on 10/7/1977 and immediately sidetracked to PTMCINT-02 (PTD 177065) below the existing 13-3/8” surface casing shoe. PTMCINT-02 penetrates the Stump Island pool outside of the 1/2 mile radius of P1-08A. P1-17 (PTD 193051) P1-17 was spudded 4/3/1993. A 13-1/2” hole was drilled to 3,860’ md and 10-3/4” surface casing was ran to 3,860’. The 10-3/4” casing was cemented with 2,385 sx (425 bbl) of Permafrost E cement lead followed by 350 sx (72 bbl) Class G tail. Full returns were noted throughout the primary cement job, and the plug bumped. A top job was performed with 250 sx Permafrost C cement. The 9-7/8” production hole was drilled to 10,532’ md and 7-5/8” production casing was ran to 10,532’. The 7-5/8” casing was cemented with 530 sx (120 bbl) Class G cement. Full returns were noted, and the plug bumped. A Cement Bond Log was ran 5/13/1993 and logged from 10,413’ md up to the tubing tail at 9,488’. Cement was logged across the entire interval, which puts the TOC behind the 7-5/8” casing above 9,488’ md (8,155’ ssTVD). Top of Stump Island interval is at 8,248’ ssTVD. P1-18A (202076) The parent well P1-18 (PTD 199116 – also known a NV-18) was drilled to test the Nuvuk formation. The well was spudded on 12/6/1999. A 12-1/4” hole was drilled to 4,625’ and 9-5/8” surface casing was ran to 4,609’. The 9-5/8” casing was cemented in two stages with the first stage being 189 sx (150 bbl) 10.7 ppg ArcticSet Lite III lead followed by a 219 sx (46 bbl) Class G tail. The plug was bumped, an ES cementer was opened and 375 bbl of 10.7ppg ArcticSet Lite III cement was pumped. “Clabbered” returns were noted at surface, and the plug was bumped. The 8-3/4” exploration hole was drilled to 11,187’. After exploration data was collected, P&A operations began on the 8-3/4” open hole. The first P&A cement plug was placed across the Ivishak and Sag from TD up to 10,877’ with 26 bbl of Class G. The second P&A cement plug was placed across the Kuparuk and Stump Island in two stages from 10,487’ up to 9,913’ with 48 bbl of Class G, and from 9,913’ up to 9,320’ with another 48 bbl of Class G. Then a 9-5/8” EZSV was set at 4,543’ and 13bbl of Class G cement were squeezed through the retainer and 4 bbl of Class G were layed in on top. The rig was released on 1/4/2000. P1-18 (NV-18) does not penetrate the Stump Island within a 1/2 mile radius of P1-08A). P1-18A exited the 9-5/8” casing from the parent well with the window from 4,491’ – 4,507’ md. The 8- 3/4” production hole was drilled to 10,641’ and 7” production casing was ran to 10,623’ md. The 7” production casing was cemented with 190 sx (110 bbl) of 11.2 ppg lead followed by 205 sx (42 bbl) 15.8 ppg tail. The plug was bumped and returns while cementing were noted at 90%. A Cement Bond Log was ran on 5/16/2002. Cement was present across the entire logging interval from 10,520’ md up to the tubing tail at 9,788’ md (8,632’ ssTVD). This log indicates that the TOC behind the 7” production casing is above 8,632’ ssTVD. Volumetric and lift calculations from data available on the 7” primary cement job put the TOC at 7,505’ md (6,706’ ssTVD). This is equivalent to a 60% excess factor and accounts for the rathole and shoe tract volumes and factors in the 90% return rate. Top of Stump Island interval is 8,285’ ssTVD. TOC behind the 7-5/8” casing above 9,488’ md (8,155’ ssTVD). Top of Stump Island interval is at 8,248’ ssTVD. Top of Stump Island interval is 8,285’ ssTVD. second P&A cement plug was placed across the Kuparuk and Stump Island in two stages TOC at 7,505’ md (6,706’ ssTVD). ®ôīī ĺŕ ťŪıŕ IŜīÍĲî ÍŜĖĲČ ĖƏô èŘĺŜŜ ťŪıŕ IŜīÍĲî ÍŜĖĲČ ēĺô "ôŕťē ÍŜĖĲČ ēĺô "ôŕťē iiώaôťēĺî ¾ĺĲÍī IŜĺīÍťĖĺĲ bĺťô ŜŜ«"ĖĲ ċťώıî ċťώŜŜ«"ŜŜ«" ͐ϱ͕͖͐͒͗͐͒ϱ͔ϯ͗Г ͐͏͖͔͕͕͑͗͘ÍæĺŽôώ͗͐͑͒ ôıôĲťώĺĲî [ĺČ ´ôŜ iÍæĺŽôώťĺŕώĺċώīĺČČĖĲČ ĖĲťôŘŽÍīϟ ͐ϱ͏͖͖͑͗͐͐Г ͓͘͏͖͓͕͗͗͑͗͐͗ ôıôĲťώĺĲî [ĺČ ´ôŜ ͐ϱ͏͑͗͒͏͕͑ϱ͖ϯ͗Г ͓͐͐͑͑͗͘͏͏͗͐͗͒ ôıôĲťώĺĲî [ĺČ ´ôŜ ͐ϱ͏͗͒͐͘͏͖Г ͓͓͓͐͐͐͒͐͘ÍæĺŽôώ͗͏͔͑ ôıôĲťώĺĲî [ĺČ ´ôŜ iώÍæĺŽôώťĺŕώĺċώīĺČČĖĲČ ĖĲťôŘŽÍīϟ aIbϱ͏͐͗͒͏͐͘ϱ͔ϯ͗Г ͓͖͔͐͑͒͐͗͒͐͒͘͘ ôıôĲťώĺĲî [ĺČ bĺ ®ôīīæĺŘôώĖŜώЭώſĖťē ıŪīťĖŕīôώèôıôĲťώŕīŪČŜϟ ͐ϱ͖͓͖͐͗͑͗ϱ͔ϯ͗Г ͐͏͔͓͒͑͐͘͘ÍæĺŽôώ͔͔͗͐ ôıôĲťώĺĲî [ĺČ ´ôŜ iώÍæĺŽôώťĺŕώĺċώīĺČČĖĲČ ĖĲťôŘŽÍīϟ ͐ϱ͔͖͐͗͗͑͗Г ͐͏͕͓͔͑͒͘͘ÍæĺŽôώ͕͗͒͑ ôıôĲťώĺĲî [ĺČ iώÍæĺŽôώťĺŕώĺċώīĺČČĖĲČ ĖĲťôŘŽÍīϟώώ@ώťÍĖīώÍťώ͘Ϡ͖͗͗Д ıîώϯώ͗Ϡ͕͒͑ДώŜŜ«"ώŜôť æôīĺſώťŪıŕώIŜīÍĲîϟ ͕͖͏͕«ĺīŪıôťŘĖèϯ[Ėċť ´ôŜ bĺ SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES (20 AAC 25.283, A, 11): Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 2 mapped faults that transect the Stump Island interval and enter the confining zone within the 1/2 mile radius of the production and confining zone trajectory for P1-08A. Fracture gradients within the confining zone (Top Stump Island Shale and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. Faults 1 and 2 intersect the production interval and confining zone within the 1/2 mile radius of the planned frac. Their displacements, sense of throw, and zone in which they terminate upwards are given below. >ÍŪīť ēŘĺſ "ĖŘôèťĖĺĲ ĺŕώ¾ĺĲô ĺťťĺıώ¾ĺĲô ͐ϱ͐͒ώ"ĖŜťÍĲèôώťĺώ>ÍŪīť ͓͐͏ϱ͐͏͏ώċť "b ĺīīŽĖīīôώaŪîŜťĺĲôŜ ÍŜôıôĲť ͗͗͏ċť ͑͏ϱ͔͏ώċť "b ťŪıŕώIŜīÍĲîώēÍīô ÍŜôıôĲť ͑Ϡ͓͒͐ ċť Fault 1 Fault 2 Maximum stress direction is estimated to be North – South plus or minus 15 degrees based data from the P1-02 FMS log from 30-MAR-1988. The planned frac half-length of 285’ should not reach any of the mapped faults. Fault 1 is the closest to P1-08A, at 880’ away. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12): Fracture Stimulation Pump Schedule ťÍČôώϭ >īŪĖî ťÍČô «ĺīŪıôϼČÍīϽ ŪıŪīÍťĖŽôώ«ĺīŪıô ϼČÍīϽ Íťô Řĺŕϟ ĺĲèϟ ϼŕŕÍϽ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲť ϼϭϽ ͐͑͏ϭώ[ĖĲôÍŘ [ĺÍî ͕Ϡ͒͏͏͕Ϡ͒͏͏͐͏ ͑͑͏ϭώ[ĖĲôÍŘ >(͗Ϡ͖͏͏͔͐Ϡ͏͏͏͔͑ ͒ēŪťîĺſĲ ͔͐Ϡ͏͏͏ ͓͒͏ϭώ³ϱ[ĖĲħ Íî ͑Ϡ͏͏͏͖͐Ϡ͏͏͏͔͑ ͔͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͑Ϡ͏͏͏͐͘Ϡ͏͏͏͔͑͏ϟ͔͐͏͏ώıôŜē ͐Ϡ͏͏͏ ͕͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͐Ϡ͓͏͏͑͏Ϡ͓͏͏͔͑͏ϟ͖͔͐͏͏ώıôŜē ͐Ϡ͏͔͏ ͖͒͏ϭώ³ϱ[ĖĲħ "ĖŽôŘťôŘϯèĺŪŘ ͐Ϡ͏͏͏͑͐Ϡ͓͏͏͔͑͐ϟ͏͐͏͏ώıôŜē ͐Ϡ͏͏͏ ͗͑͏ϭώ[ĖĲôÍŘ iŽôŘώ>īŪŜē ͗Ϡ͓͏͏͑͘Ϡ͗͏͏͔͑ ͘ēŪťîĺſĲ ͑͘Ϡ͗͏͏ ͐͏͒͏ϭώ³ϱ[ĖĲħ Íî ͘Ϡ͏͏͏͒͗Ϡ͗͏͏͔͑ ͐͐͒͏ϭώ³ϱ[ĖĲħ ͐ώ͐͏Ϡ͏͏͏͓͗Ϡ͗͏͏͔͑͐ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͏Ϡ͏͏͏ ͐͑͒͏ϭώ³ϱ[ĖĲħ ͑ώ͐͏Ϡ͏͏͏͔͗Ϡ͗͏͏͔͑͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͏Ϡ͏͏͏ ͐͒͒͏ϭώ³ϱ[ĖĲħ ͒ώ͐͏Ϡ͏͏͏͕͗Ϡ͗͏͏͔͑͒ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͒͏Ϡ͏͏͏ ͓͐͒͏ϭώ³ϱ[ĖĲħ ͓ώ͐͏Ϡ͏͏͏͖͗Ϡ͗͏͏͔͓͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͏Ϡ͏͏͏ ͔͐͒͏ϭώ³ϱ[ĖĲħ ͔͐͏Ϡ͏͏͏͗͗Ϡ͗͏͏͔͔͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͔͏Ϡ͏͏͏ ͕͐͒͏ϭώ³ϱ[ĖĲħ ͕ώ͐͏Ϡ͏͏͏͗͘Ϡ͗͏͏͔͕͑ϟ͏͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͏Ϡ͏͏͏ ͖͐͑͏ϭ[ĖĲôÍŘ >īŪŜē ͗Ϡ͓͏͏͐͏͖Ϡ͑͏͏ Estimated Cumulative fluid volume: 107,200 gal (4,053 bbl) Estimated total proppant: 210,000 # Table 5– Anticipated Pressures MIT-T 3000 psi MIT-IA 3000 psi Maximum Anticipated Treating Pressure:4000 psi IA Pop-off Set Pressure (~95% of MIT-IA):2850 psi IA Minimum Hold Pressure (Pop-off – 300 psi):2550 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):5275 psi w/ 2550 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:4750 psi Global Kickout (95% of MATP):5015 psi N2 POP-off set pressure (MATP):5275 psi Treating Line Test Pressure (MATP + 1000 psi):6275 psi OA Pressure:Monitor Max Anticipated Proppant Loading:6 PPA There are three overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. 5275 4000 psi Frac Modelling: Maximum Anticipated Treating Pressure: ~4,000 psi Surface pressure is calculated based on a conservative closure pressure of ~0.70 psi/ ft or ~5,845 psi. Net pressure estimated to be built (600 psi). Total friction pressure estimated at 1,200 psi between pipe friction and perforation friction. Hydrostatic pressure of the pad fluid is estimated at 3,690 psi (8.5ppg). 5845psi (closure)+ 600psi (net)+ 1200psi (friction) - 3690psi (hydrostatic) = 3955psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average top confining layer stress is anticipated to be 0.71 psi/ ft and average bottom confining layer stress is anticipated to be 0.70 psi/ft. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~285 ft with a height of ~179 ft TVD. The Kuparuk interval below the Stump Island in P1-08A has a high gas-oil ratio making production marginal. The fracture stimulation was designed to reduce the likelihood of inducing a fracture that will penetrate through the lower confining interval to avoid linking up to the high gas-oil ratio Kuparuk production. Disclaimer Notice: This model was generated by a third party using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. 4,000 psi Pre-Job Anticipated Chemicals to be pumped: SECTION 13: POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN (20 AAC 25.283, A, 13): After the fracture stimulation and potentially during the post frac coiled tubing fill cleanout, the well will be put on production through a portable well test unit. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if proppant production is above the acceptable threshold. The initial flowback period is intended to produce back the treating fluid volume to tanks as quickly as possible. When production is less than 20% water cut and less than 0.5% solids the flowback will be routed to the LPC production facility. There will be a flowback tank farm on pad to store any produced fluids from flowback operations that do not meet the LPC facility specifications mentioned above. The fluids and proppant not suitable for LPC processing will be hauled to GNI for disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. From:Davies, Stephen F (OGC) To:Eric Dickerman Cc:Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Aras Worthington Subject:PBU P1-08A (PTD 202-199, Sundry 324-608) - Frac Sundry - Question Date:Thursday, October 24, 2024 5:00:00 PM Attachments:Memo to Operators 032823.pdf Erik, On October 22nd, AOGCC received Hilcorp’s Sundry Application to fracture PBU P1-08A. The listed operations start date is November 1st. Is this start date accurate? Please take note of the attached Memo to Operators. This helps AOGCC senior staff with our work priorities and efficiency. Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 October 28, 2024 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 10/24/2024 (a)(2) Plat Provided with application. SFD 10/24/2024 (a)(2)(A) Well location Provided with application. P1-08A lies in Sections 16 and 15 of T12N, R14E, UM. SFD 10/24/2024 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online October 24, 2024), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of P1-08A. There are no subsurface water rights or temporary subsurface water rights within 11-1/2 miles of the surface location of P1-08A. SFD 10/24/2024 (a)(2)(C) Identify all well types within ½ mile List of wells provided with application. SFD 10/24/2024 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. Absence of freshwater aquifers is supported by AIO 4A Finding 17 (salinity of 12,000 to 20,000 ppm for all aquifers in the Pt. McIntyre oil field) and AIO 4A Conclusion 10 (no USDWs are known to exist in the PBU Eastern Operating Area and Pt. McIntyre oil field). The Affected Area of AIO 4A includes P1-08A and P1-08. A review of nearby well Pt. McIntyre 3 (PTD 188-005), which is the closest well with shallow porosity data that lies within ½ mile of P1-08A, shows all sands between the base of permafrost and surface casing shoe are very low in resistivity, clearly indicating brackish formation water. AOGCC’s quick-look analysis using Pickett Plots demonstrates that these sands all contain formation waters that exceed 10,000 mg/l TDS. SFD 10/28/2024 (a)(4) Baseline water sampling plan None required. SFD 10/24/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 October 28, 2024 (a)(5) Casing and cementing information Provided with application. CDW 10/22/2024 (a)(6) Casing and cementing operation assessment Kuparuk Reservoir abandonment plug to be pressure tested to 3000 psi. 7-5/8” x OH TOC calculated to be 7741’ MD (Well above planned perf and fracture interval. Surface casing 10-3/4” cemented from shoe at 3560 ft was cemented to surface with a top job performed. With the Kuparuk plugged, 7-5/8” casing cement is cemented from plug to TOC (calculated as CBL not run) at 7741 ft. 4.5” tubing secured with a packer at 9017 ft. Packer set within cemented 7-5/8” portion. 