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Home My WebLink About225-0511. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: Kuparuk River Field Torok Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 21,938'1786 None Casing Collapse Structural Conductor Surface 2,470 Intermediate 4,790 Production 7,850 Liner 9,210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Allen Eschete Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Allen.Eschete@ConocoPhillips.com 9/14/2025 21,923' Halliburton TNT Prod Packer Baker ZXP, No SSSV 10,226 Perforation Depth MD (ft): 907-265-6558 Senior Completions Engineer KRU 3T-605 5,138' 21,923'5,138' None 993' 4-1/2" 5,039'7-5/8" 11,921' 4-1/2" 5,138' 20" 10-3/4" 80' 7-5/8"10,188' 2,601' MD 6,890 5,210 118' 2,434' 4,849' 118' 2,640' 9,233' Length Size Proposed Pools: L-80 TVD Burst 10,017' 10,860 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528 / ADL393883 225-051 P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20917-00-00 ConocoPhillips Alaska, Inc. AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): TNT Packer: 9,875' MD / 4,983' TVD ZXP: 10,002' MD / 5,006' TVD Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:13 am, Aug 26, 2025 Digitally signed by Allen Eschete DN: OU=ConocoPhillips Alaska, O=Completions Engineering, CN= Allen Eschete, E=Allen.Eschete@ConocoPhillips.com Reason: I am the author of this document Location: Date: 2025.08.26 09:14:42-08'00' Foxit PDF Editor Version: 13.1.6 Allen Eschete 325-516 10-404 A.Dewhurst 28AUG25 CDW 08/27/2025 9/14/2025 DSR-8/26/25VTL 9/2/2025 X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.02 12:08:06 -08'00'09/02/25 RBDMS JSB 090425 SECTION 1 - AFFIDAVIT 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators 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). SECTION 2 – PLAT 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no known underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. See Conclusion number 3 of the Area Injection Order AIO 39 – Kuparuk River – Torok Oil Pool, which states “The injection interval does not contain freshwater and is not a potential underground source of drinking water.” SECTION 4 – PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283(a)(4) 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 and tested in accordance with 20 AAC 25.030. See Wellbore schematic for casing details. SonicScope 475 with SLB evaluation provided. Partial cement from 4650 ft. CDW 08/27/2025 SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: The 10-3/4” casing cement report on 06/09/2025 was pumped with 430 barrels of 11.0 ppg lead cement and 57 barrels 15.8 ppg tail cement. This was displaced with 223 bbl 9.8 ppg spud mud. The plug bumped and the floats held. The 7-5/8” casing cement report on 06/16/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 169 barrels of 14.0 ppg lead cement, followed with 59 barrels of 15.3 ppg tail cement. This was displaced with 455 barrels of 10.0 ppg RheGuard NAF. The plug bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 6,218’ MD (3,908’ TVD). The 4-1/2” liner cement report on 07/01/2025 shows the job was pumped as designed, indicating competent cementing operations. 93 bbls of cement were lost during the job but 10 bbls of cement were observed after circulating a bottoms up from the liner top packer indicating the entire lateral is cemented. The cement job was pumped with 373 barrels of 13.5 ppg cement. The cement was displaced with 9.5 ppg CI NaCl brine and the plugs bumped and held for 5 minutes. Floats held. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE- TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 06/10/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes On 06/16/2025 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes. On 06/04/2025 the 4-1/2” tubing was pressure tested to 4,200 psi for 30 minutes. On 07/01/2025 The 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 8,500 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7-5/8" Annulus pressure test 3,850 4-1/2" Tubing pressure Test 4,200 Electronic PRV 8,050 Highest pump trip 7,550 A tubing test of 4200 psi allows a tubing differential of 3818 psi for the 110% test criteria. With an IA hold of 3500 psi allows a maximum surface treating pressure of 7318 psi. CDW 08/26/2025 SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight, ppf Grade API Burst, psi API Collapse, psi 10-3/4” 45.5 L-80 5,209 2474 7-5/8” 29.7 L-80 6,885 4,789 7-5/8” 33.7 P-110S 10,860 7,870 4-1/2” 12.6 L-80 8,430 7,500 Table 2: Wellbore pressure ratings Stimulation Surface Rig-Up Kuparuk 10K Frac Tree SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The fracturing zone, the Torok Oil Pool, has an average thickness of approximately 260 ft TVD over the course of the lateral section of well 3T-605, from where it intersects the top formation at 10,205 MD (8,984’ TVDSS) to the TD of the well. The Torok Oil Pool is comprised of thinly interbedded sandstone, siltstone, and silty shale layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and very fine grained. The silty shales are composed of clay-rich, moderately to poorly sorted silt and clay. The estimated fracture pressure for the Moraine interval is approximately 12.5-13.5 ppg. The overlying confining interval of the Torok Formation consists of mudstones and siltstones with a thickness of approximately 800’ TVD along the 3T-605 trajectory. The top of the Torok confining interval in the well starts at 7,245’ MD (4,188’ TVDSS). The estimated fracture gradient of the overlying Torok formation is approximately 0.82 psi/ft. The underlying confining zone below the Base Moraine consists of lower Torok, HRZ, and Kalubik shales totaling approximately 500’ TVD. The estimated fracture gradient for this section ranges from 15-18 ppg, with the gradient increasing down section. The Base Moraine is estimated from seismic to be at 5,250 ft TVDSS along the length of the well. The estimated formation pressure within the Torok Oil Pool is 2,285psi at a depth of 5,200’ TVDSS. SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, 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 & Cement assessments for all wells that transect the confining zone: 3S-606: The 7-5/8” casing cement report on 2/11/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 111 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 29 barrels of 15.3 ppg without BMII. The plug was bumped, pressure increased to 1500 psi and held for 5 minutes. A cement bond log indicates competent cement with a cement top @ 3,950 MD (3,164’ TVD). 