7-5/8” casing (test to 3000 psi) and Kuparuk isolation plug (test to 2200 psi) before frac. MGR CDW 10/25/2024 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 10/24/2024 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing was set at 3560’ MD (-3,558’ TVD) and cemented with good returns at surface. For the original well P1-08, 9-7/8” hole was drilled from the base of surface casing set at 3560’ MD (-3560’ TVD) to total depth of 10,193’ MD (-8,693’ TVD). The mud log indicates good-quality oil shows were encountered in P1-08 below 9,150’ MD (-8,225’ TVDSS) and the top of the Stump sand is at 9,167’ MD (-8,238’ TVDSS). The 7-5/8” casing shoe was set at 10,193’ MD (8,693’ TVDSS) and cemented with 135 barrels of Class G 15.8 ppg. Assuming 40% washout, the estimated SFD 10/25/2024 MGR 10-25-24 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 October 28, 2024 top of cement is about 7,740’ MD (-7,145’ TVDSS). P1-08A was drilled out through the bottom of P1-08 and continued horizontally within the Kuparuk reservoir. So, the original cement surrounding the 7-5/8” casing isolates the Stump and Kuparuk hydrocarbon-bearing zones. (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3000 psi MITIA planned, 3000 psi MITT plan. CDW 10/22/2024 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 5K psi wellhead, 10K TreeSaver max. frac. pressure allowable 5275 psi. Pump knock out 4750-5015 and GORV 5275 psi., lines test 6275 psi. CDW 10/22/2024 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: Colville mudstones, shales, and siltstones that have an aggregate thickness of about 1,330’ true vertical thickness (TVT) underlain by the Stump Island siltstone and shale that is 11’ TVT. Fracture gradients are about 0.70 to 0.71 psi/ft (~13.5 ppg EMW). Fracturing Zone: Stump Island consisting of very fine- grained sandstone and siltstone is cemented. Fracture gradient expected to range from about 0.66 psi/ft (12.7 ppg EMW). Lower confining zones: HRZ Shale with an aggregate TVT of over 64’. Fracture gradient expected to range from about 0.70 psi/ft (13.5 ppg EMW). SFD 10/25/2024 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. Hilcorp has identified (and platted) 37 wells (including sidetracks) and identified 7 wells that transect the confining zone within ½ mile of P1-08A. For these 7 wells, Hilcorp has CDW 10/25/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 October 28, 2024 provided cementing review including TOC (CBL log) and zonal isolation - all showing isolation. Six wells within the AOR all display cement isolation of the Stump interval. For the seventh well, Pt McIntyre 1, the Ivishak, Shublik, Sag River, and Kuparuk are isolated by cement. In this well, the Stump Island interval is hydrocarbon-bearing (fair-quality mud log oil show), but the interval is likely not entirely covered by cement. However, the Stump intercept in Pt McIntyre 1 is located about 2,000' north of the intercept in P1-08A. Due to that separation it is highly unlikely that Pt McIntyre-01 will interfere with frac fluids in P1-08A. SFD 10/26/2024 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Two faults: The operator has identified two faults using seismic and well data within a ½-mile radius of P1-08A. This fault does not intersect P1-08 or Pl-08A, and it lies approximately 900’ from the proposed fracturing interval, and the modeled half-length of the induced fracture is 285’. It is unlikely that this fault will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 10/25/2024 (a)(12) Proposed program for fracturing operation Provided with application. CDW 10/22/2024 (a)(12)(A) Estimated volume Provided with application. 4053 bbl total dirty vol. 210K lb total proppant CDW 10/22/2024 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 10/22/2024 (a)(12)(C) Chemical name and CAS number of each Provided with application. Halliburton disclosure provided. Proprietary chemicals on file at AOGCC. CDW 10/22/2024 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 10/22/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 October 28, 2024 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 4000 psi. Max. 5275 psi allowable treating pressure. Max pressure is 4750 to 5015 psi to Pump shutdown. 5275 psi N2 POP off. With 2550 psi back pressure IA (IA popoff set 2850 psi), max tubing differential should be 2750 psi. CDW 10/22/2024 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 285’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 180’ (top TVD of about 8,255’ and base TVD of about 8,435), so induced fractures may penetrate a short distance into the overlying confining Colville confining layer that is about 1,300’ thick in this area. It may also penetrate into, but not through, the underlying HRZ shale that provides lower confinement. SFD 10/25/2024 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 10/22/2024 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 2550 psi back pressure, plan to test to 3000 psi, popoff set as 2850 psi CDW 10/22/2024 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing Proposed: 4.5” tubing will be anchored with a packer at 9017 ft with perforations planned for stump island zone 9250-9260 ft MD (reference log), and a cement plug on bottom. 7-5/8”cemented to 7741 ft (calculated TOC). CDW 10/22/2024 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3000 psi. Max pressure differential is estimated as 2725 psi (5275 with 2550 psi backpressure) so test of 3000 psi satisfies 110%. CDW 10/22/2024 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 6275 psi line pressure test, pump knock out 4750 and 5015 psi with max. global kickout 5275 psi. IA PRV set as 2850 psi. CDW 10/22/2024 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU P1-08A (PTD No. 202-199; Sundry No. 324-608) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 October 28, 2024 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 10/22/2024 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 2850 psi. Surface annulus open. Frac pressures continuously monitored. CDW 10/22/2024 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 10/22/2024 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). SFD 10/25/2024 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 10/25/2024 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU P1-08A Pull LTP Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-199 50-029-22384-01-00 12444 Conductor Surface Intermediate Production Liner 8764 80 3519 10156 3399 12408 20" 10-3/4" 7-5/8" 3-1/2" x 3-3/16" x 2-7/8" 8763 42 - 122 41 - 3560 37 - 10193 9045 - 12444 42 - 122 41 - 3554 37 - 8743 8197 - 8764 unknown 470 2480 5120 10540 none 1490 5210 8180 10160 11390 - 12370 4-1/2" 12.6# L-80 35 - 9088 8771 - 8762 Structural 4-1/2" TIW HBBP , 9017 , 8176 4-1/2" TRSV-4A , 2260 , 2260 9017 8176 Bo York Operations Manager Eric Dickerman Eric.Dickerman@hilcorp.com (907)564-5258 PRUDHOE BAY / PT MCINTYRE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028297 35 - 8229 452 323 21574 20781 32 12 1535 1690 2280 2331 N/A 13b. Pools active after work:PT MCINTYRE OIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 1:51 pm, Sep 27, 2024 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.09.26 15:16:52 - 08'00' Bo York (1248) DSR-9/27/24WCB 10-3-2024 RBDMS JSB B100324 ACTIVITYDATE SUMMARY 8/8/2024 ***WELL S/I ON ARRIVAL*** (Pull LTP) RAN FLAPPER CHECKER TO 4-1/2" TRCF-4A AT 2,260' MD (confirmed open) ***CONTINUE ON 8/9/24 WSR*** 8/9/2024 ***CONTINUED FROM 8/8/24 WSR*** (Pull LTP) RAN 4-1/2" BRUSH & 3.80" G. RING TO BKR KB LTP AT 9,045' MD JARRED ON BKR KB LTP AT 9,045' MD FOR 6 HRS (no movement) ***CONTINUE ON 8/10/24 WSR*** 8/10/2024 ***CONTINUED FROM 8/9/24 WSR*** (Pull LTP) JARRED ON BKR KB LTP AT 9,045' MD FOR 2 HRS (no movement) ***WELL S/I ON DEPARTURE*** 9/3/2024 LRS CTU #2 / 2.0" Tapered CS (0.134" wall) Blue Coil. Job Scope: Fish KB LTP MIRU CTU2. Function test BOPs. M/U Baker fishing BHA. RIH & Latch LTP @ 9018' CTM / 9036' Mech. 6 Jar Licks and LTP came free. Let Elements relax. PUH hung up in Sliding Slv. 4 jar licks and came free. POOH. Could not release Fish w/ 4" GS. Manually release GS. Recovered 4-1/2" KB LTP & seal assembly w/mule shoe guide. Missing center element off 4-1/2" KB packer. Discuss plan forward w/OE. FP tubing w/38 bbls diesel. RDMO CTU2. ***Job Completed*** 9/8/2024 ***WELL S/I ON ARRIVAL*** (Fish KB LTP) RAN 4-1/2" BLB, 3.69" 3-PRONG WIRE GRAB TO DEPLOYMENT SLEEVE @ 9,035' SLM RAN 3-1/2" BLB, 2.62" 2-PRONG WIRE GRAB TO DEVIATION @ 9,644' SLM ***WELL, LEFT S/I ON DEPARTURE, DSO NOTIFIED*** Daily Report of Well Operations PBU P1-08A () JARRED ON BKR KB LTP AT 9,045' MD FOR 2 HRS (no movement) RIH & Latch LTP @ 9018'g@ CTM / 9036' Mech. 6 Jar Licks and LTP came free. Let Elements relax. PUH hungg up in Sliding Slv. 4 jar licks and came free. POOH. Could not release Fish w/ 4" GS.gj Manually release GS. Recovered 4-1/2" KB LTP & seal assembly w/mule shoe guide. JARRED ON BKR KB LTP AT 9,045' MD FOR 6 HRS (no movement) 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: 8/13/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240813 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug BRU 232-04 50283100230000 162037 7/25/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/10/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/18/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/23/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/28/2024 AK E-LINE Hoist IRU 44-36 50283200890000 193022 8/3/2024 AK E-LINE CBL IRU 44-36 50283200890000 193022 7/31/2024 AK E-LINE CIBP IRU 44-36 50283200890000 193022 7/29/2024 AK E-LINE RCT MPU I-01 50029220650000 190090 7/20/2024 AK E-LINE CBL MRU M-02 50733203890000 187061 7/20/2024 AK E-LINE Plug PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL PBU V-220 50029233830000 208020 6/28/2024 READ InjectionProfileAnalysis PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey Please include current contact information if different from above. T39418 T39419 T39420 T39421 T39421 T39422 T39422 T39422 T39422 T39423 T39423 T39423 T39424 T39425 T39426 T39427 T39428 T39428 PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.13 13:58:22 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/06/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231206 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 13-8 50133203040000 177029 11/15/2023 HALLIBURTON EPX NCIU A-17 50883201880000 223031 11/28/2023 HALLIBURTON RBT PBU 04-46A 50029224340100 223082 11/1/2023 HALLIBURTON RBT PBU 05-26A 50029219840100 201221 11/24/2023 HALLIBURTON PPROF PBU 06-20B 50029207990200 223075 10/18/2023 BAKER MRPM PBU D-01A 50029200540100 197078 10/31/2023 HALLIBURTON RBT PBU N-07A 50029201370100 204105 10/7/2023 BAKER SPN PBU P1-08A 50029223840100 202199 9/22/2023 BAKER SPN PBU P2-56 50029226100000 195162 11/14/2023 BAKER SPN PBU P2-57A 50029221830100 202214 11/1/2023 BAKER SPN Please include current contact information if different from above. T38205 T38206 T38207 T38208 T38209 T38210 T38211 T38212 T38213 T38214 12/6/2023 PBU P1-08A 50029223840100 202199 9/22/2023 BAKER SPN Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.06 14:25:58 -09'00' PI2,t. Pi —c5 A • W P7)5 ?01-4910 Regg, James B (DOA) From: Cook, Guy D (DOA) 40116Sent: Monday, April 16, 2018 12:41 PM 1 To: Regg, James B (DOA) Subject: Fwd: PBU P1-08A Deficiency Report Attachments: PBU P1-08A Deficiency Report 4_15_18.pdf; ATT00001.htm; P1-08A WH sign needed; ATT00002.htm La • FYI: Thank you, Guy Cook SCAN NEV Sent from my iPhone Begin forwarded message: From: "AK, OPS FF Well Ops Comp Rep" <AKOPSFFWeIIOpsCompRep@bp.com> Date:April 16, 2018 at 12:32:15 PM AKDT To: "AK, OPS GPMA Field O&M TL" <AKOPSGPMAFieIdOMTL@bp.com>, "AK,OPS LPC DS Ops Lead" <AKOPSLPCDSOpsLead@bp.com> Cc: "AK, OPS FF Well Ops Comp Rep" <AKOPSFFWellOpsCompRep@bp.com>, "Cook, Guy D(DOA) (guy.cook@alaska.gov)" <guy.cook@alaska.gov> Subject: FW: PBU P1-08A Deficiency Report Richard I placed the order for the sign yesterday. When it is delivered to you, please arrange to have it installed onto the WH, then sign and date the deficiency report and return to the AOGCC Inspectors at aogcc.inspectorsCa7alaska.gov. Instructions are on the bottom of the report. Guy Cook gave us until 5/1/18 to have this corrected and closed out. That should be sufficient time since the signs usually arrive with 3-4 days once it has been ordered. If we need a time extension get with Vince and he can request one. Thanks Lee From: Cook, Guy D (DOA) [mailto:guy.cook@alaska.gov] Sent: Sunday, April 15, 2018 4:56 PM To: Hulme, Lee <Lee.Hulme@bp.com> Cc: Regg,James B (DOA)<jim.regg@alaska.gov> Subject: PBU P1-08A Deficiency Report Lee, Here is the deficiency report for P1-08A having the incorrect well identification sign. Please have the current sign replaced with a well identification sign with the proper information and then send in the report, and a picture of the sPinstalled on the well house, to the AOGCO the correct by date. Please remember to sign the deficiency report as well. If you have any questions please call Jim Regg. Thank you, Guy Cook Petroleum Inspector AOGCC 907-227-2614 guy.cook@alaska.gov 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 Guy Cook at 907-227-2614 or guy.cook@alaska.gov. 2 i • State of Alaska SPA- Oil and Gas Conservation Commission Deficiency Report Location: PBU P1-08A Date: 4/15/18 PTD: 2021990 Operator: gP Exploration Alaska Type Inspection: SVS Operator Rep: Lee Hulme Inspector: Guy Cook Position: Well Ops Compliance Op.Phone: 659-5332 Correct by(date): 5/01/18 Op. Email: lee.hulme@bp.com Follow Up Req'd: YES Detailed Description of Deficiencies Date Corrected Incorrect well identification sign on welihouse. Please refer to MC 25.040 of the Alaska Oil and Gas Laws and Regulations Attachments: Operator Rep Signatures: AOGCC Inspector *After signing,a copy of this fdrm is to be left with the operator. Follow-up Instructions Return a copy of this Deficiency Report to AOGCC(Attention:Inspection Supervisor)within 7 days of receipt. Include the"Date Corrected"and attach supporting documentation for each corrective action implemented to address the deficiencies. If a follow-up inspection was performed by AOGCC,include the date and name of Inspector. Extensions for corrective actions taking longer than the"correct be date must be requested