3S-617: The 7 & 5/8” casing cement report on 11/5/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 142 barrels of 15.3 ppg. The plug was not bumped. Pressure was being monitored and no pressure built up indicating that the floats held. A cement bond log indicates competent cement with a cement top @ 3,841’ MD (3,157’ TVD). 3S-624: The 7-5/8” casing cement report on 12/24/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 125 barrels of 15.3ppg primary cement with LCM and 22 barrels of 15.3ppg primary cement without LCM. The plug was bumped and the floats held. A cement bond log indicates competent cement with a cement top @ 3,435’ MD (2,778’ TVD). 3T-603: The 7-5/8” casing cement report on 10/29/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 203 barrels of 14.0 ppg lead cement, followed with 31 barrels of 15.3 ppg tail cement, displaced with 440 barrels of 9.6 ppg WBM. The plug bumped and floats held. A cement bond log run on 11/02/24 indicates competent cement with a cement top @ 5,768’ MD (3,792’ TVD). 3T-608: The 7-5/8” casing cement report on 10/28/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 203 barrels of 14.0 ppg lead cement with BMII, followed with 31 barrels of 15.3 ppg tail cement, displaced with 463 barrels of 9.5 ppg FWP. The plug bumped, bled off pressure and pressure and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 5,768 MD (3,843’ TVD). Source: https://ogc-docs.commerce.alaska.gov/WebLink/DocView.aspx?id=124588&page=1&dbid=0 Colville Delta 2: The well was plugged and abandoned on 3/16/1986. According to Plugging & Location Clearance Report, Set retainer at 6160’ 173 ft3 with 121 ft3 on top of the retainer. Set at 4,790’, squeeze 288 ft3. Drilled retainer 4790’. Set retainer at 4770’, squeeze 115 ft3. Drilled to 5500’ and set retainer at 5,000’, squeeze 161 ft3 with 10 sx on top of retainer. 23 ft3 plug from 140’ to 40’. TOC at 85’. 11 ft3 from 85’ to surface. Cement annulus with 310 ft3. Cut off casing head. Welded Plat on 95/8 STUB. Welded Plate on 7” STUB with well info. Source: https://ogc-docs.commerce.alaska.gov/weblink/0/doc/95379/Page1.aspx ODSN-17: According to the Pioneer Natural Resources Operation Summary Report on the AOGCC website, on 9/27/2010, while displacing the 7" liner cement job, the plugs landed early but did not hold much pressure, and pumping was continued pas the estimated stroke count and shoe track volume (the overdisplacement volume was estimated to be 28 bbls). This resulted in a wet shoe which was confirmed by pumping mud from surface. On 10/1/2010, the squeeze job (15 bbls of 15.8ppg cement, 13 bbls of SW, 102 bbls of 10.1ppg mud) was performed as planned. ODSN-17L1: Same as above ODST-47: According to the Pioneer Natural Resources job log on the AOGCC webiste, on 9/13/2012, the 7- 5/8"" casing cement job (55 bbls of Premium Class G tail cement at 15.8ppg) was pumped with partial returns (74 bbls) and the post job cement analysis showed ~70 psi of lift pressure. The cement bond log shows 52' of strong bond and 95' with partial bond of a total of 147' bonding. According to the Caelus Natural Resources job log on the AOGCC website, on 4/7/2019, the squeeze job (200 bbls in the formation and 9 bbls in the lateral tubular) was performed. The top of cement was at 12,223' CTM. ODSN-17/L1 wells are not within the AOR. Also, KRU 3S-602 and NDST-02PH are within the AOR and are included in the Moraine Frac AOR Spreadsheet reviewed by AOGCC. See attached emails. -A.Dewhurst 28AUG25 SECTION 11 – LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(11) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that a fault transects the Torok Oil Pool reservoir within one half mile radius of the 3T-605 wellbore trajectory. The fault intersects the 3T-605 well trajectories at 12,666’ MD, it is interpreted to have offset the toe section of the 3T-605 well upwards by <5ft. The fault trace is below seismic resolution, but an initial strike interpretation is shown in Plat 1. The fault is interpreted to not affect overburden integrity and therefore its presence will not interfere with containment. If there is any indication that a fracture has intersected the mapped fault (or any other faults unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3T-605 was completed in July 2025 as a horizontal injector in the Torok formation. The well is completed with a 4.5” tubing upper completion and a cemented 4.5” liner with a dart activated sliding sleeve lower completion. The first stage frac will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage, a dart will be dropped to shift open the 2nd stage sleeve and isolate the first stage. A frac will then be pumped through the 2nd stage. Darts will continue to be dropped to provide isolation from the previous stage and open each subsequent stage. Proposed Procedure: Halliburton Pumping Services: 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre- existing conditions. 2. Ensure the frac tree was tested to ~10,000 psi at rig. 3. Ensure all pre-frac well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,288’ MD / 2,164’ TVD. 4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 5. MIRU 25 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with either seawater or treated produced water. 6. MIRU HES Frac Equipment. 7. PT Surface lines to ~9,500 psi using a Pressure test fluid. 8. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 9. Bring up pumps and increase annulus pressure to 3,500 psi as the tubing pressures up. 10. Perform DFIT after opening the Alpha Sleeve according to the attached pump schedule. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. Resume pumping to pump Frac Stage 1. 11. Pump Frac Stages 2 through 24 by following attached pump schedule (skipping stages 19 and 20) at ~37 bpm with a maximum expected treating pressure of ~8,500 psi. Stages 19 and 20 will be skipped due to proximity of the fault at 12,666’. 