and accompanied by justification(Attention:Inspection Supervisor).Documentation of deficiences that are outside of AOGCC regulatory jurisdiction will be forwarded to the appropriate authority for follow-up action. Revised 2/2016 i • Regg, James B (DOA) From: AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com> Sent: Sunday, April 15, 2018 4:44 PM To: Lastufka,Joseph N Cc: AK, OPS FF Well Ops Comp Rep; AK, OPS LPC DS Ops Lead Subject: P1-08A WH sign needed Joe Please order a wellhouse sign for well P1-08A and charge to ALSLPCOPER. Upon its arrival to the Slope, please have Tools Services notify Richard Faucett and have the sign delivered to: GPMA I Brent Reese/ Richard Faucett 1659-8642 184 - Butler Bldg Thank you, Lee Lee Hulme Well Ops Compliance Re BP Exploration (Alaska) Inc. Office: (907) 659-5332 Cell: (907) 229-5795 Harmony— 7187 (Alternate: Vince Pokryfki) 1 BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 January 1, 2010 Mr. Tom Maunder ~~`~"~ J~l~ 1 ~ ~~ iG Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 ~~ ~,. Subject: Corrosion Inhibitor Treatments of GPMA P1 Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from GPMA P1 that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) r Date 8/13/2009 Well Name PTD # API # Initial to of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al P1-o1 1900270 50029220180000 NA 0.2 NA 1.70 7/6/2009 P1-02A 2020650 50029217790100 NA 0.1 NA 0.90 7/8/2009 P1-03 '1890130 50029219120000 Cemented to flutes NA 0 NA 0.00 P1-04 1930630 50029223660000 NA 0.2 NA 1.70 7/8/2009 P1-05 '1930870 5002922378000D NA 0.2 NA 1.70 7/18/2009 P1-O6 '1961370 50029226950000 Sealed conductor NA NA NA NA P1-07A 2040370 50029219960100 SC Leak NA NA NA NA P1-08A 2021990 50029223840100 NA 1.2 NA 6.50 7/8/2009 P1-os '1961540 soo29227oaoooo NA 14.5 NA 141.10 7/9/loos P1-11 1920860 50029222840000 NA 0.2 NA 1.70 7/7/2009 P1-12 1910130 50029221340000 NA 0.6 NA 6.80 7/7/2009 P1-13 1930740 50029223720000 NA 1.5 NA 10.20 7/6/2009 P1-14 1930160 50029223380000 NA 1.5 NA 10.20 7/6/2009 P1-16 1930340 50029223490000 NA 0.7 NA 6.80 7/6/2009 P1-17 1930510 50029223580000 NA 1.7 NA 11.90 7/7/2009 P1-18A 2020760 50029229530100 NA 1.8 NA 8.50 7/7/2009 P1-20 1920940 50029222880000 NA 0.6 NA 3.40 9/12/2009 P1-21 1930590 50029223630000 NA 0.6 NA 5.10 7/7/2009 P1-23 1961240 50029226900000 NA 1.6 NA 13.60 7/7/2009 P1-24 1961490 50029227030000 NA 10 NA 107.10 12/13/2009 P1-25 1890410 50029219370000 Sealed conductor NA NA NA NA P1-G1 1921130 50029222980000 NA 0.2 NA 1.70 7/6/2009 e e WELL LOG TRANSMITTAL 90:J -/9q (. To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 Febmary 16, 2006 f~L/1/ RE: MWD Formation Evaluation Logs PI-08A, The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 907-273-3500 PI-08A: LAS Data & Digital Log Images: 50-029-22384-01 1 CD Rom ~ .~I ~9100 . . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Matker.doc :;2 7 J~ ). CJ\) \' DATA SUBMITTAL COMPLIANCE REPORT 1/6/2005 Permit to Drill 2021990 Well Name/No. PRUDHOE BAY UN PTM P1-08A Operator BP EXPLORATION (ALASKA) INC .Spud, :J.3 ~,~~~ API No. 50-029-22384-01-00 MD 12444-' TVD 8764 ~., Completion Date 12/27/2002"...--- Completion Status 1-01l Current Status 1-01l UIC N REQUIRED INFORMATION Mud log No Samples No Directional SurveN"'-'~'-Y;~;> ,c-.,.-......... DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: MWD, GR, Rap, CCl (data taken from logs Portion of Master Well Data Maint) Log/ Data Digital Type Med/Frmt ~. _.Rf>{" Electr Dataset Number Name c422 Gamma Ray Directional Survey ~" Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments 1 8890 12387 Open 2/14/2003 10810 12444 Open 1/9/2003 ---et> 0 ~ 1660 LIS Verification ~/ LIS Verification .rëD C Pdf ,..., 2422 Rate of Penetration /~D t./ C Lis .....,2422 Rate of Penetration 25 9525 12418 Open 4/29/2003 9525 12418 Open 4/29/2003 1-3 10900 12444 Open 2/26/2004 Rap, DGR - Horizontal Presentation - MWD 1-3 10900 12444 Open 2/26/2004 Rap, DGR - Horizontal Presentation - MWD Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments "'-'~ ADDITIONAL INFORMATION Well Cored? yß Daily History Received? Q/N ()/N Chips Received? - Y 1 N Formation Tops Analysis Received? .. Y 1 N''---- Comments: Permit to Drill 2021990 MD 12444 TVD 8764 Compliance Reviewed By: DATA SUBMITTAL COMPLIANCE REPORT 1/6/2005 Well Name/No. PRUDHOE BAY UN PTM P1-08A Operator BP EXPLORATION (ALASKA) INC Completion Date 12/27/2002 Completion Status 1-01L Current Status 1-01L UIC N ~~ ; Date: API No. 50-029-22384-01-00 ~.) JM-~~ S-- j - ~" ) ) ~Od-)q9 WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Howard Okland 333 West 7th Avenue, Suite 100 ~chorage, Alaska 99501 February 23, 2004 RE: MWD Formation Evaluation Logs: PI-08A, AK-MW-22204 PI-08A: Digital Log Images: 50-029- 22384-01 1 CD Rom J!)LI()~ PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF~ Sperry-Sun Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 BP Exploration (Alaska) Inc. Petro-technical Data Center LR2-1 900 E. Benson Blvd. ~chorage, Alaska 99508 Date: Signe~\:~~,-~~ RECEIVED FEB 2 6 2004 .,l.JJaska on & Gas Cons. Commission Anchorage ~ß~~~ ') ) c.;s 0;;)- /9 Cj I /000 WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Lisa Weepie 333 West 7th Avenue, Suite 100 Anchorage, Alaska April 17, 2003 RE: MWD FOffilation Evaluation Logs PI-08A, AK-MW-22204 1 LDWG fOffilatted Disc with verification listing. API#: 50-029-22384-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 BP Exploration (Alaska) Inc. Petro- T echnica1 Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date: Si~J1~ ./ RECe\VED APR 29 2.003 A\a8\œ ex. & Gai Coni. eommiIIIm AnfÌ\cn&Qð Jl Schlumberger Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Well P1-08A W-32A ~...Jqc:¡ ,;.y~-~ cfI Job# 23059 MGR 23060 MGR Log Description PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: RECEIVED FEB 1 4 2003 AIa8ka Oii & GIs Cons. CommIaeion Anchorage Date 12/26/02 01/03/03 Blueline 02/11/03 NO. 2653 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Sepia Color Prints ~ CD ~ Schlumberger GeoQuest 3940 Arctic Blvd I Suite 300 Anchorage, AK 99503-5711 :~~;, ~ ~ '.. ) ') STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Œa Oil D Gas D Suspended 0 Abandoned 0 Service 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface .[.~,. (:;jf\;"'."""':'¡a;,:'~r ~p :~e.~~~~~;:b1 :~~:~:~~~~:~~:M .,',',',", .A,,' J¡;;',:~t;,~,',Û1O.,.,' ".,.,'.,.., :: ::: ::::: At t~tal depth I J. _::Jttt,.-,,< ;, 2021 NSL,785 WEL, SEC. 15, T12N, R14E, UM'_''''''''''"'j,,,,, .'" X=679535, Y=5995275 5. Elevation in feet (indicate KB, OF, etc.) 6. Lease Designation and Serial No. KBE = 48.9' ADL 028297 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp., or Aband. 12/23/2002 " 12/25/2002 ; 12/27/2002 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey 12444 8764 FT 12408 8763 FT Œa Yes 0 No 22. Type Electric or Other Logs Run MWD, GR, Rap, CCL Deepen Classification of Service Well 7. Permit Number 202-199 8. API Number 50- 029-22384-01 9. Unit or Lease Name Point Mcintyre 10. Well Number P1-08A 11. Field and Pool Point Mcintyre 15. Water depth, if offshore 16. No. of Completions N/A MSL One 20. Depth where SSSV set 21. Thickness of Permafrost 2260' MD 1465' (Approx.) I GRADE H-40 NT -80 NT95HS L-80 L-80 CASING, LINER AND CEMENTING RECORD SETTING DEPTH HOLE Top BOTTOM SIZE CEMENTING RECORD Surface 80' 30" 270 sx Arcticset (Approx.) 41' 3546' 13-1/2" 2229 cu ft 'E', 406 cu ft Class 'G' 37' 10193' 9-7/8" 756 cu ft Class 'G' 10026' 10900' 6-3/4" Uncemented Slotted Liner 9045' 12444' 3-3/4" 230 cu ft Class 'G' 23. CASING SIZE WT. PER FT. 20" 91.5# 10-3/4" 45.5# 7-5/8" 29.7# 4-1/2" 12.6# 3-1/2" x 3-3/16" 9.3# /6.2# x 2-7/8" 6.16# 24. Perforations open to Production (MD+ TVD of Top and Bottom and interval, size and number) 2" Gun Diameter, 4 spf MD TVD 11390' - 11630' 8771' - 8770' 11650' - 11920' 8770' - 8770' 11960' - 12000' 8769' - 8768' 12200' - 12370' 8764' - 8762' 25. SIZE 4-1/2", 12.6#, L-80 MD TVD 26. AMOUNT PULLED TUBING RECORD DEPTH SET (MD) 9088' PACKER SET (MD) 9017' ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 2000' Freeze Protected with MeOH 27. Oate First Production January 1, 2003 Date of Test Hours Tested 1/26/2003 12.2 Flow Tubing Casing Pressure Press. 766 PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Gas Lift PRODUCTION FOR OIL-BBL TEST PERIOD 1 ,429 CALCULATED OIL-BBL 24-HoUR RATE GAs-McF 2,533 GAs-McF WATER-BBL -0- WATER-BBL CHOKE SIZE 20° OIL GRAVITY-API (CORR) GAS-OIL RATIO 1,773 CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submij C'''RTc No core samples were taken. 28. Form 10-407 Rev. 07-01-80 RODMS BF l Alaska OH& FEB 3 ¡~ ,- G~ Submit In Duplicate ) ) 29. Geologic Markers 30. Formation Tests Marker Name Measured Depth True Vertical Depth Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Lower Kuparuk Zone 81 9535' 8528' Lower Kuparuk Zone A 11 002' 8771' 31. List of Attachments: Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Terrie Hubble ~ ~jð& Title Technical Assistant Date '[) l' ~e .Q~ P1-08A 202-199 Prepared By Name/Number: Terrie Hubb/e, 564-4628 Well Number Permit No. I Approval No. Drilling Engineer: Mark Johnson, 564-5666 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 ) ) ARCED ~p~~êÎtiQn~...$;umìt1a.~..,..~e,p()~. Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: P1-08 P1-08 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Ft()rn~<TÖ . HôÜrs TaSk Côdé NPT Phase 12/21/2002 00:00 - 07:00 7.00 MOB P PRE 07:00 - 07: 15 0.25 MOB P 07:15 - 07:30 0.25 MOB P 07:30 - 08:00 0.50 MOB P 08:00 - 10:00 2.00 MOB P PRE PRE PRE PRE 10:00 - 12:00 12:00 - 17:30 2.00 BOPSUR P 5.50 BOPSUR P DECOMP DECOMP 17:30 - 21:15 3.75 BOPSUR P DECOMP 21:15 - 21:50 0.58 BOPSUR P DECOMP 21 :50 - 22:45 22:45 - 00:00 0.92 BOPSUR P 1.25 BOPSUR P DECOMP DECOMP 12/22/2002 00:00 - 01 :30 1.50 BOPSUR P DECOMP 01 :30 - 01 :45 01 :45 - 04:35 0.25 CLEAN P 2.83 CLEAN P DECOMP DECOMP 04:35 - 06: 15 1.67 CLEAN P DECOMP 06:15 - 08:30 2.25 CLEAN P DECOMP 08:30 -10:15 1.75 CLEAN P DECOMP 10:15 -12:30 2.25 CLEAN P DECOMP 12:30 - 12:45 0.25 CLEAN P DECOMP 12:45 - 13:00 0.25 STMILL P WEXIT 13:00 - 13:30 0.50 STMILL P WEXIT 13:30 - 15:40 2.17 STMILL P WEXIT Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 Spud Date: 12/21/2002 End: 12/27/2002 OØ$cti ptiqn()fqp~[atipn$ . Move Nordic 1 from F pad to Point Mac 1. Phase 1 weather conditions, 30 mph winds, blowing snow. Had rear tire leak. Repaired seal ring on tire twice. Position rig in front of well. S/I P1-09. P1-07 was already S/I. SAFETY MEETING. Review back in procedure, hazards and , mitigation. Very close well spacing, 15 ft. Back Nordic 1 over well. Very close on both sides. ACCEPT RIG AT 08:00 HRS, 12-21-2002. General rig up. Position tanks, trailers, heaters, hardline and berms. Nipple up BOPE. Perform initial BOPE Pressure / Function test. Testing witnessed by AOGCC inspecter, John Spaulding. Attempt to Press. test hardline to tiger tank, found ice plug in line. Thaw ice plug. PT hardline to 4000 psi. Pre spud Safety meeting. Attended by Rig Nordic and SWS crews, Sperry, Baker Oil Tools, Rig TP, BP Co Rep. Discuss well conditions, hazards from adjacent wells, and mitigation. Plan forward hazards and mitigation. Pull BPV. Pump KCL to kill well. 1700 psi on wellhead at start of kill. 5.0 bpm, 2800 psi at start of kill. Continue pumping KCL to kill well. WB volume=194 bbls. Shut down pumping after 300 bbls KCL and 200 bbls of flopro away. Final injection pressure 1200 psi at 6 bpm. Shut down pumping. Wellhead showing slight positive pressure. SI well at swab. Safety meeting prior to picking up milling BHA. Make up coil connecter. Pull test CTC to 30klbs. Fill coil with mud. PT CTC to 3500 psi, ok. Open swab valve to tree cap. 500 psi on well. Got mixed mud/gas returns. Do not have the well killed enough to rig up drilling BHA. Need to make cleanout run. Pick up nozzle, stinger, SWS MHA for cleanout run. MU injector. RIH with BHA #1, taking returns thru the choke and gas buster. Getting occasional gas back. Stop in horizontal hole for no flow check. No flow. Kick on pumps. Still getting gas cut mud back. Circulate bottoms up at 1.2 bpm. Still gassy returns. Circulate bottoms up again. 1.6 bpm. 9.3 PPG FloPro. Flow check. Well is dead. No gas in Returns. POH while circ. at 2.1 bpm. Flow check at surface. Well is dead. UO nozzle BHA. SAFETY MEETING. Review procedure, hazards and mitigation form BHA M/U. M/U HCC 3.77" Parabolic diamond mill, BKR straight motor, Circ sub, Hyd Disc, 1jt PH6, Bowen Up Jars, Hyd Disc, Chk valves and CTC. Total Length = 59.87'. RIH with BHA #2, 3.77" Diamond milling BHA. Circ 0.5 bpm. Ran thru XN Nipple at 9066' with no wt loss or motor work. Tagged Pack-off Bushing at 10899' CTD. Correct depth to 10,876'. [-23']. Printed: 1/2/2003 1 :29:45 PM ) ') ARCO .C).J>Øf~~iPI'1~.,.'~t.I(1'1~êiÌf'¥".'~~.PQn Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/22/2002 P1-08 P 1-08 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Pl"orl1'"To . Hours Task Code NPT Phase 15:40 - 17:30 1.83 STMILL P WEXIT 17:30 - 18:30 1.00 STMILL P WEXIT 18:30 - 19:30 1.00 STMILL P WEXIT 19:30 - 20:40 1.17 STMILL P WEXIT 20:40 - 21 :35 0.92 STMILL P WEXIT 21 :35 - 00:00 2.42 STMILL P WEXIT 0.67 STMILL P 12/23/2002 00:00 - 00:40 WEXIT 00:40 - 02:15 1.58 STMILL P WEXIT 02: 15 - 02:30 0.25 STMILL P WEXIT 02:30 - 02:45 0.25 DRILL P PROD1 02:45 - 03:30 0.75 DRILL P PROD1 03:30 - 05:25 1.92 DRILL P PROD1 05:25 - 05:45 0.33 DRILL P PROD1 05:45 - 06:30 0.75 DRILL P PROD1 06:30 - 08:00 1.50 DRILL P PROD1 08:00 - 09:00 1.00 DRILL P PROD1 09:00 - 09:30 0.50 DRILL P PROD1 09:30 - 10:15 0.75 DRILL P PROD1 10:15 -10:30 0.25 DRILL P PROD1 10:30 - 11 :00 0.50 DRILL P PROD1 11 :00 - 11 :30 0.50 DRILL P PROD1 Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 Spud Date: 12/21/2002 End: 12/27/2002 p~sçriptìÒIiQfG)Þ~réltiQ~§ Ease down and mill Pack-off Bushing at 0.5 FPH. 2.2 bpm, 2360- 2400 psi. Milled thru it in 30 min. Easy milling. Ream up and down OK. RIH to Guide Shoe. Tag at 10897.2'. Mill guide shoe. 0.5 FPH, 2.2.bpm, 2380 - 2410 psi. 2 light stalls to get started. Pump at 2.2 bpm to stay on low torque end of motor. 10897.4', Continuing to mill ahead very delicately. Little weight on bit and low motor work. CTP=2450 psi. Free spin 2.2/2.3/2380 psi. Pit volume=264 bbls. IAP=O, OAP=80 psi. 10898.1', CTP down to free spin. Does not look like any motor work at al\. May be thru guide shoe. Increase ROP until we get 200 psi motor work. Check cuttings sample. 100% formation sand, no meta\. Probably from open slotted liner perforations above guide shoe. 10899.0', Drilling break. Probably thru shoe. ROP now 25 fph. Continue to mill formation. 10910', Completed 10' of open hole, backream thru guide shoe to 10865'. No problems observed on backreaming trip. Dry drift down thru guide shoe. Hung up at 10899'. Kick pumps on, ream exit thru guide shoe again. Tried to dry drift again, and hung up 4' deeper at 100904'. Kick pumps on and work it some more. Continue to ream thru guide shoe. 2.2/2.2/2230 psi. Pit volume=257 bbls. IAP=O, OAP=105 psi. SSSV control panel 4200 psi and stable. Dry drift again, made it down then back up thru guide shoe, then hung up at packoff bushing at 10875'. Suspect a piece of junk may above us. Kick pumps on, ream down to TD and back to 10865'. SI pumps, dry drift down to TD and back to 10865' 2 times, with no problems. Finally got hole clean. POH to pick up drilling BHA. Tag up at surface. Lay down milling BHA. Mill recovered in gauge at 3.77", with very little sign of wear. Tool box talk prior to picking up first OH drilling BHA. Make up BHA #3, first OH drilling BHA. DPI 3.75" x 4.125" bi center bit, BH11.04 deg motor. Sperry GR-MWD package. RIH with BHA #3. Shallow hole test at 2000'. MWD and orienter worked properly. Continue RIH. Tag up at 10933' CTM. Set depth to last tag from milling run of 10910'. Kick on pumps to orient to 140R. 11510', Free spin 2.6/2.6/3300 psi. Begin drilling. Pit vol=250 bbls. IAP=O, OAP=95 psi. Drilling, 2.6/2.6 bpm, 3250 -3600 psi, 60 FPH, 82 deg incl, 112R TF. Drilled to 11,000'. Drilling, 2.6/2.6 bpm, 3250 -3600 psi, 60 FPH, 82 deg incl, 112R TF. Drilled to 11,038'. Wiper Trip. Clean hole up to window. No problem pulling BHA into liner. Pull up to 9580' for Tie-in. Log GR tie-in to formation at 9530'. Added 1 ft to CTD. RIH. Orient TF to 70 R. Drilling, 2.6 / 2.6 bpm, 3250 -3600 psi, 60 FPH, 82 deg incl, 70R TF. Drilled to 11,062'. Printed: 1/2/2003 1 :29:45 PM ) ) ARCO Qp~~~~~p~$...,.§~tQ~ar¡.'.'~~.Þøm Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 Spud Date: 12/21/2002 End: 12/27/2002 Legal Well Name: P 1-08 Common Well Name: P1-08 Event Name: REENTER+COMPLETE Contractor Name: NORDIC CALISTA Rig Name: NORDIC 1 [late 12/23/2002 11 :00 - 11 :30 0.50 DRILL P 11 :30 - 12:45 1.25 DRILL P 12:45 - 13:30 0.75 DRILL P 13:30 - 14:00 0.50 DRILL C 14:00 - 16:10 2.17 DRILL C 16:10 - 16:40 0.50 DRILL C 16:40 - 18:30 1.83 DRILL C 18:30 - 18:55 0.42 DRILL X 18:55 - 19:25 0.50 DRILL C 19:25 - 20:30 1.08 DRILL C 20:30 - 22:25 1.92 DRILL C 22:25 - 00:00 1.58 DRILL C 12/24/2002 00:00 - 00:55 0.92 DRILL C 00:55 - 01 :05 0.17 DRILL C 01 :05 - 02: 1 0 1.08 DRILL P 02: 1 0 - 02:25 0.25 DRILL P 02:25 - 03:45 1.33 DRILL P 03:45 - 03:55 0.17 DRILL P 03:55 - 04:05 0.17 DRILL P 04:05 - 04:30 0.42 DRILL P 04:30 - 05:35 1.08 DRILL P 05:35 - 05:45 0.17 DRILL P 05:45 - 07:00 1.25 DRILL P 07:00 - 07:30 0.50 DRILL P 07:30 - 08:30 1,00 DRILL P 08:30 - 09:30 1.00 DRILL P 09:30 - 10:45 1.25 DRILL P 10:45 - 11 :30 0.75 DRILL P 11 :30 - 12:00 0.50 DRILL P 12:00 - 12:20 0.33 DRILL P 12:20 - 13:30 1.17 DRILL P 13:30 - 14:10 0.67 DRILL P 14:10 - 14:40 0.50 DRILL P 14:40 - 15:00 0.33 DRILL P 15:00 - 16:00 1.00 DRILL P PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 GR shows hotter shale than expected. Geo requested we circ bottoms up to check sample. Circulate bottoms up for Geo sample. Drilling, 2.6 / 2.6 bpm, 3250 -3600 psi, 60 FPH, 80 deg incl, 70R TF. Drilled to 11,097'. Still in the same shale, 120 GR API. 95 ft MD in shale, Circulate bottoms up for Geo sample. Determine we are in LA sand which is 21-22 ft thick. Need a strong bend motor to land well above shale. POH for high bend motor to land well as soon as possible. At surface. Adjust motor to 2.57 deg bend. Bit still in new condition. Check orienter OK. RIH with Build MWD BHA #4, 2.57 deg motor and DPI bi-center bit #4. Wait for driller to repair shaker screens. Orient 20R. 11097', Resume drilling. Drilling straight high side with a 2.57 deg motor to drill up back into the target sand. 11147',95 deg inc at bit, POH for 1 deg motor. Tag up at surface, change motor bend back to 1.04 deg. Continue RIH with BHA #5 to resume drilling lateral section. Orient to 90R. Resume drilling. Free spin=3550 psi. 2.8/2.8/3700 psi. ROP=85 fph. Pit vol=220 bbls. IAP=O, OAP=125, SSSV gauge pressure=4500 psi. 11210', Pick up to orient. Resume drilling. Pit volume=217 bbls. ROP=50 fph. 3 clicks. Resume drilling. 2.8/2.8/3850 psi. TF=67R, INC=93.9, still trying to build up out of LA sand. 11300', Wiper trip to shoe. Resume drilling. 2.8/2.8/3680 psi. Orient to left side turn. Resume drilling. 2.8/2.8/3750 psi. 96 deg Incl. Drilling break at 11385'. 100 FPH. Drilled to 11400'. 8720' TVDSS. Shoe was at 8711' TVDSS. Drilling, 2.6/2.6 bpm, 3300 - 3800 psi, 120 FPH, 93.5 deg Incl. Drilled to 11450'. Wiper trip to shoe. Clean hole. RIH to TD. Drilling, 2.6/2.6 bpm, 3300 - 3800 psi, 120 FPH, 80L,90 deg Incl. Drilled to 11,500'. Drilling, 2.6 / 2.6 bpm, 3300 - 3800 psi, 120 FPH, 80L, 89 deg Incl. Drilled to 11,600'. Wiper trip to window. Clean hole. RIH to TD. Drilling, 2.6/2.6 bpm, 3300 - 3800 psi, 100 FPH, 60L,89 deg Incl. Drilled to 11,657'. Orient around. Drilling, 2.6/2.6 bpm, 3300 - 3800 psi, 120 FPH, 60L,90 deg Incl. Drilled to 11,750'. Wiper trip to window. Clean hole. Wiper trip up to 9575'. Log Tie-in with GR at 9532 ft. [-1 ft CTD]. RIH to TD. Swap to new FloPro System. Drilling, 2.5/2.5 bpm, 3200-3600 psi, 111 FPH, 60L, 90.40 deg Printed: 1/2/2003 1 :29:45 PM ) ') ARGO Q,p~~,~~~g~~~.~m~ry'R.epqrt Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: [)$ite 12/24/2002 12/25/2002 P 1-08 P1-08 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Spud Date: 12/21/2002 End: 12/27/2002 Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 From-To . HoUrs Task Cddê NPT Phase P~sçript¡on".pfQp~rati.dn$ 15:00 - 16:00 1.00 DRILL P PROD1 Incl, Drilled to 11840 16:00 - 16:30 0.50 DRILL P PROD1 Drilling, 2.6/2.6 bpm, 3300-3900 psi, 105 FPH, 36L, 89.4 Deg Incl, Drilled to 11900 16:30 - 17:20 0.83 DRILL P PROD1 Wiper trip to window. Clean hole. Wiper trip up to 1 0900'md. 17:20-18:10 0.83 DRILL P PROD1 Drilling, 2.6/2.6 bpm, 3500-3900psi, 120-190FPH, 91deg Incl, Drill to 12050' (8716' TVD) 18:10 - 20:45 2.58 DRILL P PROD1 Wiper trip up to tie-in at 9532', subtract 5.0' 20:45 - 21 :25 0.67 DRILL P PROD1 Drill from tag at 12050' 2.5/2.5/3450/55120R holding 92 deg PVT 232. Drill to 12126' 21 :25 - 21:45 0.33 DRILL P PROD1 Orient around 21 :45 - 22:20 0.58 DRILL P PROD1 Drill from 12126' 2.5/3400/70R holding 91 deg PVT 227. Drill to 12200' 22:20 - 23:30 1.17 DRILL P PROD1 Wiper to shoe 23:30 - 00:00 0.50 DRILL P PROD1 Drill from 12200' 2.5/3400/70R holding 91 deg. Drill to 12260' (8714' TVD) 00:00 - 01 :00 1.00 DRILL P PROD1 Drill from 12260' 2.5/3400/55R holding 91 deg. Drill to 12350' 01 :00 - 02:15 1.25 DRILL P PROD1 Wiper to shoe 02:15 - 03:00 0.75 DRILL P PROD1 Drill from 12350' 2.5/3400/70R Drill to 12434' (temp TD, will TD at 12444') 03:00 - 03:15 0.25 DRILL P PROD1 Wiper to window 03:15 - 05:10 1.92 DRILL N SFAL PROD1 Park at 11804', circ at min rate 0.6/1285. Work on rig power problem-lost a transformer. Boilers down, drain lines 05:10 - 06:05 0.92 DRILL P PROD1 Repairs finished. Resume wiper to tie-in 06:05 - 06:20 0.25 DRILL P PROD1 Log tie-in from 9570' logging up, corr -1' 06:20 - 07:10 0.83 DRILL P PROD1 RIH Clean 07: 1 0 - 07:25 0.25 DRILL P PROD1 Tag TD at 12431'md. Drill to TD of 12444'. "*','" 07:25 - 08: 15 0.83 DRILL P PROD1 Backream at 30fpm 2.5 bpm out of hole. Hole is clean. 08:15 -10:15 2.00 DRILL P PROD1 Inside 4-1/2" slotted POH at 60fpm, pumping 2.6bpm. Flag pipe @ 9000' (47.09' off TD), 7450'md (53.09' above slotted liner exit). 10:15 - 10:35 0.33 DRILL P PROD1 PJSM: Discuss laying down tools, pinch points, beaver slide is off limits. 10:35 - 11 :45 1.17 DRILL P PROD1 LD drilling assembly. Prep to run liner. 11 :45 - 12:30 0.75 CASE P COMP PJSM: Discuss plan forward with team for running liner. Emphasive good communication. 12:30 - 17:45 5.25 CASE P COMP PU liner. TIW float shoe, 1 float jt., TIW float collar, Baker Latch collar, 33 jts 2-7/8" STL, 10' 2-7/8" STL PUP, 15 jts 2-7/8" STL, 3-3/16" XO 2-7/8",48 Jts 3-3/16" TCII, 3-1/2" XO 3-3/16", 14 jts 3-1/2" STL, XN nipple, 3-1/2" PUP, 3-1/2" PUP, Deployment sleeve, CTLRT. Cementrolizers on every joint of 2-7/8". Fill liner at half way point. 17:45 - 18:45 1.00 CASE P COMP Cut 22' CT. MU new Baker CTC. Pull test, Pressure test. 18:45 - 20:05 1.33 CASE P COMP RIH w/liner on CT 20:05 - 20:30 0.42 CASE P COMP 10900' 41k, 21k RIH thru shoe to TD w/ nary a bobble and tag at 12457' CTD. Recip 35' at 51.5k to ball drop point 20:30 - 21 :05 0.58 CASE P COMP Load 5/8" steel ball and displace to seat 2.6/2.6/2760, 0.8/0.8/1340 w/ mud. Ball seat sheared at 4050 psi. PUH and released at 35k 21 :05 - 21 :50 0.75 CASE P COMP Circ 1.1/1.1/1500 while wo vac trucks. MIRU DS cementers 21 :50 - 23:25 1.58 CASE P COMP Displace 9.3# mud w/ 9.3# 3% KCIINaCI 2.9/2.9/2850. Got bottoms up gas in returns Safety mtg re: cementing Batch up cement. Cmt to wt at 2315 hrs Printed: 1/2/2003 1 :29:45 PM ') ) AReo Øp'tà:tibl1~ .',$Lll11tmi:ttJR,pp:r::t . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: P1-08 P 1-08 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 !YoUrs Task Code NPT Phase 12/25/2002 23:25 - 23:50 0.42 CEMT P COMP 23:50 - 00:00 12/26/2002 00:00 - 00:35 0.17 CEMT P 0.58 CEMT P COMP COMP 00:35 - 02:00 1.42 CASE P COMP 02:00 - 02:30 0.50 CASE P COMP 02:30 - 02:40 0.17 EVAL P COMP 02:40 - 05: 10 2.50 EVAL P COMP 05:10 - 06:10 1.00 EVAL P COMP 06:10 - 08:15 2.08 EVAL P COMP 08:15 - 09:15 1.00 EVAL P COMP 09: 15 - 09:30 0.25 EVAL P COMP 09:30 -11:15 1.75 EVAL P COMP 11 :15 - 12:45 1.50 EVAL P COMP 12:45 - 13:30 0.75 EVAL P COMP 13:30 - 15:30 2.00 PERF P COMP 15:30 - 16:30 1.00 CASE N WAIT COMP 16:30 - 17:30 1.00 CASE P COMP 17:30 - 18:55 1.42 CASE P COMP 18:55 - 19:50 0.92 CASE N SFAL COMP 19:50 - 20:00 0.17 CASE N COMP 20:00 - 20:30 0.50 CASE P COMP 20:30 - 22:00 1.50 CASE P COMP Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 Spud Date: 12/21/2002 End: 12/27/2002 [:)~$criþtiÞnÒf..Øp~rati~ns Displacement completed. PT OS @ 3500 psi. Load CT wI 41 bbls 15.8 ppg G (expandable) cement wI latex 2.5/2.5/2480 Load wiper dart. Displace dart and verify gone Displace dart with 9.3# KCI/NaCI 3.0/3.0/2560. Dart latched LWP at calc displ. Displace LWP to latch collar 2.6/2.6/2440 and bumped at calc displ to 1500 psi. Unsting at 35k. CIP 0035 hrs 12/26/02 Full returns thruout, 40+ bbls around shoe POOH filling hole at 1.2 bpm (as requested to minimize ECD's) LD CTLRT Safety mtg re: CSH/memory tool MU 2.3" mill on 2.125" motor. MU SWS memory GR/CCL in carrier, MHA MU 50 stds and 10 singles of CSH workstring RIH wI BHA #6 Log down from 8900' at 60'/min while circ perf pill to bit. Tag TO. Log up at 60ftlmin laying in 14bbl high vis perf pill. POH wI BHA #6 PJSM: Discuss standing back hydril. Review job tasks. Stand back injector, unstab, Drop ball to open circ sub below hydril, stand back 55 stands of CS Hydril. (Dowell: 1500psi compressive strength on cement @1 0:00) Wait on cement to reach 2000psi compressive strength. Download memory GR/CCL data. PT liner lap to 2000psi. Lost 900psi in 15min. Check surface lines, double blocked, pumps isolated. Re-test liner lap. Lost 1000psi in 15min. Order out Liner top packer. Load perf guns into pipe shed, while waiting on liner top packer to arrive. Wait on 4' extension for liner top packer. Continue to troubleshoot liner lap leak. IA on vacuum, call out crew to shoot IA fluid level. PU liner top packer with 4' space-out extension. RIH with BHA #7. DHD sonolog found IA FL @ 96' Park at 8150' to repair levelwind pall Continue RIH 32.3k, 20k @ 9000' See stinger enter Deployment Sleeve at 9067' CTD at 17k (verify wI CT press incr), stack 10k at 9074'. Pull back to neutral at 9068.9', then additional 2.5' to 9066.4'. Check lap for leak. Press up on BS to 2000 psi w/1.5 bbls and lost 500 psi in 5 min (no change to IA). Bleed off press. Check new liner for leak. PT down CT to 1000 psi and no loss in 5 min. Bleed off press. Unsting and PUH 33k to ball drop at 9050' Load 5/8" steel ball. Circ to seat wI KCI 2.1/2.1/1450, 0.5/130. Bleed off press. Sting back in with ball on seat. Pull back to neutral, then additional 2' to 9066.8'. Check BS again to 2000 psi Gust because) to be sure seals stung in and no change to CT press. Bleed off press. Press CT to 2500 psi and set L TP. PUH 10k to verify set. Stack wt to verify. Bleed off CT press Press BS to 2000 psi w/1.0 bbl and monitor 5 min wI 50 psi loss to coil (leaking isolation valve), no change to IA. Bleed off press. Printed: 1/2/2003 1 :29:45 PM ) ) ARGO Øp~~~ti()ns .