12. The well is ready for Post Frac well prep/production tree installation, coiled tubing cleanout and flowback. Based on tubing test to 4200 psi, differential pressure max of 3818 psi, IA hold of 3500 psi, max surface frac pressure limited to 7318 psi. CDW 08/26/2025 pp ~8,500 psi. SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will be turned over to production for initial clean up production. Frac Design Attachments: 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-605 (PTD No. 225-051; Sundry No. 325-516) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 August 28, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 28AUG25 (a)(2) Plat Provided with application. A.Dewhurst 28AUG25 (a)(2)(A) Well location Provided with application. Well lies in Section 1 of T12N, R7E, UM. A.Dewhurst 28AUG25 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application, there are no wells used for drinking water purposes known to lie within ½ mile of the surface location of KRU 3T-605. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of KRU 3T-605. A.Dewhurst 28AUG25 (a)(2)(C) Identify all well types within ½ mile Provided with application. The operator has identified 27 wells within ½-mile radius. A.Dewhurst 28AUG25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth This well lies within the boundary of the Kuparuk River Unit Aquifer Exemption map that shows the area exempted under Title 40 CFR 147.102(b)(3) as currently depicted on EPA Region 10’s “Alaska Oil & Gas Aquifer Exemptions Interactive Map”, available through EPA Region 10’s web site. Recent communication from the EPA to the AOGCC has indicated that the exempted aquifer area was fixed to the 1986 boundary/extents as defined when the exemption was granted. The AOGCC is currently seeking guidance from the EPA to confirm that the 3T pad is within the original boundary that was granted the exemption. A.Dewhurst 28AUG25 (a)(4) Baseline water sampling plan Not applicable. There are no water wells within a ½-mile radius of the wellbore trajectory. A.Dewhurst 28AUG25 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. TOC included. CDW 08/27/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-605 (PTD No. 225-051; Sundry No. 325-516) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 August 28, 2025 (a)(6) Casing and cementing operation assessment 10-3/4” surface casing cemented to surface. 7-5/8” intermediate casing cemented from shoe of 10226 ft to TOC 6218 ft (SonicScope), 4.5” production liner cemented to liner top, No issues with cement for the upcoming stimulation. CDW 08/27/2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers are present. See Section (a)(3), above. Yes. TOC (good cement) is less than 250’ TVD above top of Coyote as required, but there is an additional ~500’ TVD of cement/slurry above the reported TOC. A.Dewhurst 28AUG25 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. Coyote and Moraine isolated by 7-5/8" intermediate casing cement. TOC at 6,218' MD. A.Dewhurst 28AUG25/ CDW 08/26/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3850 psi MITIA, 4200 psi MITT. CDW 08/26/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree max. frac. Pressure limited by testing to 7318 psi. Pump knock out 7550 and ePRV 8050 psi., tree test 10K psi, lines test 9500 psi. CDW 08/26/2025 (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: Torok Formation mudstone and siltstone having about 800’ of true vertical thickness (TVT). Fracture gradient is expected to range from about 0.82 psi/ft (15.8 ppg EMW). Fracturing Zone: Torok Oil Pool interbedded very fine-grained sandstone, siltstone and silty shale of around 260’ TVT. Fracture gradient expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Lower confining zones: Lower Torok, HRZ shale, and Kalubik shale that have an aggregate TVT about 500’. Fracture A.Dewhurst 28AUG25 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-605 (PTD No. 225-051; Sundry No. 325-516) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 August 28, 2025 gradient expected to range from about 0.78 to 0.94 psi/ft (15 to 18 ppg EMW). (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. There are 27 wells within ½ mile of 3T-605 and 9 wells (including pilot holes and plugbacks) that penetrate the confining intervals. AOGCC evaluated all 9 wells (including plugbacks and sidetracks) that may transect the confining zones within the KRU 3T-605 Area of Review. CPAI has not identified any wells for increased monitoring during frac. Nuna 1 as close enough to proposed frac at 3T-605 that it will be watched and may effect pumping of 3T-605 frac. Nuna 1 is proposed for perf and wash as Coyote is not isolated by cement. Max frac propped half-length of max 210 ft at toe and 180 ft at 10513 ft (shallowest frac port). AOGCC finds it is unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. Latest AOR included via emails and sharepoint includes 3S and 3T and no pad wells and cementing/isolation details. A.Dewhurst 28AUG25/ CDW 08/27/2025 (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 The operator has identified 1 fault that intersects KRU 3T-605. 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. Description of the faults are in the application. A.Dewhurst 28AUG25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 08/26/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-605 (PTD No. 225-051; Sundry No. 325-516) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 August 28, 2025 (a)(12)(A) Estimated volume Provided with application. 47094 bbl total dirty vol. 4.46M lb total proppant CDW 08/26/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 08/26/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Halliburton, Patina, (not Resmetrics) disclosures provided. CDW 08/26/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 08/26/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Based on stated testing, AOGCC will limit surface frac pressure to 7318 psi Max. not the stated 8500 psi allowable treating pressure. Max pressure is 7550-8050 psi ePRV. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3818 psi. CDW 08/26/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The maximum anticipated half-length of the induced fractures is 210’. A.Dewhurst 28AUG25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but CPAI 3T has options. CDW 08/26/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, plan to test to 3850 psi, popoff set as 3600 psi CDW 08/26/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with a packer set at 10126 ft with shallowest sleeve planned for 10513 ft. TOC in 7-5/8” casing at 6218 ft. SonicScope CBL conservatively shows good cement at area of interest so no cement concerns. CDW 08/26/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4200 psi. Max pressure differential allowed is 3818 psi. With 3500 psi IA hold, max allowed surface frac pressure is calculated as 7318 psi to satisfy 110% CDW 08/26/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3T-605 (PTD No. 225-051; Sundry No. 325-516) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 August 28, 2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9500 psi line pressure test, pump knock out 7550-8050 psi ePRV. IA PRV set as 3600 psi. CDW 08/26/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 08/26/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 08/26/2025 (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 08/26/2025 (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). A.Dewhurst 28AUG25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 28AUG25 (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. 1 Dewhurst, Andrew D (OGC) From:Eschete, Allen <Allen.Eschete@conocophillips.com> Sent:Thursday, 28 August, 2025 15:17 To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S; Wallace, Chris D (OGC); Loepp, Victoria T (OGC) Subject:RE: [EXTERNAL]KRU 3T-605 Frac Sundry (325-516): Question Andy, Thanks for talking through this on the phone a few minutes ago. NDST-02PH and KRU 3S-602 are within the ½ mile radius and included in the AOR spreadsheet. ODSN-17/L1 is in the Nuiqsut. Thanks, Allen Eschete Office: (907) 265-6558 Cell: (907) 519-2976 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, August 28, 2025 2:45 PM To: Eschete, Allen <Allen.Eschete@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]KRU 3T-605 Frac Sundry (325-516): Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Allen, I’m completing my review of the KRU 3T-605 frac sundry and have a question about the Area of Review. x I’m showing that the NDST-02PH and possibly the KRU 3T-602 wells are within the ½-mile AOR x I’m also showing that the ODSN-17/L1 are down in the Nuiqsut and not within the AOR Would you please conƱrm the above and send an updated AOR table (PDF) if so? Thanks, Andy Andrew Dewhurst You don't often get email from allen.eschete@conocophillips.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3T-605 50-103-20917-00-00 225-051 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 1-Jul-25 1Transmittal Receipt________________________________ X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.aurana@slb.comSLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point.# Schlumberger-Private225-051T40762Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.08.11 08:07:26 -08'00' WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS E-Delivery3S-721 50-103-20911-00-00 225-025 KUPARUK RIVER MWD/LWD/DD TOP OF CEMENT FINAL FIELD 7-May-25 13T-613 50-103-20914-00-00 225-036 KUPARUK RIVER MWD/LWD/DD TOP OF CEMENT FINAL FIELD 23-May-25 13T-605 50-103-20917-00-00 225-051 KUPARUK RIVER MWD/LWD/DD TOP OF CEMENT FINAL FIELD 21-Jun-25 13S-719 50-103-20919-00-00 225-058 KUPARUK RIVER MWD/LWD/DD TOP OF CEMENT FINAL FIELD 15-Jul-25 1Transmittal Receipt________________________________ X____________________________________________Print Name Signature DatePlease return via courier or sign/scan and email a copy to Schlumberger.aurana@slb.comSLB Auditor - A Transmittal Receipt signature confirms that a package (box, envelope, etc.) has been received and the contents of the package have been verified to match the media noted above. The specific content of the CDs and/or hardcopy prints may or may not have been verified for correctness or quality level at this point.# Schlumberger-PrivateT40687T40688T40689T406903T-60550-103-20917-00-00225-051KUPARUK RIVERMWD/LWD/DDTOP OF CEMENTFINAL FIELD21-Jun-251Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.07.28 08:43:18 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3T-605 JBR 08/01/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 5" and 7 5/8" test joints used for testing. The annular failed on the low with the 5" test joint. Actuated the annular and adjusted the hydraulic pressure the the bag and it passed the retest. 16 charge bottles with 11 at 1000 psi and 5 at 1050 psi. Test Results TEST DATA Rig Rep:Z. Coleman/ S. MichaelOperator:ConocoPhillips Alaska, Inc.Operator Rep:C. Hull/M. Arthur/A. Lunda Rig Owner/Rig No.:Doyon 142 PTD#:2250510 DATE:6/10/2025 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopGDC250610141815 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1786 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 FP #1 Rams 1 7 5/8" Solid P #2 Rams 1 Blind/Shear P #3 Rams 1 3.5" x 6" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 P HCR Valves 2 3 1/8" 5000 P Kill Line Valves 3 3 1/8" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1825 200 PSI Attained P8 Full Pressure Attained P48 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@2000 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P18 #1 Rams P7 #2 Rams P7 #3 Rams P7 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2        Test charts attached Test Bope 7-5/8” & 5” 250/3500 On The Annular Both Test Joints 250/5000 On Everything Else 1. 7-5/8” TJ, Annular 250/3500 2.7-5/8” TJ, UPR’s CMV’s #’s 1, 12, 13, 14, Rig floor kill line valve, Upper IBOP, 5” Dart valve #1 250/5000 3. CMV’s #’s 9, 11, Mezz Kill line valve, Lower IBOP, 5” Floor valve #1 250/5000 4. CMV’s #’s 8, 10, HCR Kill, 5” Floor valve #2 250/5000 5. CMV’s #’s 6, 7, Manual Kill, 250/5000 6. Super Choke 250/2000 7.Manual Choke 250/2000 8.CMV’s #’s 2, 5, 250/5000 9. HCR Choke 250/5000 10. Manual Choke 250/5000 Koomey Drawdown Remove 7-5/8”Test Joint 11. CMV’s #’s 3, 4, Blind rams 250/5000 Install 5” Test joint 12. 5” TJ Annular 250/3500 13.5” TJ 3-1/2” X 6” Lower VBR’s 250/5000 IBOP=2 Manual choke=1 LPR’s=1 Dart=1 Mud Cross=6 Total Components=32 TIW=2 Annular=2 CMV’s =14 UPR’s=1 Hyd. choke=1 Blind/Shears=1 BOPE Test - Doyon 142 KRU 3T-605 PTD 2250510 AOGCC Insp # bopgdc250610141815 6/10/2025 BOPE Test - Doyon 142 KRU 3T-605 PTD 2250510 AOGCC Insp # bopgdc250610141815 6/10/2025 BOPE Test - Doyon 142 KRU 3T-605 PTD 2250510 AOGCC Insp # bopgdc250610141815 6/10/2025 DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET WELL: 3T-605 6/10/2025 ACCUMULATOR PSI 3000 MANIFOLD PSI 1480 FUNCTION RAMS/ANNULAR/ HCR'S, DON'T FUNCTION BLINDS! FUNCTION ONE RAM TWICE LET PRSSURE STABILIZE AND RECORD BACK UP NITROGEN BOTTLE'S ACCUMULATOR PSI 1825 NITROGEN BOTTLE'S PSI BOTTLE # 1 2000 BOTTLE # 2 2000 BOTTLE # 3 2000 BOTTLE # 4 2000 BOTTLE # 5 2100 BOTTLE # 6 1900 AVG FOR 6 BOTTLE'S =2000 TURN ON ELEC. PUMP, SEC FOR 200 PSI =8 TURN ON AIR PUMP'S TIME FOR FULL CHARGE =48 Annular 18 UPR 7 Blind/ Shear 7 LPR 7 KILL HCR 2 Choke HCR 2 BOPE Test - Doyon 142 KRU 3T-605 PTD 2250510 AOGCC Insp # bopgdc250610141815 6/10/2025 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Torok Oil Pool, KRU 3T-605 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-051 Surface Location: 1976' FSL, 645' FWL, NWSW S1 T12N R7E, UM Bottomhole Location: 4624' FSL, 2280' FWL, NENW S23 T13N R7E, UM Dear Mr. Brillon: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 4th day of June 2025. . Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.04 17:07:26 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 21,907 TVD: 5142 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 6/13/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 650' to ADL355036 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open Surface: x-467856 y- 6003702 Zone- 4 12 to Same Pool: 891' to 3T-603 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20" 94 H-40 Welded 81 39 39 120 120 13.5" 10.75" 45.5 L80 Hyd563 2591 39 39 2630 2432 9.875" 7.625" 29.7 L80 Hyd563 9283 39 39 9322 4876 9.875" 7.625" 33.7 P110-S Hyd563 800 9322 4876 10122 5031 6.5" 4.5" 12.6 P110-S Hyd563 11935 9972 5008 21907 5142 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Matt Smith Chris Brillon Contact Email:matt.smith2@conocophillips.com Wells Engineering Manager Contact Phone:907-263-4324 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10 yds P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Torok Oil Pool 1976' FSL, 645' FWL, NWSW S1 T12N R7E ADL025528 / ADL393883 (including stage data) 3737' FSL, 5174' FWL, SENE S35 T13N R7E LONS 01-013 4624' FSL, 2280' FWL, NENW S23 T13N R7E 2560 / 5760 GL / BF Elevation above MSL (ft): 2300 1786 18. Casing Program: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc. 59-52-180 KRU 3T-605 940sks 11ppg, 280sks 15.8ppg 694sks 14ppg, 138sks 15.3ppg Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks 1366sks 14.8ppg Casing Length Size Cement Volume MD Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Surface Conductor/Structural Liner Production Intermediate Perforation Depth MD (ft): Perforation Depth TVD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Authorized Title: Authorized Signature: Commission Use Only See cover letter for other requirements. Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 10:51 am, Apr 24, 2025 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available Cement logs must be reviewed with the AOGCC as soon as available and prior to running the production liner. Diverter variance approved per 20 AAC 25.035(h)(2) 225-051 50-103-20917-00-00 X SFD DSR-4/25/25SFD 5/29/2025VTL 6/4/2025 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.04 17:07:42 -08'00' 06/04/25 06/04/25 RBDMS JSB 060525 <ZhϯdͲϲϬϱ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. .58'67 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 April 24, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill 3T-605 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Injector well from the 3T drilling pad. The intended spud date for this well is 6/13/2025. It is intended that Doyon 142 be used to drill the well. 3T-605 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. As noted in section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will be sized for the intermediate casing string. The 9 7/8” intermediate hole will be drilled and set in the Moraine reservoir. A 7 5/8” casing string will be set and cemented from TD to secure the shoe and cover 250’TVD above any hydrocarbon-bearing zones (Coyote). The production interval will be comprised of a 6 1/2” horizontal hole that will be landed and geo-steered in the Moraine formation. The well will be completed as a fracture stimulated Injector with 4 1/2” liner and frac sleeves, cemented from TD to the liner top. The upper completion will include a production packer with GLM’s and a downhole guage tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI BOPE between well maintenance program, reflected by low failure rates in BOP tests since its entry into the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. It is also requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3T-605. At 3T, there has not been any significant indication of shallow gas hydreates to date through the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Matt Smith at 907-263-4324 (matt.smith2@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: 3T-605 Well File / Jenna Taylor ATO 1560 Will Earhart ATO 1552 Matt Smith Chris Brillon ATO 1548 Drilling Engineer Roland Kirschner ATO 636 cerely, t S ith onshore Moraine Injector Requested diverter variance is recommended provided the surface hole interval does not significantly exceed planned depth of 2432' TVD. SFD 3T-605 PTD Page 1 of 10 3T-605 Application for Permit to Drill Document Table of Contents 1.Well Name .............................................................................................................................................................. 2 2.Location Summary ................................................................................................................................................... 2 3.Proposed Drilling Program..................................................................................................................................... 4 4.Blowout Prevention Equipment ............................................................................................................................. 5 5.Diverter System ..................................................................................................................................................... 5 6.MASP Calculations ................................................................................................................................................ 