$l;IlTImaJYff~p~()rt Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: P 1-08 P 1-08 REENTER+COMPLETE NORDIC CALISTA NORDIC 1 Date Frbm''-Td HÖurs Task Cbde NPT Phásé 12/26/2002 20:30 - 22:00 1.50 CASE P COMP 22:00 - 23:00 1.00 CASE P COMP 23:00 - 23:30 0.50 CASE P COMP 23:30 - 23:45 0.25 PERF P COMP 23:45 - 00:00 0.25 PERF P COMP 12/27/2002 00:00 - 01 :50 1.83 PERF P COMP 01 :50 - 03:00 1.17 PERF P COMP 03:00 - 04:35 1.58 PERF P COMP 04:35 - 05:20 0.75 PERF P COMP 05:20 - 06:40 1.33 PERF P COMP 06:40 - 06:55 0.25 PERF P COMP 06:55 - 07:10 0.25 PERF P COMP 07:10 - 09:10 2.00 PERF P COMP 09:10 - 09:20 0.17 PERF P COMP 09:20 -12:15 2.92 PERF P COMP 12:15 - 13:05 0.83 CLEAN P COMP 13:05 - 16:45 3.67 CLEAN P COMP 16:45 - 17:00 0.25 CLEAN P COMP 17:00 - 18:30 1.50 RIGD P COMP 18:30 - 20:00 1.50 RIGD P COMP 20:00 - 22:00 2.00 RIGD P COMP 22:00 - 00:00 2.00 RIGD P COMP Start: 12/21/2002 Rig Release: 12/27/2002 Rig Number: N1 Spud Date: 12/21/2002 End: 12/27/2002 fl)es~riþtiônof Oþeratiqô$ Press CT to shear ball seat at 3700 psi. PUH 33k and release from L TP. Top of L TP at 9045.4' CTD (or 9034.8' ELMD) which is just above SWS nipple POOH LD L TP setting tool Safety mtg re: perf guns RU to run perf guns. MU guns MU 47 SWS 2" Powerjet guns and blanks MU 39 stds CSH RIH wI CT. Tag at 12404' CTD. Corr to 12405' ELMD. PUH 38k to ball drop point Pump 8 bbls fresh mud. Load 5/8" steel ball and displace KCI. Circ to seat with guns on depth 2.0/3600, 0.9/800. PVT 289 Ball seat sheared at 3050 psi. Lost all returns initially, then gradually healed to 0.5 bpm losses while PUH 39k. After guns were above perf interval had nearly full returns. POOH Perforated wI 2" PowerJet guns 4 spf 11390-11630' 11650-11920' 11960-12000' 12200-12370' PJSM, discuss keeping hole full while pulling Hydril, monitoring well for flow at surface, pinch points and body positioning. Line up returns thru manifold, fill stack, shut down and monitor WHP. No change in WHP over 15min. Stand back 39 stands CS Hydril PJSM on LD spent guns with Schlumberger TCP specialist. Beware of trapped pressure, fluid leaking from guns, burrs on guns. LD 47 spent perf guns. PU stinger and nozzle, stab CT, close swab, PT stack to 3500psi. RIH with nozzle to liner top, tag at 9047'md. Swap tubing to 3%KCL, with driller on choke. Freeze protect 2000' with Methanol. Trap 650psi on well head. Unstab CT, stand back injector, LD nozzle. Set BPV with DSM lubricator. WHP 320 psi MIRU DS N2 Displace CT wI N2 and bleed off press ND BOPE. NU tree cap and test Rig Released at 2200 hrs 12/7/02 Move to V-03 Remove lubricator and top of Hydril flange to send to shop for breakout (can't break Otis union). DS mechanics remove ODS reel drive plate for repairs Safety mtg re: move off well. DSO SI P1-09 Move off P1-08 and park at entrance to Pad. Clean up location and inspect. Safety mtg re: move to V-03 wI support personnel Printed: 1/2/2003 1 :29:45 PM ') ) aO;)-/91 31-Dec-02 AOGCC Lisa Weepie 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 DEFINITIVE Re: Distribution of Survey Data for Well P1-08A Dear Dear Sir/Madam: Enclosed are two survey hard copies. Tie-on Survey: Window / Kickoff Survey Projected Survey: 10,810.00' MD 'MD (if applicable) 12,444.00' MD Please call me at 273-3545 if you have any questions or concerns. Regards, William T. Allen Survey Manager Attachment( s) RECEIVED JAN 0 9 2003 AIa8k8 Oit & Gas Cons. Commi88ion Anchcnge Sperry-Sun Drilling Services North Slope Alaska BPXA Point Mcintyre Pad 1 P1-0BA Job No. AKMW22204, Surveyed: 25 December, 2002 Survey Report 3 January, 2003 Your Ref: API 500292238401 Surface Coordinates: 5994573.44 N, 674317.88 E (70023' 27.0790" N, 148034'54.6033" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Surface Coordinates relative to Project H Reference: 994573.44 N, 174317.88 E (Grid) Surface Coordinates relative to Structure Reference: 96.95 S, 315.71 E (True) Kelly Bushing: 48.90ft above Mean Sea Level Elevation relative to Project V Reference: 48.90ft Elevation relative to Structure Reference: 48.90ft spe""""Y-!5ul! DFtILLING SERVices A Halliburton Company D EF\ ""'.V: ~ ~ Survey Ref: svy11422 Sperry-Sun Drilling Services Survey Report for Point Mcintyre Pad 1 - P1-08A Your Ref: API 500292238401 Job No. AKMW22204, Surveyed: 25 December, 2002 BPXA North Slope Alaska Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (O/100ft) 10810.00 86.800 110.800 8705.63 8754.53 1380.53 N 3853.82 E 5996043.44 N 678138.47 E 2647.24 Tie On Point-Drill out End of P1-m MWD Magnetic 10900.00 86.800 110.800 8710.65 8759.55 1348.62 N 3937.82 E 5996013.50 N 678223.19 E 0.000 2735.95 10924.25 84.990 113.940 8712.39 8761.29 1339.41 N 3960.19 E 5996004.82 N 678245.76 E 14.916 2759.92 10955.80 83.260 115.280 8715.62 8764.52 1326.34 N 3988.72 E 5995992.42 N 678274.59 E 6.922 2791.16 10992.93 80.440 119.160 8720.89 8769.79 1309.54 N 4021.40 E 5995976.38 N 678307.65 E 12.832 2827.86 ~ 11027.48 79.820 123.030 8726.81 8775.71 1291.97 N 4050.54 E 5995959.49 N 678337.19 E 11 . 180 2861.88 11057.55 80.350 127.080 8731.99 8780.89 1274.96 N 4074.78 E 5995943.05 N 678361.83 E 13.384 2891.38 11093.78 80.970 127.440 8737.87 8786.77 1253.31 N 4103.23 E 5995922.08 N 678390.78 E 1.972 2926.85 11141.10 93.570 131.310 8740.12 8789.02 1223.39 N 4139.68 E 5995893.01 N 678427.92 E 27.847 2973.38 11170.75 93.920 134.310 8738.18 8787.08 1203.28 N 4161.39 E 5995873.42 N 678450.08 E 10.165 3002.22 11200.80 91.280 138.710 8736.82 8785.72 1181.51 N 4182.04 E 5995852.13 N 678471.24 E 17.062 3031.00 11234.00 92.250 138.540 8735.80 8784.70 1156.61 N 4203.97 E 5995827.75 N 678493.74 E 2.966 3062.44 11264.88 94.980 136.070 8733.85 8782.75 1133.96 N 4224.87 E 5995805.59 N 678515.16 E 11.911 3091.86 11293.60 96.040 136.070 8731.09 8779.99 1113.37 N 4244.70 E 5995785.47 N 678535.47 E 3.691 3119.33 11326.80 97.000 141.530 8727.32 8776.22 1088.57 N 4266.42 E 5995761.18 N 678557.76 E 16.593 3150.54 11366.63 93.740 138.360 8723.59 8772.49 1058.22 N 4291.93 E 5995731.44 N 678583.97 E 11.391 3187.81 11420.93 93.830 135.720 8720.01 8768.91 1018.58 N 4328.85 E 5995692.66 N 678621.81 E 4.854 3239.61 11459.98 90.930 134.840 8718.38 8767.28 990.86 N 4356.30 E 5995665.59 N 678649.90 E 7.760 3277.24 11508.88 88.550 131.840 8718.61 8767.51 957.30 N 4391.86 E 5995632.87 N 678686.23 E 7.831 3324.81 11569.66 88.370 129.200 8720.24 8769.14 917.83 N 4438.04 E 5995594.49 N 678733.32 E 4.352 3384.55 11597.83 88.990 126.730 8720.89 8769.79 900.51 N 4460.25 E 5995577.69 N 678755.92 E 9.038 3412.43 11630.85 89.250 125.320 8721.40 8770.30 881.09 N 4486.95 E 5995558.90 N 678783.07 E 4.342 3445.27 '~ 11661.46 89.780 124.090 8721.66 8770.56 863.66 N 4512.11 E 5995542.06 N 678808.63 E 4.375 3475.77 11702.30 90.480 121.090 8721.56 8770.46 841.67 N 4546.52 E 5995520.88 N 678843.54 E 7.543 3516.56 11753.25 90.31 0 117.920 8721.21 8770.11 816.58 N 4590.85 E 5995496.83 N 678888.45 E 6.231 3567.51 11793.30 90.570 115.630 8720.90 8769.80 798.54 N 4626.60 E 5995479.63 N 678924.61 E 5.754 3607.49 11830.46 89.160 111.580 8720.99 8769.89 783.66 N 4660.65 E 5995465.55 N 678958.99 E 11.540 3644.41 11866.33 89.960 109.820 8721.27 8770.17 770.98 N 4694.20 E 5995453.66 N 678992.83 E 5.390 3679.80 11938.33 90.930 105.760 8720.71 8769.61 748.99 N 4762.74 E 5995433.27 N 679061.86 E 5.797 3750.16 11981.93 91.890 102.420 8719.63 8768.53 738.38 N 4805.01 E 5995423.65 N 679104.37 E 7.968 3792.07 3 January, 2003 - 14:03 Page 20f4 DrillQuest 3.03.02.004 Sperry-Sun Drilling Services Survey Report for Point McIntyre Pad 1 - P1-08A Your Ref: API 500292238401 Job No. AKMW22204, Surveyed: 25 December, 2002 BPXA North Slope Alaska Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 12019.96 92.250 99.420 8718.26 8767.16 731.18 N 4842.32 E 5995417.32 N 679141.84 E 7.940 3827.98 12060.00 93.390 99.600 8716.29 8765.19 724.57 N 4881.76 E 5995411.63 N 679181.42 E 2.882 3865.44 12094.33 91.720 101.530 8714.76 8763.66 718.29 N 4915.47 E 5995406.13 N 679215.27 E 7.430 3897.78 12121.30 89.160 102.770 8714.55 8763.45 712.61 N 4941.83 E 5995401.07 N 679241.76 E 10.547 3923.45 12158.55 89.160 106.290 8715.10 8764.00 703.27 N 4977.88 E 5995392.57 N 679278.01 E 9.449 3959.34 12194.10 90.750 107.700 8715.13 8764.03 692.88 N 5011.88 E 5995382.98 N 679312.24 E 5.978 3993.98 -- 12231.78 91.100 110.340 8714.52 8763.42 680.60 N 5047.49 E 5995371.53 N 679348.13 E 7.067 4030.96 12266.88 91.110 114.450 8713.84 8762.74 667.23 N 5079.93 E 5995358.93 N 679380.88 E 11.707 4065.74 12316.48 90.310 118.270 8713.23 8762.13 645.22 N 5124.36 E 5995337.95 N 679425.81 E 7.868 4115.22 12347.98 89.520 120.390 8713.27 8762.17 629.79 N 5151.83 E 5995323.17 N 679453.62 E 7.182 4146.72 12384.25 89.160 122.680 8713.69 8762.59 610.82 N 5182.73 E 5995304.93 N 679484.96 E 6.391 4182.97 12418.25 88.900 124.620 8714.27 8763.17 591.98 N 5211.03 E 5995286.75 N 679513.69 E 5.756 4216.89 12444.00 88.900 124.620 8714.76 8763.66 577.36 N 5232.22 E 5995272.63 N 679535.22 E 0.000 4242.56 Projected Survey All data is in Feet (US) unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well Reference. Northings and Eastings are relative to Well Reference. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4. The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from Well Reference and calculated along an Azimuth of 120.000° (True). Magnetic Declination at Surface is 26.115°(21-Dec-02) Based upon Minimum Curvature type calculations, at a Measured Depth of 12444.00ft., The Bottom Hole Displacement is 5263.98ft., in the Direction of 83.703° (True). '~ 3 January, 2003 - 14:04 Page 3 0'4 Dri/lQuest 3.03.02.004 Sperry-Sun Drilling Services Survey Report for Point McIntyre Pad 1 - P1-0BA Your Ref: API 500292238401 Job No. AKMW22204, Surveyed: 25 December, 2002 BPXA North Slope Alaska Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) Comment 10810.00 12444.00 8754.53 8763.66 1380.53 N 577.36 N 3853.82 E 5232.22 E Tie On Point-Drill out End of P1-08 Projected Survey ~ Survey tool program for P1-0BA From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth (ft) (ft) Survey Tool Description 0.00 10810.00 0.00 10810.00 8754.53 12444.00 8754.53 AK-3 BP _HM - BP High Accuracy Magnetic(P1-08PB1) 8763.66 MWD Magnetic(P1-08A) '~ 3 January, 2003 - 14:04 Page 4 of4 Dril/Quest 3.03.02.004 1 a. Type of work D Drill B Redrill D Re-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1443' NSL, 738' WEL, SEC. 16, T12N, R14E, UM At top of productive interval 3058' NSL, 3343' WEL, SEC. 15, T12N, R14E, UM At total depth 2030' NSL, 785' WEL, SEC. 15, T12N, R14E, UM 12. Distance to nearest property line 13. Distance to nearest well / ADL034624, 785' MD No Close Approach 16. To be completed for deviated wells Kick Off Depth 10900' MD Maximum Hole Angle 18. Casin~ Program Specifications Size Hole Casino Weiaht Grade CouDlina 3-3/4" 3-3/16" x 6.2# L-80 TC11 2-7/8" 6.16# L-80 ST-L STATE OF ALASKA ALASKAc~_l AND GAS CONSERVATION COMM. )ION PERMIT TO DRILL 20 AAC 25.005 1 b. Type of well D Exploratory D Stratigraphic Test II Development Oil D Service D Development Gas D Single Zone D Multiple Zone 5. Datum Elevation (OF or KB) 10. Field and Pool KBE = 48.9' Point Mcintyre 6. Property Designation ADL028297 7. Unit or Property Name Point Mcintyre 8. Well Number /' P1-08A 9. Approximate spud date 10-05-02 / Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 12425' MD I 8745' TVD 17. Anticipated pressure {see 20 MC 25.035 (e) (2)} 91 0 Maximum surface 3306 P;ig, At total depth (TVD) 8740' I 4180 psig Setting Depth T OD Bottom Lenath MD TVD MD TVD 2345' 9055' 8155' 11400' 8749' 1425' 11400' 8749' 12425' 8745' it-/()A- q{!iJ(Oi.... ~!:P ~(3f//~ ~ 11. Type Bond (See 20 AAC 25.025) Number 2S100302630-277 Quantitv of Cement (include staae data) 118 cu ft Class 'G' Uncemented Slotted Liner 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Su rface Intermediate Production Liner 1 0900 feet 8759 feet 1 0900 feet 8759 feet Length Plugs (measured) Junk (measured) Size Cemented MD TVD 110' 20" 3505' 10-3/4" 10156' 7-5/8" 874' 4-1/2" 270 sx Arcticset (Approx.) 2229 cu ft 'E', 406 cu ft 'G' 110' 3546' 110' 3540' 756 cu ft Class 'G' Uncemented Slotted Liner 10193' 8742' 10026' - 10900' 8729' - 8759' true vertical RleEfVED SEP 2 4\ 2002 AlasKaOlla Gal Ions. GoßII1dI8Ion B Filing Fee D Property Plat II BOP Sketch D Divertepg~ Drilling Program B Drilling Fluid Program D Time vs Depth Plot D Refraction Analysis D Seabed Report D 20 AAC 25.050 Requirements Slotted Liner: 10084' - 10900' Perforation depth: measured Slotted Liner: 8737' - 8759' 20. Attachments Contact Engineer Name/Number: Mark Johnson, 564-5666 Prepared By Name/Number: Sondra Stewman, 564-4750 21. I hereby certify that t~, ",e" ' oreg, Oing", i,S t, ~~,u, ,,' ",and ~rre~t n, ' O,r, ,r" e""c, t, t" '0""",, t,h, ,e, be"" ~t ,O",f""m, Y", "k, "n,o,."W, Ie, dge . Signed Lamar GanttÍ\~15 ~ ~ . Tltl~C: Dnlh~g Engl~eer . Date "I(Z¥ð7.. . '.,.'", "<~~mt~'J)ØW' -' Permit Number API Number APPfRv~1 F1~ See cover letter 2. 