5 7.Procedure for Conducting Formation Integrity Tests ............................................................................................. 6 8.Casing and Cementing Program ........................................................................................................................... 6 9.Drilling Fluid Program ............................................................................................................................................ 7 10.Abnormally Pressured Formation Information ................................................................................................... 8 11.Seismic Analysis ................................................................................................................................................ 8 12.Seabed Condition Analysis ................................................................................................................................ 8 13.Evidence of Bonding .......................................................................................................................................... 8 14.Discussion of Mud and Cuttings Disposal and Annular Disposal ...................................................................... 8 15.Drilling Hazards Summary ................................................................................................................................. 8 16.Proposed Completion Schematic ..................................................................................................................... 10 3T-605 PTD Page 2 of 10 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as 3T-605 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 1,976 FSL, 645 FWL, NWSW S1 T12N R7E, UM NAD 1927 Northings: 6003702 Eastings:467856 RKB Elevation 51’AMSL Pad Elevation 12’AMSL Top of Productive Horizon (Heel) 3737‘ FSL, 5174‘ FWL, SENE S35 T13N R7E, UM NAD 1927 Northings: 6010730 Eastings: 470827 Measured Depth, RKB: 10,122 Total Vertical Depth, RKB:5,031 Total Vertical Depth, SS:4,980 Total Depth (Toe) 4624‘ FSL, 2280‘ FWL, NENW S23 T13N R7E, UM NAD 1927 Northings: 6010960 Eastings: 471505 Measured Depth, RKB:21,907 Total Vertical Depth, RKB:5,142 Total Vertical Depth, SS:5,091 Pad Layout 3T-605 PTD Page 3 of 10 Well Plat 3T-605 PTD Page 4 of 10 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 142 onto 3T-605 2. Rig up and test diverter and riser, dewater cellar as needed. 3. Drill 13 1/2” hole to the surface casing point as per the directional plan. 4. Run and cement 10 3/4” surface casing to surface. 5. Install BOPE and MPD equipment. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice). 7. Pick up and run in hole with 9 7/8” drilling BHA to drill the intermediate hole section. 8. Chart casing pressure test to 3,000 psi for 30 minutes. 9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW. 10. Drill 9 7/8” hole to section TD, setting pipe 5-10’ TVD in the Moraine Reservoir using near-bit GR. (LWD Program: GR/RES, near-bit GR). 11. Run 7 5/8” casing and cement to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing if possible on plug bump to 4000 psi. 12. Freeze protect down the Outer Annulus (10 3/4” surface casing x 7 5/8” intermediate casing annulus). 13. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice). 14. Pick up and run in hole with 6 1/2” drilling BHA. Log top of cement with sonic tool in real-time mode. 15. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump. 16. Drill out shoe track and 20 feet of new formation. Perform LOT to a maximum of 16 ppg. Minimum required leak-off value is 11.0 ppg EMW. 17. Drill 6 1/2” hole to section TD (LWD Program: GR/RES/Den/Neu/Sonic). 18. Pull out of hole with drilling BHA. Review intermediate cement job details and sonic log TOC. 19. Run 4 1/2” liner with toe valve, frac sleeves and liner hanger and packer to 21,907 MD. 20. Cement 4 1/2 liner from TD to liner top. Pressure test 4 1/2” liner and liner hanger packer for 30 minutes. 21. Run 4 1/2” upper completion with glass plug, production packer and gas lift mandrels. Space out and land tubing hanger. 22. Pressure test hanger seals to 5,000 psi. 23. Pressure test against the glass plug to set production packer, test tubing to 4,200 psi, chart test. 24. Bleed tubing pressure to 2,200 psi and test IA to 3,850 psi, chart test. 25. Install HP-BPV. 26. Nipple down BOP. 27. Install tubing head adapter assembly. N/U frac tree and test to 10,000 psi/5 minutes. 28. Freeze protect down tubing and annulus. 29. Secure well. Rig down and move out. Please note – This well will be frac’d 3T-605 PTD Page 5 of 10 4. Blowout Prevention Equipment Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP schematics on file for Doyon 142. Doyon 142 will use a BOPE stack equipped with an annular preventer, fixed 7 5/8” solid body rams, blind/shear rams and variable rams while drilling and running casing in the intermediate section of 3T-605. 3T-605 has a MASP of 1,785 psi in the intermediate hole section using the methodology in section 6 MASP calculations. With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2. Per 20AAC 25.035.e.a.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing begin used, except that pipe rams need not be sixed to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Intermediate Drilling/Casing Production Proposed Configuration: Proposed Configuration: Annular Preventer (iii) Annular Preventer 7 5/8” fixed rams during drilling Intermediate VBRs in Upper Cavity Blind/Shear Rams (ii) Blind/Shear Rams VBRs (i) VBRs in Lower Cavity 5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) A diverter waiver is requested, as there have been no indications of hydrates on 3T pad, with 3T-608’s well surface shoe within 500’ of the 3T-605. 6. MASP Calculations Requirements of 20 AAC 25.005(c)(4) (A) maximum downhole pressure and maximum potential surface pressure; Requested diverter variance is recommended provided the surface hole interval does not significantly exceed planned depth of 2432' TVD. SFD 3T-605 PTD Page 6 of 10 Method 1: Method 2: Method 1 Method 2 = [( ×0.052 ) ] × = ( ) × Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient – 0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP – Formation Pore Pressure at the next casing point Gas Gradient – 0.1 psi/ft Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13 1/2 20 119 119 10.9 8.6 53 2,630 2,432 8.6 1,087 56 56 844 INTRM 9 7/8 10 3/4 2,630 2,432 13.5 8.6 1,087 10,122 5,031 8.6 2,250 1,464 1,464 1,747 PROD 6 1/2 7 5/8 10,122 5,031 13.0 8.6 2,250 21,907 5,142 8.6 2,300 1,785 3,029 1,785 (B) data on potential gas zones; The well bore is not expected to penetrate any shallow gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary 7. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out the casing shoe and perform LOT/FIT as per the procedure that ConocoPhillips Alaska has on file with the Commission. 8. Casing and Cementing Program Requirements of 20 AAC 25.005 (c)(6) Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 10 3/4 13 1/2 45.50 L80 Hyd563 Cement to Surface 7 5/8 9 7/8 29.70 33.70 L80 P110-S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper most producing zone (Coyote) 4 1/2 6 1/2 12.60 P110-S Hyd563 Cemented liner with frac sleeves Cementing Calculations 3T-605 PTD Page 7 of 10 10 3/4” Surface Casing run to 2,630 ’ MD / 2,432 ’ TVD Cement 2,630 MD to 2,130 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,130' to surface with 10.7 ppg Arctic Lite Crete. Assume 250% excess annular volume in permafrost and 50% excess below the permafrost (1,663 ’ MD), zero excess in 20” conductor. !" !#$%&' (() *+,-./0! !1 !(2 !#$3' (0/3) *+,-.(/(2 !1 7 5/8” Intermediate Casing run to 10122’ MD / 5,031 ’ TVD Top of slurry is designed to be at 6,064 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing zone, Coyote. If a shallower hydrocarbon zone of producible volumes, is encountered while drilling, a 2-stage cement job will be performed to isolate this zone. Assume 40% excess annular volume. ( '"' !#$"'' (&) *+,-.(/0&0 !1&'4%"135 ("( !#$(&' (0/!) *+,-.(/&00 !1&'4%"135 4 1/2” Production Liner run from 10,122’ MD / 5,031’ TVD to 21,907’ MD / 5,142’ TVD Cement the liner from TD to the liner top using a 14.8 ppg Class G + Add's cement. Assume 25% excess annular volume in the open hole, and 0% excess in the 7 5/8” intermediate casing. ( "3! !#$( !&' (&/3) *+,-.(/!!2 !1(042(15 9. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate Production Hole Size in. 13 1/2 9 7/8 6 1/2 Casing Size in. 10 3/4 7 5/8 4 1/2 Density PPG 8.6 – 9.8 9.0 – 9.6 9.0 – 10 PV cP 20-50 <22 <20 YP lb./100 ft2 50 - 80 20 - 30 15 - 30 Funnel Viscosity s/qt. 250 – 300 40-60 35-50 Initial Gels lb./100 ft2 30 - 50 8 - 15 5- 10 10 Minute Gels lb./100 ft2 50 - 70 <20 7 - 15 API Fluid Loss cc/30 min. N.C. – 8.0 < 10.0 < 6.0 HPHT Fluid Loss cc/30 min. N/A < 10.0 < 10.0 pH 8.5-9.5 9-10 9-10 Surface Hole: A water based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain proper specifications The mud weight will be maintained at H9.8 ppg by use of solids control system and dilutions where necessary. Intermediate: Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight at or below 9.6 ppg for formation stability and be prepared to add loss circulation material if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important. The mud will be weighted up to 9.5 ppg before pulling out of the hole. Production Hole: 3T-605 PTD Page 8 of 10 The horizontal production interval will be drilled with a Non-Aqueous Fluid (NAF) mud system weighted to 9.0 – 10 ppg. MPD will be utilized to add back pressure during connections to minimize pressure cycling. Diagram of Doyon 142 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 10. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. 12. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. 13. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. 15. Drilling Hazards Summary 13 1/2" Hole / 10 3/4” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Follow real time surveys very closely, gyro survey as needed to ensure survey accuracy. Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out Washouts/Hole Sloughing Low Cool mud temperatures, minimize circulating times when possible Running sands and gravels Low Maintain planned mud properties, increase mud weight, use weighted sweeps Lost Circulation Moderate Monitor ECDs for signs of packoff before losses occur. Keep hole clean and utilize LCM sweeps to regain circulation. 3T-605 PTD Page 9 of 10 9 7/8” Hole /7 5/8” Casing Interval Event Risk Level Mitigation Strategy Sloughing shale / Tight hole / Stuck Pipe Low Good hole cleaning, pre-treatment with LCM, stabilized BHA, maintain planned mud weights and adjust as needed, real time equivalent circulating density (ECD) monitoring Lost circulation Moderate Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure (Coyote / K3) Low Well control drills, check for flow during connections, increase mud weight if necessary. 6 1/2” Hole / 4 1/2” Liner - Horizontal Production Interval Event Risk Level Mitigation Strategy Lost circulation Moderate Reduce pump rates, real time ECD monitoring, maintain mud rheology, add lost circulation material Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Moderate Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Running Liner to Bottom Moderate Properly clean hole on the trip out with BHA, perform clean out run if necessary, utilize super sliders for weight transfer if needed, monitor T&D real time Well Proximity Risks: 3T is a multi-well pad, with only a few existing wells. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Unlikely to encounter any abnormal pressure, however, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the primary intermediate cement job will be replanned to cover the zone as per the agency regulations. Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. 3T-605 PTD Page 10 of 10 16. Proposed Completion Schematic !!"" #$ %%&'$"( )*"*+,+$-. ($!/ 0 ( )$$ 1 #2 %34! 4,"($$%(*5"6(7"(8(5$ '!((99:; %341<=<5=>( 1 ==2 + <!#4,.?0$*$!< 4,@"-* ' 9 9 11# *A11 *$ ($ 1 =2"+2!##4,.?0$*$!<4,@"-*'991#1 *$ 1 ==" # + 2!<4,.?0$*$!#4,@"-* ' 9 9 1#21 *$ ($ Agree: Moraine interval is cement isolated in these four wells. SFD 39 500 500 800 800 1100 1100 1500 1500 2000 2000 3000 3000 5000 5000 8000 8000 12000 12000 17000 17000 21908 3T-605 wp12.1 Plan Summary 0 4 Dogleg Severity0 3500 7000 10500 14000 17500 21000 Measured Depth 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 30.0 30.0 60.0 60.0 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in] 39100200300 400 501 602 704 806 9081010 3T-603 39100200300399498596 3T-608 39100200300401502604 3T-602 wp05 v539100200300401501602702803904 1005 1106 1208 1310 3T-604 wp05 v5 391002003004004995986977968959931092119012881387 1485 158316821781 3T-606 wp08 39100200300 400499598697795893992 3T-607 wp05 0 3000 True Vertical Depth0 2750 5500 8250 11000 13750 16500 Vertical Section at 0.10° 10-3/4" Surface Casing 7-5/8" Intermediate Casing 4-1/2" Production Liner 18 35 Centre to Centre Separation0 425 850 1275 1700 2125 2550 2975 Measured Depth Equivalent Magnetic Distance DDI 7.229 SURVEY PROGRAM Date: 2019-07-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.00 500.00 3T-605 wp12.1 (3T-605) r.5 SDI_URSA1 500.00 2620.00 3T-605 wp12.1 (3T-605) MWD+IFR2+SAG+MS 2620.00 10120.00 3T-605 wp12.1 (3T-605) MWD+IFR2+SAG+MS 10120.00 21907.30 3T-605 wp12.1 (3T-605) MWD+IFR2+SAG+MS Ground / 12.00 CASING DETAILS TVD MD Name 2431.68 2629.55 10-3/4" Surface Casing 5031.15 10122.96 7-5/8" Intermediate Casing 5142.00 21907.30 4-1/2" Production Liner Mag Model & Date: BGGM2024 20-Jun-25 Magnetic North is 13.71° East of True North (Magnetic Declinatio Mag Dip & Field Strength: 80.60° 57172.50nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00 3 500.00 2.00 26.45 499.96 3.12 1.55 1.00 26.45 3.13 Start Build 2.00 4 1607.45 24.15 26.45 1572.00 226.03 112.45 2.00 0.00 226.23 Start 109.59 hold at 1607.45 MD 5 1717.04 24.15 26.45 1672.00 266.18 132.42 0.00 0.00 266.41 Start Build 2.00 6 2666.76 43.14 26.45 2459.00 735.14 365.73 2.00 0.00 735.80 Start 20.00 hold at 2666.76 MD 7 2686.76 43.14 26.45 2473.59 747.39 371.82 0.00 0.00 748.05 Start DLS 2.00 TFO -0.02 8 4088.11 71.17 26.44 3226.04 1791.07 890.92 2.00 -0.02 1792.66 Start 4256.15 hold at 4088.11 MD 9 8344.26 71.17 26.44 4599.74 5398.06 2684.62 0.00 0.00 5402.85 Start DLS 2.00 TFO -77.85 1010460.35 84.00 345.00 5073.57 7403.13 2866.52 2.00 -77.85 7408.24 Start Build 1.00 11 10660.35 86.00 345.00 5091.00 7595.57 2814.96 1.00 0.00 7600.59 3T Cantwell T01 041125 Start DLS 1.00 TFO 30.10 1210810.71 87.30 345.75 5099.79 7740.82 2777.07 1.00 30.10 7745.77 Start 546.84 hold at 10810.71 MD 1311357.55 87.30 345.75 5125.53 8270.25 2642.66 0.00 0.00 8274.96 Start DLS 1.00 TFO -7.81 1411368.53 87.41 345.74 5126.04 8280.89 2639.96 1.00 -7.81 8285.59 3T Cantwell T02 041125 Start DLS 1.00 TFO -10.21 1511383.07 87.55 345.71 5126.68 8294.96 2636.37 1.00 -10.21 8299.66 Start 1045.30 hold at 11383.07 MD 1612428.38 87.55 345.71 5171.31 9307.02 2378.67 0.00 0.00 9311.26 Start DLS 1.00 TFO -125.62 1712437.50 87.50 345.64 5171.70 9315.85 2376.42 1.00 -125.62 9320.08 3T Cantwell T03 041125 Start DLS 1.00 TFO -125.79 1812442.99 87.47 345.60 5171.94 9321.16 2375.05 1.00 -125.79 9325.39 Start 216.04 hold at 12442.99 MD 1912659.03 87.47 345.60 5181.49 9530.21 2321.36 0.00 0.00 9534.34 Start DLS 1.00 TFO 0.10 2012912.24 90.00 345.60 5187.08 9775.38 2258.40 1.00 0.10 9779.41 3T Cantwell T04 041125 Start DLS 1.00 TFO 3.07 21 13031.10 91.19 345.66 5185.85 9890.51 2228.91 1.00 3.07 9894.48 Start 588.42 hold at 13031.10 MD 2213619.52 91.19 345.66 5173.66 10460.49 2083.24 0.00 0.0010464.19 Start DLS 1.00 TFO 179.26 2313668.20 90.70 345.67 5172.86 10507.65 2071.19 1.00 179.2610511.33 3T Cantwell T05 041125 Start DLS 1.00 TFO 178.06 2413728.75 90.09 345.69 5172.44 10566.31 2056.21 1.00 178.0610569.97 Start 1082.55 hold at 13728.75 MD 2514811.30 90.09 345.69 5170.65 11615.28 1788.65 0.00 0.0011618.46 Start DLS 1.00 TFO -173.67 2614820.85 90.00 345.68 5170.64 11624.53 1786.29 1.00 -173.6711627.70 3T Cantwell T06 041125 Start DLS 1.00 TFO -179.57 2714926.03 88.95 345.67 5171.61 11726.43 1760.27 1.00 -179.5711729.56 Start 472.30 hold at 14926.03 MD 2815398.32 88.95 345.67 5180.27 12183.96 1643.41 0.00 0.0012186.88 Start DLS 1.00 TFO 0.43 2915503.50 90.00 345.68 5181.24 12285.86 1617.39 1.00 0.4312288.73 3T Cantwell T13 041125 Start DLS 1.00 TFO 0.50 3015788.09 92.85 345.70 5174.17 12561.51 1547.09 1.00 0.5012564.25 Start 495.55 hold at 15788.09 MD 31 16283.64 92.85 345.70 5149.57 13041.12 1424.88 0.00 0.0013043.65 Start DLS 1.00 TFO -173.41 3216348.64 92.20 345.63 5146.71 13104.04 1408.80 1.00 -173.4113106.54 3T Cantwell T14 041125 Start DLS 1.00 TFO -170.34 3316392.48 91.77 345.56 5145.19 13146.48 1397.90 1.00 -170.3413148.95 Start 629.36 hold at 16392.48 MD 3417021.84 91.77 345.56 5125.78 13755.66 1241.00 0.00 0.0013757.85 Start DLS 1.00 TFO 169.41 3517099.96 91.00 345.70 5123.89 13831.31 1221.62 1.00 169.4113833.47 3T Cantwell T07 041125 Start DLS 1.00 TFO 172.53 3617146.51 90.54 345.76 5123.27 13876.41 1210.14 1.00 172.5313878.55 Start 540.68 hold at 17146.51 MD 3717687.19 90.54 345.76 5118.18 14400.46 1077.15 0.00 0.0014402.36 Start DLS 1.00 TFO -177.82 3817741.07 90.00 345.74 5117.93 14452.69 1063.89 1.00 -177.8214454.56 3T Cantwell T08 041125 Start DLS 1.00 TFO -179.05 3917883.94 88.57 345.72 5119.71 14591.13 1028.67 1.00 -179.0514592.95 Start 770.06 hold at 17883.94 MD 4018654.00 88.57 345.72 5138.91 15337.15 838.74 0.00 0.0015338.63 Start DLS 1.00 TFO -2.26 41 18796.96 90.00 345.66 5140.69 15475.66 803.40 1.00 -2.2615477.07 3T Cantwell T09 041125 Start DLS 1.00 TFO -3.38 4218810.44 90.13 345.65 5140.67 15488.72 800.07 1.00 -3.3815490.12 Start 1319.75 hold at 18810.44 MD FORMATION TOP DETAILS TVDPath Formation 851.57 K-15 1353.85 Ugnu C 1591.99 Ugnu B 1622.31 Base Perm 1724.40 Ugnu A 1970.32 West Sak 2379.73 West Sak Base 2530.12 C-80 2597.01 C-50 3787.01 C-35 4114.24 Coyote 4198.99 Coyote Base 5026.65 Moraine 5118.68 Moraine Blue By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by Plan 12+39 @ 51.00usft (D142) -25000250050007500True Vertical Depth0 2500 5000 7500 10000 12500 15000 17500Vertical Section at 0.10°10-3/4" Surface Casing7-5/8" Intermediate Casing4 1/2 x 6-3/410002000300040005000600070008000900010000110001200013 000 140001500016000 17 00 0 1800019000 200002100021908 0°30°60°71°87°88°87°90°91 ° 90°89°9 3 ° 9 2 ° 91°89°90°88°90° 9 1 ° 3T-605 wp12.1 K-15Ugnu CUgnu BBase PermUgnu AWest SakWest Sak BaseC-80C-50C-35CoyoteCoyote BaseMoraineMoraine Blue3T-605 wp12.110:11, April 18 2025Section View 035007000105001400017500South(-)/North(+)-10500 -7000 -3500 0 3500 7000 10500 14000West(-)/East(+)10-3/4" Surface Casing7-5/8" Intermediate Casing4 1/2 x 6-3/450010001500200025003000350040004500500051423T-605 wp12.13T-605 wp12.1While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.10:14, April 18 20253ODQ9LHZ