0 Z- - /? I 50- 029-22384-01 ILl I '( U V'\ for other reauirements Conditions of Approval: Samples Required 0 Yes li No Mud Log Required 0 Yes fži No Hydrogen Sulfide Measures 0 Yes ~ No Directional Survey Required 1!1 Yes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K 0 5K 0 10K 0 15K 0 3.5K psi for CTU 8WID:;]Ãl'ttGN~g;;t.fo -SÇoO I""": . t;>y order of t ~ Approved By 1) Taylor Seamount !~dM_il>rj'¡¡r! ì/"Je commission Date V / l '() bZ Form 10-401 Rev. 12-01-85 t ' " "o-r." SUb~it Triplicate ') ) BP P1-08A Sidetrack Summarv of Operations: A CTD through tubing sidetrack is planned for well PI-08. The sidetrack, PI-08A, will extend out from the existing 4 YZ" slotted liner shoe and target Zone LBl:' 3.75" openhole will be drilled from 10900' to TO at 12425'~ The well will be completed with a bonzai 3 3/16" solid cemented and 27/8" slotted liner from TO to 9055' (TOL). The existing 4 'l2" slotted liner is gassed out and will be abandoned during the primary cement job of this new sidetrack bonzai liner (form 10-403 has been submitted). Phase 1: Prep work. Planned for October 1, 2002. / I. Slickline - Drift tubing. Dummy gas lift valves. Pressure test IA to 2500 psi. Pressure test OA to 2000 psi. 2. Service coil- Mill SWN nipple at 9066' to a 3.80" ill. Clean out 4 'l2" slotted liner to shoe track. Perform circulation test with Flo Pro drilling mud to determine potential mud losses during CTD drilling operation. Phase 2: CTD Sidetrack summary. Planned for October 5, 2002 1. MIRU ClD rig 2. Mill 4 'l2" slotted liner packoffbushing and guide shoe at 10900' to 3.8" ill to exit into new fonnation. 3. Drill 3.75" openhole to ",12425' TO withMWD and gamma ray. / 4. Run and cement 33/16" x 2 7/8" bonzai CJffientedlslotted liner completion." The 3 3/16" liner portion will be solid from 9055' (TOL) to 11400' and cemented from 9700-11400'( The 27/8" liner section will be slotted from 11400' to 12425' lD. The bottom of the cemented 3 3/16" bonzai section will be at '" 11400', which is 500' beyond the 4 yz" slotted liner shoe. 5. Run liner top packer to the top of the new 3 3116" ClD liner at 9055' md. At this point, the 4 'l2" slotted liner completion in PI-08 is completely abandoned (3 3/16" liner top packer on top, 3 3/16" l~ acro~s entire 4 yz" slotted liner interval, and 500' of cemented 3 3/16" liner beyond the 4 'l2" shoe. 6. RDMO. Mud Program: . Phase 1: 9.5-9.7 ppg used Flo Pro mud . Phase 2: 9.5-9.7 ppg used Flo Pro for milling, new Flo Pro for drilling. / Disposal: . All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. . All Class I wastes will go to Pad 3 for disposal. Casing Program: / . A 3 3/16" solid cemented x 2 7/8" slotted liner bonzai production liner completion will be run. The 3 3/16" solid liner portion will ron from TOL at 9055' (8155' ssSt . ' (8749' ss). It will be cemented from 11400' to 9700'md. The 3 3116" cement volume is planned to 21 bbl of 15.8 ppg class G. The 2 7/8" slotted liner portion will run from 11400' to lD at 12425' (8745' ss)/ Well Control: . BOP diagram is attached. / . Pipe rams, blind rams and the CT pack off will be pressure tested to 400 psi and to 3500 psi. . The annular preventer will be tested to 400 psi and 2500 psi. ) ) Directional . See attached directional plan. Max. planned hole angle is 91 deg. . Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Logging . MWD Gamma Ray log will be run over all of the open hole section. Hazards . The highest H2S recorded to date on H-Pad was 60 ppm from PI-I3 on 10/1/98. PI pad is not an IDS / pad. PI-08 H2S is 0 ppm. Potential mud losses to 4 ~" slotted liner section while drilling new 3.75" sidetrack section. Contingency if losses will not heal would be to run and cement 3 3/16" liner after drilling 500' of new hole. This drilling liner would isolate losses to the 4 ~" slotted liner. The remainder of the sidetrack would be drilled with 2.75" openhole slimhole tools to TD and completed with 23/8" slotted liner. Crossing one fault, but with low risk of lost circulation. . . Resenoir Pressure Res. press. is estimated to be 4180 psi at 8740'ss (9.2 ppg EMW). Max. surface pressure with gas (0.10 psi/ft) to surface is 3306 psi. MOJ 9/19/02 \ TREE = WELLHEAD = cw 'ACTUÃfÖR';;'-"""-'--'---BAKËifc' ï<íis:Ë\,;;---------'---------------šo' ~""""",,,,,,,,,-,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,_.,,,,,,,,,,,,,,,",..........................._~...............,,,.,...-,......"'''''''''-'-. BF. ELEV = ï¿ÕP-;---"'------'----'-_._-----------------4329' ..~.~_-_A'~~!~_-~--.-.'--.---.-,._-,-,--'~~---~.'.-~.~~~t.- Datum MD = 10127' -õäiüiTiïV'ö';;"'''''''''''''''ääõö;'šs' ) P1-08 A Proposed CTD Sidetrack fl..clfAØ) 10-3/4" CSG, 45.5#, L-80, ID = 9.953" 1-1 3560' Minimum 10 = 3.8" @ 9066' 4-112" PARKER SWN NIPPLE PERFORA TK>N SUMMARY REF LOG: CDR on 07/18/93 ANGLE AT TOP PERF: 64 @ 10045' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE PI.. 10045-10084 crrted proposed SL 10084-10900 crrted proposed I 4-112" TOO, 12.6#, L-80, 0.0152 bpf, ID=3.958" 1-1 9088' r TOP OF CEMENT 1-1 9700' I TOP OF 4-1/2" LNR:- UNCEMENTED l-i 10023' 1 I TOP OF 4-1/2" FORTEDLNR 4-112" FORTED LNR, 12.6#, L-8Q, 0.0152 bpf, ID = 3.953" I TOPOF 4-112" SLOTTED LNR 1-1 10084' I 7-5/8" CSG, 29.7#, NT-95-HS, ID = 6.875" 1-1 10193' 10045' 10084' I TD 1-1 10900' 4-1/2" SLOTTED LNR, 12.6#, -i 10900' L-80, 0.0152 bpf, ID = 3.953" DA TE REV BY COMVIENTS 07/25/93 ORIGINAL COMR.ETION 01/16/01 SIS-1s1 CONVERTED TO CANVAS 02/20/01 SIS-MD FINAL 08/12101 RN/KAK CORRECTK>NS 02/24/02 VWZ/KA K MAX ANGLE CORRECTK>N ~ . ~ L I I z I I F & - I SAFETY NOTES: TUBING HANGER - ~C BPS @ 34.S' MD. 2260' 1-1 4-112" CAMeO TRCF SSSV, ID = 3.812" 1 ~ GAS LIFT MANDRELS ST MD lVD DEV TYPE VLV LATCH FORT DATE. 1 4152 4144 7 WBX SO BK5 20 03/09/02 2 8883 8075 42 WBX BK5 l 8946' 1-1 BAKER CMDSLlDlNG SLV, ID=3.813" I I 9017' 1-1 7-5/8" X 4-112" TWHBBPPKR 1 l 9049' I 9055' I 9066' 1 9088' I . 9080' I 10016' r 10017' DA TE REV BY COMMENTS 03/09/02 RUtlh GL V UPDATE 1-1 4-1/2" PARKERSWS NIP,ID=3.813" 1 1-1 Top of 3-3/16" liner 1-1 4-112" PARKER SWN NIP, ID = 3.725" 1-1 4-112" TUBING TAIL WI 4" PARKER WLEG 1 1---1 1-1 1-1 ELMD TT LOGGED 12/30/97 1 6-7/8" CTU ENTRY GUIDE I TlWSS HYDPKR, D=4.001" 1 FOINT ~INTYRE UNIT waL: P1-08 PERMIT No: 93-098 API No: 50-029-22384-00 Sec. 16, T12N, R14E, 2075.42 FEL 2485.66 FNL BP Exploration (Alaska) TRæ= WELLHEAD = CW 'ÄCTüÄTÕif;;;,~,,-,w""""ãÃKERC' ï<ã~-ËÜ~\r;_.m"_"--'---'''------------5Õ; lii~~~p\1f&' ) 10-3/4" CSG, 45.5#, L.80, ID = 9.953" 1-1 3560' Minimum 10 = 3.725" @ 9066' 4-112" PARKER SWN NIPPLE PERFORA TION SUMMARY REF LOG: CDR on 07/18/93 ANGLE AT TOP PERF: 64 @ 10045' Note: Refer to Production DB for historical perf data SIZE sÞF INTERVAL Opn/Sqz DATE PI. 10045-10084 0 08102/93 SL 10084.10900 0 08/02193 I 4-1/2" TBG, 12.6#, L-80, 0.0152 bpf, ID = 3.958" l-i 9088' I TOP OF 4.112" LNR - UNCEMENTED 1-1 4-1/2" LNR - UNCEMENTED, 12.6#, -i L-80, 0.0152 bpf, ID = 3.953" I TQPOF 4-1/2" PORTED LNR 1-1 10023' 1 10045' 10045' -i 10084' 4.1/2" PORTED LNR, 12.6#, L-80, 0.0152 bpf,lD = 3.953" I TOPOF 4-1/2" SLOTIED LNR 1-1 10084' I 7-5/8" CSG, 29.7#, NT-95-HS, ID = 6.875" 1-1 10193' 1 TD 1-1 10900' 4-1/2" SLOTTED LNR, 12.6#, -1 10900' L-80, 0.0152 bpf, ID= 3.953" DATE REV BY COrvNENTS 07/25/93 ORIGNAL COMR.ETK:>N 01/16/01 SIS-1s1 CONVERTED TO CANVAS 02/20/01 SIS-MD FINAL 08/12/01 RNlKAK CORRECTIONS 02/24/02 VPNZ/KAKMAX ANGLE CORRECTION P1-08 .. .. ~ L I . SAFETY NOTES: TUBING HANGER- )Me BPS @ 34.S' MD. 2260' 1-1 4-1/2" CAMeo TRCF SSSV, ID =3.812" 1 ~ GAS LIFT MANDRELS ST MD 1VD DEV TYPE VLV LATCH PORT DATE 1 4152 4144 7 wax SO BKS 20 03/09/02 2 8883 8075 42 wax BKS I I 1 8946' 1-1 BAKER CMD SLIDING SL V. ID = 3.813" 1 '&--t 9017' 1-1 7.5/8" X 4-1/2" TWHBBPPKR I g I - 9049' 1-1 4-1/2" PARKERSVVS NIP,ID=3.813" 1 9066' 1-1 4-1/2" PARKER SWN NIP, ID = 3.725" 9088' l-f 4-1/2" TUBING TAIL WI 4" PARKER WLEG 1 9080' 1-1 ELMD T1 LOGGED 12/30/97 1 ~ 10016' 1-1 6-7/8" CTU ENTRY GUIDE 1 I 1001T 1-1 TlWSS HYDPKR, D=4.oo1" 1 DA TE REV BY COMMENTS 03/09/02 RLltlh GL V UPDATE I . J ~ >i ~ ~i I I I I I I I I I I I I I I I ~ I :.. I I I I I I I bJ I I ~ POINT MCINTYRE UNIT WELL: P1-08 PERMIT No: 93-098 AA No: 50-029-22384-00 Sec. 16, T12N, R14E, 2075.42 FEL 2485.66 FNL BP Exploration (Alaska) 8850-::-----'----;-- . 8~~4~~~~~. I. I.~~~-.- - I I I I I I I I I :::. I ,. I" .,... 8950~ ,:,~, ,~+,¡ .., ,~ ,,,:';i i'''~'' "i , , ; -¡"T;¡T¡¡~' , ,¡ . 2450 2500 2550 2600 2650 2700 2750 2800 2850 2900 2950 3000 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 Vertical Section at 120.00. [50ft/In) BP Amoco PLAtJiII' ~ Po_tW~ on. - MOl 1tJt. lIef.- v....- AotIIe 'nM' WlLLPATH DlTAlLa -- P'''''' _IIU_' '1'" 18810... -, 11 ... 'I1J1t'8I - ....- ~ = :~ .... .... .... REFERENCE INFORMATION Co-ordlnat. ~1 Ref8llll1ce: Well Centre: P1.08, True North v~ (VS ~::::: ~~~ ;~~~el MNsuredOe Reference: 11 :087/131199300:00 48.90 Calculation Method: MInimum CurvatlA - - 1M All t ......... .... ...... . .- - ttl.8O 8 ........ ..... ft8. . ,...... ..... """ . tn..... 81.08 t.... . UltlUl .... .... ., ttHOAl ...n ....., . tt....., ..... tal, . it""'" .... 1''''' ~t 1=:1 :::= ~ft:I: f' tht&AI ....., t8NU8 tI tU2lAO ...., 1fl.7' IIICI'IOM HTAIU TV. ...". +8,ff l?88.a ,..... MIJ.8I 87'"'' tMlAI 1817.82 r~r. Uff::¡ UU IT-.. faa.N .'17.11 1710.00 'It....8 ..18." 87&. 1088.7' a..... 87""'" I8O.M 4Ui.87 11'''''' 807'" a..n .,...... ....,.& ....U 87"''' """1 ""'eM 17...... "'''S "17.'" IT...... ....n '2St.IT 8L" "'M8 V88c T"" 0.01 0.00 .....,... 0.00 0.00 anul 0.00 0.00 ..,-..0 "&00 110.00 .8..'" '1.00 80.00 H7a.DO '&01 0.00 aoaM ,&.. 87&00 12'1.11 1&00 80.00 aMi'" "&00 t70.00 ........ "1.00 .."... M'a..O 11.00 80.00 san..1 1&00 :110.00 ..t30... ta.oo 80.00 aH.M ANNOTATION' TVD MD _to- .,...... ,....... TIP .".... ,_... flOP "".a1 "."... 1 .7H.11 ,,_... . ,,- 1""'" . .".... 1181..... . "..... "nt.... . ".,... ""''''' . "..... 11...... , "..... 11'""" . "..... 11"''''' . ""'"1I.U"" 11 ,,- ,_.... TII TAAG£Tœr-.LS TW +NI-8 .EJ.W ... ~=~.2 '71g-~ ~na~ mH: =rn P1.o8A T&.2 8140 00 1001.<42 .__88 POnt P1-08A T&.4 8740.00 stU4 1230.. Point P1.(I8A T63 8145.00 tot." 4$45.51 PoInt ------'.-------"----' ObP ... .a.. INTEQ Direct: (907) 267-6613 E-mail: brij.potnis@inteq,oom Baker Hughes INTEQ: (907) 267-6600 T ^M 4 LEGEND - ~1:gg !~1:gg¡'B1) - PIan#5 P1-OBA - Plan #5 Plan: Plan #5 (P1-08IPlan#5 P1-08A) Created By: Bri¡ Potnis Date: 9/1212002 Azimuths to True North Magnetic North: 26.20. Magnetic Field Stren~h: 57543nT D~ate:g:~~M; Model: BGGM2002 Contact Information: I P1-OBA T5.4 I I-~.. .~~+-~ I. " . ,~Plan#5 P1-OéA~---. I ! ~..:..:..:.--. --- ¡:~ I I I ---~----- ~-- I I '1 I ¡ 1 1.1 II I I I I l' '11 9/12/2002 3;.10 PM ~ '~ Obp ) ) -tIC INTEQ BP Baker Hughes INTEQ Planning Report Company: BP Amoco Field: Point Mac Site: PtMac1 Well: P1-08 W~npatb: Plan#5Pl-QSA , 1>_:,19/1212002 ' '1'kØe:15:41:31 rage: , ~rct"'~l~~~nce~" Well:p,1..oS;TrueNóñt\ V~,('l'V.p)j~~f~n~: ,SY$t~¡iM~n,.Se~Le..,EtI ~..{VS)Refe~nAA: .. WEtlf.(qr()()~¡O;qQF.120!0Q~) . S.ryèy~kt1latio..M:~thocl: Minimum Curvature. . Db: t Oracle Point Mac North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Goo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Field: Map Zone: Coordinate System: Geomagnetic Model: Alaska. Zone 4 Well Centre BGGM2002 Pt Mac 1 TR-12-14 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Posidon Uncertainty: 0.00 ft Ground Level: 0.00 ft Site: 5990567.02 ft 672146.94 ft Latitude: Longitude: North Reference: Grid Convergence: 70 22 48.179 N 148 36 0.861 W True 1.32 deg P1-08 P1-08 Well Position: +N/-S 3955.64 ft Northing: 5994573.42 ft Latitude: +E/-W 2263.00 ft Easting: 674318.18 ft Longitude: Posidon Uncertainty: 0.00 ft Well: Slot Name: 08 70 23 27.079 N 148 34 54.595 W Wellpatb: Plan#5 P1-08A 500292238401 Current Datum: 11 : 087/13/199300:00 Magnetic Data: 9/1212002 Field Strength: 57543 nT Vertical Section: Depth From (fVD) ft 0.00 +N/-S ft 0.00 Drilled From: Tie-on Depth: Above System Datum: Declination: Mag Dip Angle: +E/-W ft 0.00 P1-08 10810.00 ft Mean Sea Level 26.20 deg 80.88 deg Direction deg 120.00 Height 48.90 ft Targets ~I.ongitude Deg MinSec P1-08A Polygon5.2 0.00 1297.02 3903.38 5995961.00 678190.00 70 23 39.825 N 148 33 0.274 W -Polygon 1 0.00 1297.02 3903.38 5995961.00 678190.00 70 23 39.825 N 148 33 0.274 W -Polygon 2 0.00 1409.34 3977.02 5996075.00 678261.00 70 23 40.929 N 148 32 58.115 W .Polygon 3 0.00 1292.96 4120.36 5995962.00 678407.00 70 23 39.784 N 148 32 53.919 W -Polygon 4 0.00 1120.96 4289.41 5995794.00 678580.01 70 23 38.091 N 148 32 48.971 W -Polygon 5 0.00 1007.85 4506.84 5995686.00 678800.00 70 23 36.977 N 148 32 42.605 W -Polygon 6 0.00 899.38 4697.38 5995582.01 678993.01 70 23 35.910 N 148 32 37.027 W -Polygon 7 0.00 817.45 4907.54 5995505.00 679205.00 70 23 35.102 N 148 32 30.874 W .Polygon 8 0.00 644.23 5257.62 5995340.00 679559.00 70 23 33.396 N 148 3220.625 W -Polygon 9 0.00 512.44 5203.53 5995207.00 679508.01 70 23 32.101 N 148 3222.211 W -Polygon 10 0.00 579.91 5056.05 5995271.01 679359.00 70 23 32.765 N 148 3226.529 W .Polygon 11 0.00 685.20 4873.44 5995372.00 679174.00 70 23 33.802 N 148 32 31.875 W -Polygon 12 0.00 773.68 4639.43 5995455.00 678938.01 70 23 34.674 N 148 32 38.726 W -Polygon 13 0.00 913.60 4430.62 5995590.00 678726.00 70 23 36.051 N 148 3244.839 W -Polygon 14 0.00 1023.08 4240.11 5995695.01 678533.01 70 23 37.129 N 148 32 50.416 W .Polygon 15 0.00 1191.33 4059.97 5995859.00 678349.00 70 23 38.784 N 148 32 55.689 W P1-08A T5.1 8710.00 1348.24 3937.59 5996013.00 678223.00 70 23 40.328 N 148 3259.271 W P1-08A T5.2 8740.00 1001.42 4396.66 5995677.00 678690.00 70 23 36.915 N 148 3245.832 W P1-08A T5.4 8740.00 591.84 5230.39 5995287.00 679533.00 70 23 32.881 N 148 32 21.423 W P1-D8A T5.3 8745.00 909.91 4545.57 5995589.00 678841.00 70 23 36.014 N 148 3241.472 W 0\', b ",,' p ') ) ... .... INTEQ BP Baker Hughes INTEQ Planning Report Company: BP Amoco meld: PointMåc:: Siœ: PfMac1 Wtll: P1-'08 WeUpath: Plan#5P1-oSA Annotation MD ft 10810.00 8705.63 TIP 10900.00 8710.65 KOP 10910.00 8711.21 1 10990.96 8720.11 2 11140.96 8744.20 3 11215.43 8750.00 4 11390.43 8748.89 5 11540.43 8747.05 6 11665.43 8745.58 7 11790.43 8744.89 8 12040.43 8745.05 9 12315.43 8745.19 10 12425.00 8745.24 TD Plan: Plan #5 Identical to lamar's Plan #5 Principal: Yes Plan Section Information MD Incl ADm TVD +N/-S +EI-W DLS Build Turn TFO Target ft deg deg ft ft deg(1OOft, 9eg11,~ degl100ft deg 10810.00 86.80 110.80 8705.63 1380.53 3853.82 0.00 0.00 0.00 0.00 10900.00 86.80 110.80 8710.65 1348.62 3937.82 0.00 0.00 0.00 0.00 10910.00 86.80 110.80 8711.21 1345.07 3947.16 0.00 0.00 0.00 0.00 10990.96 80.60 118.33 8720.11 1311.69 4020.27 12.00 -7.66 9.30 130.00 11140.96 81.06 136.56 8744.20 1222.04 4137.31 12.00 0.31 12.15 90.00 11215.43 90.00 136.56 8750.00 1168.19 4188.31 12.00 12.00 0.00 0.00 11390.43 90.72 115.57 8748.89 1065.75 4328.98 12.00 0.41 -11.99 272.00 11540.43 90.68 133.57 8747.05 980.99 4451.97 12.00 -0.02 12.00 90.00 11665.43 90.66 118.57 8745.58 907.61 4552.72 12.00 -0.02 -12.00 270.00 11790.43 89.96 103.59 8744.89 862.78 4669.02 12.00 -0.56 -11.99 267.40 12040.43 89.97 133.59 8745.05 744.52 4886.04 12.00 0.00 12.00 90.00 12315.43 89.97 100.59 8745.19 621.03 5127.51 12.00 0.00 -12.00 270.00 12425.00 89.97 113.73 8745.24 588.77 5231.97 12.00 0.00 12.00 90.00 Survey MD DLS TFO' Tool' ft degl10Qf't deg 10810.00 86.80 110.80 8705.63 1380.53 3853.82 5996043.33 678138.51 2647.24 0.00 0.00 TIP 10825.00 86.80 110.80 8706.47 1375.21 3867.82 5996038.34 678152.63 2662.03 0.00 0.00 MWD 10850.00 86.80 110.80 8707.86 1366.34 3891.15 5996030.02 678176.16 2686.67 0.00 0.00 MWD 10875.00 86.80 110.80 8709.26 1357.48 3914.49 5996021.70 678199.70 2711.31 0.00 0.00 MWD 10900.00 86.80 110.80 8710.65 1348.62 3937.82 5996013.39 678223.23 2735.95 0.00 0.00 KOP 10910.00 86.80 110.80 8711.21 1345.07 3947.16 5996010.06 678232.64 2745.80 0.00 0.00 1 10925.00 85.64 112.18 8712.20 1339.59 3961.08 5996004.90 678246.69 2760.60 12.00 130.00 MWD 10950.00 83.72 114.50 8714.52 1329.73 3983.94 5995995.58 678269.77 2785.33 L12.oo 129.91 MWD 10975.00 81.81 116.83 8717.67 1318.99 4006.29 5995985.37 678292.36 2810.05 12.00 129.69 MWD 10990.96 80.60 118.33 8720.11 1311.69 4020.27 5995978.39 678306.51 2825.81 12.00 129.40 2 11000.00 80.60 119.43 8721.58 1307.38 4028.08 5995974.27 678314.41 2834.73 12.00 90.00 MWD 11025.00 80.62 122.47 8725.66 1294.70 4049.23 5995962.08 678335.85 2859.39 12.00 89.82 MWD 11050.00 80.67 125.51 8729.72 1280.91 4069.68 5995948.78 678356.62 2883.99 12.00 89.32 MWD 11075.00 80.75 128.55 8733.76 1266.05 4089.37 5995934.38 678376.65 2908.47 12.00 88.83 MWD 11100.00 80.85 131.59 8737.76 1250.17 4108.26 5995918.95 678395.90 2932.77 12.00 88.34 MWD 11114.13 80.91 133.30 8740.00 1240.75 4118.55 5995909.77 678406.41 2946.40 12.00 87.85 P1-08A T 11125.00 80.97 134.62 8741.71 1233.30 4126.28 5995902.51 678414.31 2956.81 12.00 87.58 MWD 11140.96 81.06 136.56 8744.20 1222.04 4137.31 5995891.50 678425.60 2972.00 12.00 87.37 3 11150.00 82.15 136.56 8745.52 1215.55 4143.46 5995885.16 678431.90 2980.57 12.00 0.00 MWD 11175.00 85.15 136.56 8748.29 1197.51 4160.54 5995867.52 678449.40 3004.38 12.00 0.00 MWD Date: <9112/2002 Time: 15:41:31 , Çq+órdlnâ~)~~fet~D~: Well: P:1..()8, T'UeNQrtþ Ye~(TVJj)'Refel'ell~: Sy~em:M8$O S~l~,,~1 SeçtiQD(YS)R,eference: Well (0.OON,O;0,OE,120.00Azi) ,,~urVey Calé:ulaUOn M~~~: Minimum Curvature Db: Oracle Page: 2 Date Composed: Version: Tied-to: 9/12/2002 2 From: Definitive Path ObP ) BP ) B.. .... Baker Hughes INTEQ Planning Report lNrKQ Company: BP Amoco Date: ,. .,911212002 Time: 15:41 :31 Page: 3 Field: Point Mac C~..dina~~)Refêrençe: Well: P1-o8/Trt.iêNoi'th Site: Pt Mac 1 "ert!caI,(T~)Re{el:"e~ee: . $ys~rm:M~r\~~ l.~~~1 , . WeD: P1:.Q8 ~n(VS)Referenee: . W~n(p.ooNtQ;.Q()E.12Q,Q()Azi) , , ' " WeUpath: PIan#5P1-o8A SorveyÇa.lc....ti9DMetlt04: ' Minimum. CUlVature '. . Db: . Oracle Survey MD Incl Azim SSTVD N/S E/W MapN MapE VS DLS TFO Tool ft deg deg ft ft ft ft ft ft deg/100ft deg 11200.00 88.15 136.56 8749.75 1179.39 4177.70 5995849.81 678466.97 3028.30 12.00 0.00 MWD 11215.43 90.00 136.56 8750.00 1168.19 4188.31 5995838.86 678477.84 3043.09 12.00 0.00 4 11225.00 90.04 135.41 8750.00 1161.31 4194.96 5995832.14 678484.64 3052.29 12.00 272.00 MWD 11250.00 90.14 132.41 8749.95 1143.97 4212.97 5995815.23 678503.05 3076.55 12.00 272.00 MWD 11275.00 90.25 129.41 8749.87 1127.60 4231.86 5995799.30 678522.32 3101.09 12.00 271.99 MWD 11300.00 90.35 126.42 8749.74 1112.24 4251.58 5995784.41 678542.39 3125.85 12.00 271.98 MWD 11325.00 90.45 123.42 8749.56 1097.93 4272.07 5995770.58 678563.21 3150.76 12.00 271.97 MWD 11350.00 90.56 120.42 8749.34 1084.72 4293.29 5995757.86 678584.73 3175.74 12.00 271.95 MWD 11375.00 90.66 117 .42 8749.08 1072.63 4315.17 5995746.29 678606.88 3200.73 12.00 271.92 MWD 11390.43 90.72 115.57 8748.89 1065.75 4328.98 5995739.73 678620.85 3216.13 12.00 271.89 5 11400.00 90.72 116.72 8748.77 1061.53 4337.57 5995735.72 678629.53 3225.68 12.00 90.00 MWD 11425.00 90.71 119.72 8748.46 1049.71 4359.59 5995724.42 678651.82 3250.66 12.00 90.01 MWD 11450.00 90.71 122.72 8748.15 1036.76 4380.97 5995711.96 678673.49 3275.65 12.00 90.05 MWD 11475.00 90.71 125.72 8747.84 1022.70 4401.64 5995698.39 678694.48 3300.58 12.00 90.09 MWD 11500.00 90.70 128.72 8747.53 1007.58 4421.54 5995683.74 678714.73 3325.38 12.00 90.13 MWD 11525.00 90.69 131.72 8747.23 991.44 4440.63 5995668.05 678734.19 3349.97 12.00 90.16 MWD 11540.43 90.68 133.57 8747.05 980.99 4451.97 5995657.87 678745.78 3365.03 12.00 90.20 6 11550.00 90.68 132.42 8746.93 974.46 4458.97 5995651.51 678752.93 3374.35 12.00 270.00 MWD 11575.00 90.68 129.42 8746.64 958.09 4477.86 5995635.58 678772.19 3398.89 12.00 269.99 MWD 11600.00 90.68 126.42 8746.34 942.73 4497.58 5995620.69 678792.26 3423.65 12.00 269.95 MWD 11625.00 90.67 123.42 8746.05 928.42 4518.07 5995606.86 678813.08 3448.55 12.00 269.92 MWD 11650.00 90.66 120.42 8745.75 915.20 4539.29 5995594.14 678834.59 3473.54 12.00 269.88 MWD 11665.43 90.66 118.57 8745.58 907.61 4552.72 5995586.86 678848.20 3488.96 12.00 269.84 7 11675.00 90.61 117.42 8745.47 903.11 4561.16 5995582.57 678856.75 3498.53 12.00 267.40 MWD 11700.00 90.47 114.43 8745.24 892.19 4583.65 5995572.17 678879.48 3523.46 12.00 267.39 MWD 11725.00 90.33 111.43 8745.06 882.45 4606.67 5995562.97 678902.72 3548.27 12.00 267.36 MWD 11750.00 90.19 108.43 8744.95 873.93 4630.17 5995555.00 678926.41 3572.88 12.00 267.34 MWD 11775.00 90.05 105.44 8744.90 866.65 4654.08 5995548.28 678950.48 3597.23 12.00 267.32 MWD 11790.43 89.96 103.59 8744.89 862.78 4669.02 5995544.76 678965.50 3612.10 12.00 267.32 8 11800.00 89.96 104.73 8744.90 860.44 4678.30 5995542.64 678974.83 3621.30 12.00 90.00 MWD 11825.00 89.96 107.73 8744.92 853.45 4702.30 5995536.21 678998.99 3645.58 12.00 90.00 MWD 11850.00 89.96 110.73 8744.93 845.22 4725.90 5995528.53 679022.78 3670.14 12.00 90.00 MWD 11875.00 89.96 113.73 8744.95 835.76 4749.04 5995519.61 679046.13 3694.91 12.00 90.00 MWD 11900.00 89.96 116.73 8744.96 825.10 4771.65 5995509.49 679068.98 3719.82 12.00 89.99 MWD 11925.00 89.96 119.73 8744.98 813.28 4793.67 5995498.18 679091.27 3744.80 12.00 89.99 MWD 11950.00 89.97 122.73 8745.00 800.31 4815.05 5995485.72 679112.94 3769.80 12.00 89.99 MWD 11975.00 89.97 125.73 8745.01 786.25 4835.71 5995472.14 679133.93 3794.72 12.00 89.99 MWD 12000.00 89.97 128.73 8745.03 771.13 4855.61 5995457.49 679154.17 3819.52 12.00 89.99 MWD 12025.00 89.97 131.73 8745.04 754.98 4874.70 5995441.79 679173.63 3844.12 12.00 89.98 MWD 12040.43 89.97 133.59 8745.05 744.52 4886.04 5995431.60 679185.21 3859.18 12.00 89.98 9 12050.00 89.97 132.44 8745.05 738.00 4893.04 5995425.24 679192.36 3868.50 12.00 270.00 MWD 12075.00 89.97 129.44 8745.07 721.62 4911.92 5995409.31 679211.62 3893.04 12.00 270.00 MWD 12100.00 89.97 126.44 8745.08 706.25 4931.64 5995394.40 679231.69 3917 .80 12.00 270.00 MWD 12125.00 89.97 123.44 8745.09 691.93 4952.13 5995380.57 679252.50 3942.71 12.00 270.00 MWD 12150.00 89.97 120.44 8745.11 678.71 4973.34 5995367.85 679274.02 3967.69 12.00 270.01 MWD 12175.00 89.97 117.44 8745.12 666.61 4995.22 5995356.27 679296.17 3992.68 12.00 270.01 MWD 12200.00 89.97 114.44 8745.14 655.68 5017.70 5995345.86 679318.90 4017 .62 12.00 270.01 MWD 12225.00 89.97 111.44 8745.15 645.94 5040.72 5995336.66 679342.14 4042.42 12.00 270.01 MWD 12250.00 89.97 108.44 8745.16 637.41 5064.22 5995328.69 679365.83 4067.04 12.00 270.01 MWD 12275.00 89.97 105.44 8745.17 630.13 5088.13 5995321.96 679389.90 4091.39 12.00 270.01 MWD 12300.00 89.97 102.44 8745.19 624.11 5112.39 5995316.51 679414.29 4115.41 12.00 270.02 MWD 12315.43 89.97 100.59 8745.19 621.03 5127.51 5995313.78 679429.48 4130.04 12.00 270.02 10 12325.00 89.97 101.73 8745.20 619.18 5136.90 5995312.15 679438.91 4139.10 12.00 90.00 MWD '\\ Obp ) ") -.. .... INTEQ BP Baker Hughes INTEQ Planning Report Company: BP Amoco Field: PointMâc Site: pt Mac 1 WeD: P1-08 ' WeUpatb: PIan#5P1-QBA Dåte: .,$/1212002 1'I~e: ',1$:-41:31 Page: <:,O'"O..d~te(NE)l{e(~n«: Well:,~1:.o~¡"r(1$North , ~~.I~)'l{~~~~: $yst~n'IZ'.'M~rl'§~éi."L~.vel , ~11(Y~)R~(~..~: " ' \V~1!(9.()ON~9;99Et12()'()OAži)",. ' ~lItVeY ~lçtl..ti()..Metti9d: MinimumCuwature Db: Orâcle 4 Survey MD Iilcl Azim SSTVD ft 'deg deg ft 12350.00 89.97 104.73 8745.21 12375.00 89.97 107.73 8745.22 12400.00 89.97 110.73 8745.23 12425.00 89.97 113.73 8745.24 MapN VS DLS TFO Tool ft ft ' . (fegl1pQft (fag 613.46 5161.23 5995307.00 679463.37 4163.03 12.00 90.00 MWD 606.4 7 5185.23 5995300.57 679487.52 4187.31 12.00 90.00 MWD 598.23 5208.84 5995292.89 679511.31 4211.87 12.00 90.00 MWD 588.77 5231.97 5995283.97 679534.66 4236.64 12.00 90.00 TD ~ ' ') Nordic CTD BOP Detail ) o'\, -- CT Injector Head I 1 --- Stuffing Box (Pack-Off), 10,000 psi Working Pressure /UI I " ~ Methanol Injection .ðJLð Otis 7" WLA Quick II Connect - I 7-1/16" ID, 5000 psi working pressure :-- ' Ram Type Dual Gate BOPE - 7" Riser 1'1 I "" Annular BOP (Hydril),7-1/16" ID 5000 psi working pressure Manual over Hydraulic \.. .J I I I . I TOT k 'i:::I=Il Blind/Shear I r-- rc= ~o I 12 3/8 .. Combi PipelSli~ Fire resistant Kelly Hose to HCR Flange by Hammer up 1/4 Turn @ I Kill r h k I Valve on DS Hardline to StandpipE [ 0 ~OW :tJØ\IlfBJ1I ~:ve / manITo~ I l 7-1/16" ID, 5000 psi working pressure ~ 2"SideOutlets, ~ = I 2 318" X 3 1/2" VBRs Ram Type Dual Gate BOPE I TOT Ic:= ~,' ..::= ~ @ 23/8" Combi Pipe/Slip Manual over Hydraulic c:: I I . I I XO Spool as necessary \ / 2 flanged gate valves I I @ J . , @) I I II THA I L ~- -- ~ Tubing @ ~ Inner Annulus r Spool =, - I J --~ @::¡ðJ.ð. Outer Annulus Flanged Fire Resistant Kelly Hose to Dual Choke Manifold / Full production christmas tree MOJ 9/15/02 H 207050 DATE 8/01/02 CHECK NO. H207050 DATE VENDOR DISCOUNT NET INVOICE / CREDIT MEMO DESCRIPTION GROSS 8/01/02 Permit To Drill Fee $100.00 CK073102Q !)\ -OßA PIs contact Sandra Stewman X4750 for check pickup THE AlTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL .... $100.00 PAY 333 W 7th Av~, Ste 100 Anchorage, AK 99501 ~':.'.,'. ~ ~ . .:\.:.: ::.::::: :{:.: ::::~:.::j~.: ~::.::~:~~. f.::: ~.:~:::: ~:\::?, ~.¡ .:.: ";.; .::;¡¡¿;~ ::"::'."':'''''.~: ..n.: :......;;....., 'S'):t:r{~(~)~;;;;~?~~;:~~;:::;¿~;:;j III 20 'i' 0 50111 I: 0 t. ~ 2 0 ~ a q 51: 00 a t. t. ~ q III 0 4.1 >. - .... c...J I~.I Ot: .; H i ~~ ~ ?It N &;; 0- I] lJ.J . en S I < ~,. ) TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERIP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME~:.I ;It 4~1!- 1/- 0 <¿ A PTD# ;2.02- - / '1 'J CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) HOLE SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates "CLUE" The permit is' for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function' of the original API number stated above. In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (SO 70/80) from records, data and logs acquired for well (name on permit). . The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuance of a conservation order approvin.g a spacing . exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. fi.-~ ø~l'''- WELL PERMIT CHECKLIST COMPANY fip)C WELL NAME PI- o~ A PROGRAM: Exp- Dev.K. Redrll-X- Re-Enter - Serv - Wellbore seg- FIELD & POOL 666/0'" INIT CLASS ÓIØ~¿'- /-~,'I GEOL AREA ~?L"'!. UNIT# II 6.J 0 ON/OFF SHORE ~¡J ADMINISTRATION 1. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . fÇ' N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . Y N 3. Unique well name and number. . . . . . . . . . . . . . . . . Y N 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . Y N 5. Well located proper distance from drilling unit boundary. . . . Y N 6. Well located proper distance from other wells.. . . . . . . . . Y N 7. Sufficient acreage available in drilling unit.. . . . . . , . . . . Y N RJ-J -~ ~ /{~, 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . Y N ,6LS- ~/tfJ,,- 9. Operator only affected party.. . . . . . . . . . . . .. . . . . Y N 10. Operator has appropriate bond in force. . . . . . . . . . . . . Y N 11. Permit can be issued without conservation order. . . . . . . . \ '! J N 12. Permit can be issued without administrative approval.. . . . . \::Jj N (Service Well Only) 13. Well located w/in area & strata authorized by injection order#~ Ÿ )(, /'~. A. (Service Well Only) 14. All wells w/in X mile area of review identified. . . . . . . . .. Y N ENGINEERING 15. Conductor ~tring provided. . . . . . . . . . . .. . . . . . . 6PN 16. Surface casing protects all known USDWs. . . . . . . . . . . éJ) N ~II ¡ I L 17. CMT vol ádequate to circulate on conductor & surf csg. . . . . '¥-N'" I U 111 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . -¥-No .J. 19. CMT will cover all known productive horizons. . .'. . . . .. . ~~, S,. (tl foK J 20. Casing designs adequate for C, T, B & permafrost. .... . . N ,) 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . N CTt/U 22. If a re-drill, has a 10-403 for abandonment been a,pproved. .. 16::t.- N 23. Adequate wellbore separation proposed.. . . . . .. . . . . . (;y) N 24. If diverter required, does it meet regulations. . . . . . . . . . ""'¥"-N" /\LIlt- vv1 tJ¡ 7 25. Drilling fluid program, schematic & equip list adequate. . . . . j N ~ "t, ~( -,. f P '7 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . , N 27. BOPE press rating appropriate; test to '3500 psig. N Yk,C; ¡) '1"S 0 ~ t? c..-: ,I I 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N ~G~+ c¡ {;Ol OL.- 29. Work will occur without operation shutdown. . . . . . . . . . . N 30. Is presence of H2S gas probable... . . . . . . . . . . . . . . Y dP (Service Well Only) 31. Mechanical condition of wells within AOR verified. . . . . . . . -¥-t't'AiIk- GEOLOGY 32. Permit can be issued wlo hydrogen sulfide measures. . . . . C5ZJ N APPR DATE 33. Data presented on potential overpressure zones. . . . . . . . n ~- q,.( .¿~ 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . ~ ~ IV 14 . ,/Y ~- //¿?/~ 35. Seabed condition survey (if off-shore). . . . . . . . . . . . . . IJ (Exploratory Only) 36. Contact namelphone for weekly progress reports. . . . . . . . GEOLOGY: PETROLEUM ENGINEERING: RESERVOIR ENGINEERING RP~¿ TEM JDH ..JI-t" APPR DATE APPR DATE Rev: 07/12/02 UIC ENGINEER JBR COMMISSIONER: COT DTS )0 {Ol fa G Comments/lnstructions: SFD WGA \LJ6 A- MJW /W~ð /Q/ø>~() 'Z- G:\geology\permits\checklist.doc ) } Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Pennitting Process but is part of the history file. To improve the readability of the Well History file and to simpltfy finding information, information of this nature is accumulated at the end of the file under APPEN.DIX. No specialeffort has been made to chronologically organize this category of infonnation. .' ) a oé)-/9 9 17000 Sperry-Sun Drilling Services LIS Scan utility $Revision: 3 $ LisLib $Revision: 4 $ Tue Apr 15 12:55:27 2003 Reel Header Service name..... ....... .LISTPE Date. . . . . . . . . . . . . . . . . . . . .03/04/15 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name.... ........... . UNKNOWN Continuation Number.... ..01 Previous Reel Name...... .UNKNOWN Comments.......... ...... .STS LIS Writing Library. Scientific Technical Services Tape Header Service name. ........... .LISTPE Date. . . . . . . . . . . . . . . . . . . . .03/04/15 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name........ ....... .UNKNOWN Continuation Number..... .01 Previous Tape Name...... . UNKNOWN Comments................ .STS LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Point McIntyre MWD/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA Pl-08A 500292238401 BP Exploration Sperry Sun 15-APR-03 (Alaska) Inc. JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWDRUN 1 AK-MW-22204 M. ALLEN WHITLOW MWDRUN 2 AK-MW-22204 M. ALLEN WHITLOW MWDRUN 3 AK-MW-22204 M. ALLEN WHITLOW # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: 16 12N 14E 1443 738 MSL 0) 48.90 .00 .00 # WELL CASING RECORD 1ST STRING OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 4.125 4.500 10900.0 . ~ 2ND STRING 3RD STRING PRODUCTION STRING # REMARKS: ) ) 1. ALL DEPTHS ARE MEASURED DEPTHS UNLESS OTHERWISE NOTED. 2. ALL VERTICAL DEPTHS ARE SUBSEA TRUE VERTICAL DEPTHS (TVDSS). 3. WELL SIDETRACKED FROM P1-08, DRILLING OUT FROM THE END OF THE EXISTING SLOTTED LINER AT ABOUT 10900' MD / 8711' TVDSS. 4. MWD RUNS 1 - 3 WERE DIRECTIONAL WITH GAMMA MODULE (GM) UTILIZING GEIGER-MUELLER TUBE DETECTORS. 5. DIGITAL DATA ONLY WAS DEPTH SHIFTED TO THE SCHLUMBERGER MEMORY CNL OF 26-DEC-2002, PER THE 12-APR-2003 E-MAIL FROM D. SCHNORR (BP EXPLORATION). HEADER AND RUN INFORMATION DATA RETAIN ORIGINAL DRILLER'S DEPTH REFERENCES. 6. MWD RUNS 1 - 3 REPRESENT WELL P1-08A WITH API # 50-029-22384-01. THIS WELL REACHED A TOTAL DEPTH (TD) OF 12444' MD / 8715' TVDSS. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED (GEIGER-MUELLER TUBE DETECTORS) $ File Header Service name............ .STSLIB.001 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation...... .03/04/15 Maximum Physical Record. .65535 File Type.......... .... ..LO Previous File Name. .... ..STSLIB.OOO Comment Record FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted and DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE GR ROP $ 1 clipped curves; all bit runs merged. .5000 START DEPTH 9525.5 10921.5 STOP DEPTH 12418.5 12446.5 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE 9525.5 10895.5 10905.5 11012.0 11017.5 11029.0 11040.0 11070.0 11110.5 11212.5 11313.0 11348.5 DEPTH GR 9516.5 10886.5 10896.5 11004.5 11011.5 11022.0 11031.5 11062.0 11102.0 11203.5 11306.0 11341.0 ) ) 11360.0 11352.0 11368.0 11361.5 11382.5 11375.0 11390.0 11383.0 11398.5 11392.5 11872.0 11867.5 11897.0 11891.0 11949.0 11944.0 12037.5 12032.0 12066.0 12063.5 12076.0 12072.5 12343.0 12340.0 12348.0 12345.5 12352.5 12349.5 12354.0 12351.0 12446.5 12443.5 $ # MERGED DATA SOURCE PBU TOOL CODE BIT RUN NO MERGE TOP MERGE BASE MWD 1 9516.5 11097.0 MWD 2 11070.0 11147.0 MWD 3 11119.0 12443.5 $ # REMARKS: MERGED MAIN PASS. $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type.....O Logging Direction.. ........ ...... . Down Optical log depth units..... ..... .Feet Data Reference Point.. ~......... ..Undefined Frame Spacing...... ....... ... .... .60 .1IN Max frames per record............ . Undefined Absent value...... ...... ... .... ...-999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9525.5 12446.5 10986 5843 9525.5 12446.5 ROP MWD FT/H 0.21 1130.21 109.216 3051 10921.5 12446.5 GR MWD API 21.58 235.81 57.5193 3125 9525.5 12418.5 First Reading For Entire File. ........ .9525.5 Last Reading For Entire File... ..... ...12446.5 File Trailer Service name............ .STSLIB.001 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation. ..... .03/04/15 Maximum Physical Record. .65535 . . ') File Type............... .LO Next File Name.......... .STSLIB.002 Physical EOF File Header Service name............ .STSLIB.002 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation...... .03/04/15 Maximum physical Record. .65535 File Type................LO Previous File Name...... .STSLIB.001 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR ROP $ 2 ) header data for each bit run in separate files. 1 .5000 START DEPTH 9516.5 10912.5 STOP DEPTH 11069.5 11097.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE GM Dual GR $ # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: 23-DEC-02 Insite 4.3 Memory 11097.0 9525.0 11097.0 79.8 85.0 TOOL NUMBER 74165 4.125 10900.0 Flo Pro 9.30 65.0 9.5 57000 6.0 .000 .000 .000 .0 141.0 .0 , . ) MUD CAKE AT MT: .000 .0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type........... .......0 Data Specification Block Type.....O Logging Direction...... ...... .... . Down Optical log depth units. ..... .... .Feet Data Reference Point............. . Undefined Frame Spacing..................... 60 .1IN Max frames per record..... ....... . Undefined Absent value. . . . . . . . . . . . . . . . . . . . . . -999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type. ..0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD010 FT/H 4 1 68 4 2 GR MWD010 API 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9516.5 11097 10306.8 3162 9516.5 11097 ROP MWD010 FT/H 0.21 143.8 57.6108 370 10912.5 11097 GR MWD010 API 23.39 235.81 69.8816 445 9516.5 11069.5 First Reading For Entire File... ..... ..9516.5 Last Reading For Entire File.... ..... ..11097 File Trailer Service name............ .STSLIB.002 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation...... .03/04/15 Maximum Physical Record. .65535 File Type.............. ..LO Next File Name.......... .STSLIB.003 Physical EOF File Header Service name........... ..STSLIB.003 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation. ... ...03/04/15 Maximum Physical Record. .65535 File Type... ............ .LO Previous File Name. .... ..STSLIB.002 ') Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR ROP $ 3 ) header data for each bit run in separate files. 2 .5000 START DEPTH 11070.0 11097.5 STOP DEPTH 11118.5 11147.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE GM Dual GR $ # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type..................O 23-DEC-02 Insite 4.3 Memory 11147.0 11097.0 11147.0 81.0 88.4 TOOL NUMBER 74165 4.125 10900.0 Flo Pro 9.30 65.0 9.0 57000 6.0 .000 .000 .000 .000 .0 152.0 .0 .0 ') ) Data Specification Block Type.....O Logging Direction................ . Down Optical log depth units.......... .Feet Data Reference Point............ ..Undefined Frame Spacing.... ............... ..60 .1IN Max frames per record............ . Undefined Absent value. . . . . . . . . . . . . . . . . . . . . . -999 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 11070 11147 11108.5 155 11070 11147 ROP MWD020 FT/H 3.28 67.04 44.2962 100 11097.5 11147 GR MWD020 API 70.61 116.46 104.366 98 11070 11118.5 First Reading For Entire File........ ..11070 Last Reading For Entire File... ...... ..11147 File Trailer Service name............ .STSLIB.003 Service Sub Level Name. . . Version Number......... ..1.0.0 Date of Generation...... .03/04/15 Maximum Physical Record. .65535 File Type.............. ..LO Next File Name.......... .STSLIB.004 Physical EOF File Header Service name............ .STSLIB.004 Service Sub Level Name. . . Version Number.......... .1.0.0 Date of Generation...... .03/04/15 Maximum Physical Record. .65535 File Type............... .LO Previous File Name...... .STSLIB.003 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 11119.0 ROP 11147.5 $ 4 header data for each bit run in separate files. 3 .5000 STOP DEPTH 12415.5 12443.5 # , ... ) LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE GM Dual GR $ # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type.....O Logging Direction. ......,... .... ..Down Optical log depth units... ....... .Feet Data Reference Point....... ... ....Undefined Frame Spacing..... .......... ... ...60 .1IN Max frames per record...... ...... . Undefined Absent value. . . . . . . . . . . . . . . . . . . . . . - 9 9 9 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O ) 25-DEC-02 Insite 4.3 Memory 12444.0 11147.0 12444.0 88.4 97.0 TOOL NUMBER 74165 4.125 10900.0 Flo Pro 9.40 65.0 9.0 97000 14.2 .000 .000 .000 .000 .0 152.0 .0 .0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD030 FT/H 4 1 68 4 2 GR MWD030 API 4 1 68 8 3 '" ' ~, ,f'" ) First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 11119 12443.5 11781.3 2650 11119 12443.5 ROP MWD030 FT/H 2.04 1130.21 119.011 2593 11147.5 12443.5 GR MWD030 API 21.58 134.96 53.6074 2594 11119 12415.5 First Reading For Entire File....... ...11119 Last Reading For Entire File......... ..12443.5 File Trailer Service name............ .STSLIB.004 Service Sub Level Name. . . Version Number.......... .1.0.0 Date of Generation...... .03/04/15 Maximum Physical Record. .65535 File Type. . . . .. . . . . .. . . . .LO Next File Name.......... .STSLIB.005 Physical EOF Tape Trailer Service name............ .LISTPE Date. . . . . . . . . . . . . . . . . . . . .03/04/15 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name..... .......... .UNKNOWN Continuation Number..... .01 Next Tape Name..... "'" .UNKNOWN Comments................ .STS LIS Writing Library. Scientific Technical Services Reel Trailer Service name............ .LISTPE Date. . . . . . . . . . . . . . . . . . . . .03/04/15 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name.......... ..... .UNKNOWN Continuation Number..... .01 Next Reel Name.......... .UNKNOWN Comments................ .STS LIS Writing Library. Scientific Technical Services Physical EOF Physical EOF End Of LIS File